Dunlap, Ann C. From: Sent: To: Subject: Attachments: Richard Hargis Tuesday, June 14, 2005 2:10 PM Russial, Thomas Fwd: FW: SCS NDA SDH chg 512051 SCS NDA SOH chg 5120Sl.doc Tom, NDA between ORNL and SCS. bS >>>"Warren, Daniel H." 6/8/2005 12:44 PM>>> Bob and Rich, Attached is the final revision of the NDA for your review and approval. With your concurrence, we will pull the trigger on getting it signed by the appropriate folks. Thanks, Dan Daniel H. Warren Southern Company 205-257-6947 This message is intended only for the person's) to whom it is addressed. It is PRIVILEGED and CONFIDENTIAL. Any dissemination, distribution, copying, or use of this message or any of its contents; other than by the person's) to whom it is addressed, is prohibited and may constitute a BREACH OF CIVIL OR CRIMINAL LAW. If this message has been delivered to you in error, please delete the message from your system and contact the sender by reply email or collect telephone call (205/257 -6947 in the U.S.) as soon as possible. Thank you. SoCo FOIA Response 000346 CONFIDRNTIALITY AND NONJ>ISCLOSURE AGREEMENT This CONFIDENTIALITY AND "Agreement") is entered into this _ _ day of Company Services, Jnc. ("SCS") and NONDISCLOSURE AGREEMENT (the , 2005 by and between Southern ("Recipient"). (b) (4) WITNESSETH: WHEREAS, SCS has been selected for negotiation of an award of a Cooperative Agreement (prime contract) from the United States Department of Energy ("DOE") to serve as prime contractor to perform n demonstration pmject to engineer, procme, constl'llct, operate, maintain, and evaluate a gnsilication island plant at a facility owned jointly by SCS' affiliate, Southern Power and Orlando Utilities Corporation, at their Plant Stanton facility, located in Orlando, Florida, pursuant to application number DE-PS26-04NT4206 ("the Project"); and WHEREAS, DOE has contracted with the Recipient to prepare an Envimnmental Impact Statement ("EIS") for the Project ns pa1·t of the DOE's analysis required by the National Environmental Policy Act ("NEPA") and to perform related work (collectively, "the Work") WHEREAS, the Recipient may require access to certain of SCS's confidential, important or proprietary infonnation (detined herein as "Restricted Information") in connection with the Work; and WHEREAS, SCS desires to grant the Recipient access to Restricted Information conceming SCS and its activities, solely in connection with the Work; and WJ !EREAS, the Recipient and SCS wish to set forth the rights and obligations or the parties concerning the use, dissemination, and protection of all Restricted lnfonnalion, provided by SCS, team members, or subcontractors on the Project, to the Recipient in accomplishing the purpose of this Agreement. NOW, THEREFORE, in consideration of the premises set forth above and the mutual covenants hereinafter set forth and other good and valuable consideration the sufficiency of which is hereby acknowledged, the Recipient and SCS, intending to be legally bound hereby agree as follows: 1. Definitions For purposes of this Agreement, the term "Restricted Information" means Limited Rights Data, Restricted Computer Software, and Protected Data that is the property of SCS, its team members, or subcontractors, and any information so designated by SCS. SoCo FOIA Response 000347 For purposes of this Agreement, the terms "Limited Rights Dnta," "Restricted Computer Software," and "Protected Data" have the meanings ascribed to them under the Rights in Data-Programs Covered Under Special Data Statutes Clause attached hereto solely for the purpose of detining Restricted Data as used herein. For purposes of this Agreement, the term "Recipient" includes the Recipient and all affiliates, subsidiaries, and related companies of Recipient. For purposes of this Agreement, the term "Representative" includes the Recipient's directors, officers, employees, agents, and financial, legal, at~d other advisors. 2. Govemment Records. No information supplied by SCS, or its team members, or subcontractors, to the Recipient, even if subsequently transferred by the Recipient to DOE as provided in paragraph 4 of this Agreement, shall be considered a government record for any purpose whatsoever solely on the basis of its having been supplied to Recipient or transferred to DOE, but shall only be so considered under the operation of applicable law. 3. Confidentiality. Except as provided in paragraphs 4 and 5 of this Agreement, the Recipient and its Representatives shall not disclose any of the Restricted Information in any manner whatsoever, and shall hold and maintain the Restricted Information in strictest confidence. Recipient shall immediately notify SCS in the event of any loss or unauthorized disclosure of any Restricted Inlonnation. 4. Marking. SCS agrees that Restricted Information conveyed to Recipient will be marked with a legend identifying such as Restricted Information subject to Confidentiality and Nondisclosme Agreement. Infom1ation disclosed to Recipient without n legend identifying it as Restricted Information will not be subject to this Agreement, except that, prior to disseminating nny unmarked information which Recipient recognizes should be treated as Restricted Information, Recipient shall provide SCS a reasonable opportunity to review and mark the information appropriate! y. 5. Pennitted Disclosures. Recipient may disclose Restricted Information to DOE and the Recipient's responsible Representatives with a bona fide need to know such Restricted Information, but only to the extent necessary to evaluate or carry out the Work and only if such Representatives are advised of the confidential nature of such Restricted Information and the terms of this Agreement. SCS agrees that Restricted Information may be further disclosed by Recipient to DOE in connection with the Cooperative Agreement and the associated EIS required by the NEPA and that such information will be treated by DOE as Restricted lnfonnation received by DOE under the Cooperative Agreement. 6. Required Disclosures. In the event the Recipient or its Representatives are requested m· required (including, without limitation, by oral questions, interrogatories, requests for information or documents, subpoena, civil investigative demand, or any informal or formal investigation by any government OJ' govemmental agency or authority) to disclose any of the Restricted Information to any party not described in paragraph 4 of this Agreement, the Recipient shall notify SCS promptly in writing so that SCS may seek a protective order or other appropriate remedy or, in SCS's sole discretion, waive compliance, in writing, with the terms of 754!6-1 l 2 SoCo FOIA Response 000348 this Agreement. The Recipient agrees not to oppose any action by SCS to obtain such protective order or other remedy. 7. Use. The Recipient and its Representatives shall usc the Restricted Information solely for the purpose of the Work and shall not in any way use the Restricted Information to the detr·iment of SCS, its affiliates, pat1ners, teaming members, or contractors, including, without limitation, using the Restricted Information to develop products or services or to engage in business competitive with SCS. Nothing in this Agreement shall be construed as granting any rights to the Recipient, b)' license or otherwise, to any of the Restricted lnfonnation. The Recipient shall not make, have made, usc or sell for any purpose any product or other item using, incorporating or derived from any Restricted Information. 8. Confidential Information from DOE. From time to time, SCS, its a11iliates, partners, teaming members, or contractors, may provide Restricted Information related to the Project to DOE. In the event DOE provides such infomtation to the Recipient, the Recipient shall treat such information as Restricted lnlbrmation and usc it solely for purposes of the Work and in accordance with this Agreement. 9. Review of Documents. SCS acknowledges thnt the Work will result in documents intended for public release as part of the NEPA process. SCS agrees that it will promptly review nil information and documents provided to it by Recipient to determine if SCS consents to inclusion of the material in a public document. I 0. Return of Documents. Upon completion of the Work, the Recipient shall notify SCS and shall, at that time or any time upon the request ofSCS for any reason, return to SCS any and all records, notes, and other written, printed or other tangible materials in its possession pertaining to the Restricted Information or otherwise dispose of such materials as reasonably directed by SCS. 11. Confidentiality Period. This Agreement and the Recipient's duty to protect any Restricted Inforn1ntion received from SCS shall expire five years after completion of the Work, or upon mutual agreement of the parties, whichever shall come first. 12. Successors and Assigns. This Agreement and each party's obligation hereunder shall be binding on the representatives, assigns and successors of such party and shall inure to the benefit of the assigns and successors of such patty; provided, however, that the rights and obligations of the Recipient hereunder may be transferred to the DOE m· its designee upon termination of Recipient's Prime Contract , if any, with DOE with prior reasonable notice to scs. 13. Notices. All notices required under this Agreement shall be in writing and shall be delivered by personal delivery, facsimile transmission or by certified or registered mail, return receipt requested. Notices shall be sent to the addresses sci forth at the end of this Agreement or such other address as either party may specify in writing. 14. Severability. If any provision of this Agreement is found by a proper authority to be unenforceable or invalid, such unenforceability or invalidity shall not render this Agreement unenforceable or invalid as a whole and, in such event, such provision shall be changed and 7!1-!lf>.> l 3 SoCo FOIA Response 000349 interpreted so as to best accomplish the objectives of such unenforceable or invalid provision within the limits of applicable law or applicable court decisions. 15 Exclusions. This Agreement imposes no obligation upon Recipient with respect to Restricted information that: (a) was rightfully in Recipient's possession before receipt fi·om SCS; (b) is or becomes a matter of public knowledge through no fault of Recipient; (c) is rightfully received by Recipient fi·om a third party without a duty of confidentiality; (d) is disclosed by SCS to a third party without imposing a duty of confidentiality on the third party; (e) is independently developed by employees of Recipient who did not have access to such Restricted Tnlormation; (t) must be disclosed under order rrom a Court of competent jurisdiction, other than those imposed by pat·garph 5; o1· (g) is disclosed by Recipient with SCS' prior Wl'itten approval. TN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed and effective as of the date written above, SOUTHERN COMPANY SERVICES, INC. (b) (4) By: -------------------------- By: - - - - - - - - - - - -- - - Date: --------------------------- Date: --------------------------- Address: - - - - - - - - - - - - Address: - - - - - - - - - - - - - Facsimile Number: Facsimile Number: ---------- 4 I 4 SoCo FOIA Response 000350 5 SoCo FOIA Response 000351 Dunlap, Ann C. Richard Hargis Tuesday, June 14, 2005 3:19 PM Miller, Robert l. Rekos, Nelson F.; Gollakota, Sai V.; Russia!. Thomas Re: Fwd: FW: SCS NOA SOH chg 512051 SCS NDA SOH chg 5120Sl_l.doc From: Sent: To: Cc: Subject: Attachments: Bob, Tom Russia! has some comments on the "final" version of the SCS NDA (see attached). Rich .... ~ • • II • • PM>>> bS >>>Richard Hargis 6114/2005 2:10PM>>> Tom, Rich bS >>>"Warren, Daniel H."< DHWARREN@southernco.com > 6/8/2005 12:44 PM >>> >>> Bob and Rich, Attached is the final revision of the NDA for your review and approval. With your concurrence, we will pull the trigger on getting it signed by the appropriate folks. Thanks, Dan Daniel H. Warren Southern Company 205-257-6947 This message is intended only for the person's) to whom it is addressed. SoCo FOIA Response 000352 It is PRIVILEGED and CONFIDENTIAL. Any dissemination, distribution, copying, or use of this message or any of its contents, other than by the person's) to whom it is addressed, is prohibited and may constitute a BREACH OF CIVIL OR CRIMINAL LAW. If this message has been delivered to you in error, please delete the message from your system and contact the sender by reply e-mail or collect telephone call (205/257-6947 in the U.S.) as soon as possible. Thank you. 2 SoCo FOIA Response 000353 CONFIDENTIALITY AND NONDISCLOSURE AGREEMENT This CONFIDENTIALITY AND "Agreement") is entered into this _ _ day of Company Services, Inc. ("SCS") and (b) (4) NONDISCLOSURE AGREEMENT (the , 2005 by and between Southe11n ("Recipient"). WITNESSETH: WHEREAS, SCS has been selected for negotiation of an award of a Cooperative Agreement (prime contract) fi·om the United States Department of Energy ("DOE") to serve as prime contractor to perform a demonstration project to engineer, procure, construct, operate, maintain, and evaluate a gasification island plant at a facility owned jointly by SCS' affiliate, Southern Power and Orlando Utilities Corporation, at their Plant Stanton Htcility, located in Orlando, Florida, pursuant to application number DE-PS26-04NT4206 ("the Project"); and WHEREAS, DOE has contracted with the Recipient to prepare an Environmental Impact Statement ("EIS") for the Pmject as part of the DOE's analysis required by the National Environmental Policy Act ("NEPA") and to perform related work (collectively, "the Work") WHEREAS, the Recipient may require access to certain ofSCS's conlidential, important or proprietary information (defined herein as "Restricted Information") in connection with the Work; and WHEREAS, SCS desires to grant the Recipient access to Restricted Information conceming SCS and its activities, solely in connection with the Work; and WHEREAS, the Recipient and SCS wish to set forth the rights and obligations of the parties conceming the usc, dissemination, and protection of all Restricted Infmmation, provided by SCS, team members, or subcontractors on the Project, to the Recipient in accomplishing the purpose of this Agreement. NOW, THEREFORE, in consideration of the premises set forth above and the mutual covenants hereinafter set forth and other good and valuable consideration the sufficiency of which is hereby acknowledged, the Recipient and SCS, intending to be legally bound hereby agree as follows: I. Delinitions For purposes of this Agreement, the term "Restricted Information" means Limited Rights Data, Restricted Computer Sofiware, and Pmtcctcd Data that is the propc11y of SCS, its team members, or subcontractors, and any information so designated by SCS. SoCo FOIA Response 000354 For purposes of this Agreement, the terms "Limited Rights Data," "Restricted Computer Software," and "Protected Data" have the meanings ascribed to them under the Rights in Data-Pmgrams Covered Under Special Data Statutes Clause attached hereto solely for the pmpose of defining Restricted Data as used herein. For purposes of this Agreement, the term "Recipient" includes the Recipient and all affiliates, subsidiaries, and related companies of Recipient. For purposes of this Agreement, the term "Representative" includes the Recipient's directors, officers, employees, agents, and financial, legal, and other advisors. 2. Government Records. No infommtion supplied by SCS, or its team members, or subcontractors, to the Recipient, even if subsequently transferred by the Recipient to DOE us provided in paragraph 4 of this Agreement, shall be considered a government •·ecord for any purpose whatsoever solely on the basis of its having been supplied to Reciricnt or transferred to DOE, but shall only be so considered under the operation of applicable law., 3. Confidentiality. Except as provided in paragraphs 4 and 5 of this Agreement, the Recipient and its Representatives shall not disclose any of the Restricted InfOI'mation in any manner whatsoever, and shall hold and maintain the Restricted Information in strictest confidence. Recipient shall immediately notify SCS in the event of any loss or unauthorized disclosure of any Restricted Information. 4. Marking. SCS agrees that Restricted Information conveyed to Recipient will be marked with a legend identifying such as Restricted Information subject to Confidentiality and Nondisclosure Agreement. Information disclosed to Recipient without a legend identifying it as Restricted Information wilt not be subject to this Agreement, except that, prior to disseminating any unmarked inlbnnation which Recipient recognizes should be treated as Restricted Information, Recipient shall provide SCS a reasonable opportunity to review and mark the information appropriately. 5. Permitted Disclosures. Recipient may disclose Restricted Information to DOE and the Recipient's responsible Representatives with a bona fide need to know such Restricted Information, but only to the extent necessary to evaluate or can·y out the Work and only if such Representatives are advised of the contidential nature of such Restricted Information and the terms of this Agreement. SCS agrees that Restricted Information may be further disclosed by Recipient to DOE in connection with the Cooperative Agreement and the associated EIS required by the NEPA and that such information will be treated by DOE as Restricted Information received by DOE under the Cooperative Agreement. 6. Required Disclosures. In the event the Recipient. or its Representatives are requested or required (including, without limitation, by oral questions, interrogatories, requests for information or documents, subpoena, civil investigative demand, or any informal or formal investigation by any govcnunent or governmental agency or authority) to disclose any of the Restricted Information to any party not described in pat·agraph 4 of this Agreement,, the Recipient shall notify SCS promptly in writing so that SCS may seek a protective order or other appropriate remedy Ol', in SCS's sole discretion, waive compliance, in writing, with the terms of 2 SoCo FOIA Response 000355 this Agreement. The Recipient agrees not to oppose any action by SCS to obtain such pmtective order or other remedy.! 7. Use. The ReciJ>ient and its Representatives shall use the Restricted Information solely for the pmpose of the Work and shall not in any way use the Restricted Information to the detriment of SCS, its affiliates, partners, teaming members, or contractors, including, without limitation, using the Restricted Infonnation to develop products or services or to engage in business competitive with SCS. Nothing in this Agreement shall be construed as granting any rights to the Recipient, by license or otherwise, to any of the Restricted Information. The Recipient shall not make, have made, usc or sell for any purpose any product or other item using, incorporating or derived from any Restricted Information. 8. Confidential Information from DOE. From time to time, SCS, its affiliates, partners, teaming members, or contrnctors, may provide Restricted Information related to the Project to DOE. In the event DOE provides such information to the Recipient, the Recipient shall treat such information as Restricted Information and use it solely for purposes of the Work and in accordance with this Agreement. 9. Review of Documents. SCS acknowledges that the Work will result in documents intended fm· public release as part of the NEPA process. SCS agrees that it will promptly review all information and documents provided to it by Recipient to determine if SCS consents to inclusion of the material in a public document. l 0. Rctum of Documents. Upon completion of the Work, the Recipient shall notify SCS and shall, at that time or any time upon the request of SCS for any reason, return to SCS any and all records, notes, and other written, printed or other tangible materials in its possession pertaining to the Restricted Information or otherwise dispose of such materials as reasonably directed by SCS. II. Confidentiality Period. This Agreement and the Recipient's duty to protect any Restl'ictcd Information received from SCS shall expire five years after completion of the Work, or upon mutual agreement of the parties, whichever shall come first. 12. Successors and Assigns. This Agreement and each party's obligation hereunder shall be binding on the representatives, assigns and successors of such party and shall inure to the benefit of the assigns and successors of such party; provided, however, that the rights and obligations of the Recipient hereunder may be transferred to the DOE or its designee upon termination of Recipient's Prime Contract , if any, with DOE with prior reasonable notice to scs. 13. Notices. All notices required under this Agreement shall be in writing and shall be delivered by personal delivery, facsimile transmission or by certified or registered mail, return receipt requested. Notices shall be sent to the addresses set forth at the end of this Agreement or such other address as either pmty may specify in writing. 14. Severability. If any provision of this Agreement is found by a proper authority to be unenforceable or invalid, such unenforccability Ol' invalidity shall not render this Agreement unenforceable o1· invalid as a whole and, in such event, such provision shall be changed and l3H611 3 SoCo FOIA Response 000356 interpreted so as to best accomplish the objectives of such unenforceable or invalid provision within the limits of applicable law or applicable court decisions. 15 Exclusions. This Agreement imposes no obligation upon Recipient with respect to Restricted information that: (a) was rightfitlly in Recipient's possession before receipt from SCS; (b) is or becomes a matter of public knowledge through no fault of Recipient; (c) is rightfully received by Recipient from a third party without a duty of conlidentiality; (d) is disclosed by SCS to a third party without imposing a duty of confidentiality on the third party; (c) is independently developed by employees of Recipient who did not have access to such Restricted Information; (f) must be disclosed under order from a Comt of competent jurisdiction, other than those imposed by pargarph 5; or (g) is disclosed by Recipient with SCS' prior written approval. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed and effective as of the date written above. (b) (4) SOUTHERN COMPANY SERVICES, INC. By: - - - - - - - - - - - - - By: - - - - - - - - - - - - - Date: --------------------------- Date: -------------------------- Address: ---------------------- Address: - - - - - - - - - - - - - Facsimile Number: Facsimile Number: 'IHS61l ---------- 4 SoCo FOIA Response 000357 Dunlap. Ann C. From: Sent: To: Cc: Subject: Attachments: Gollakota, Sai V. Tuesday, June 28, 2005 3:53 PM Pinkston, Tim Rekos, Nelson F.; RWilLIAM@southernco.com; Russial, Thomas; Mundorf, William Review comments on the draft Repayment Agreement Southern Repayment-with comments-June 28.doc; Southern Repayment-without comments-June 28.doc Attached are the review comments on the draft Repayment Agreement. A few revisions are made mainly to signify the quantification of repayment based on the statements in the 'Basis for Payment' and to relate to the repayment projections made in the commercialization plan. The repayment is expected primarily from licensing of the technology in item (i) in 'Basis for Payment'. However, the original statement "KBR shall pay to SCS for transfer by SCS to DOE an amount equal to (b) (4) of the license fees and/or royalty actually retained by KBR from licensing of the Demonstration Technology to third-party users after satisfying guarantee or warranty responsibilities" is not specific with regard to the dollar amount DOE receives for each license issued (on kWe basis). DOE revisions make such statements more specific. For example, by stating that "a one time fee of$ (b) (4) of nameplate MWe capacity" would be paid to DOE, the language becomes definitive and supportive of repayment projections. Other comments: 1) Statements such as "fees and/or royalty actually retained by KBR" or "payable to DOE during the year in which the facility's commercial operation date occurs" or "projects that began construction prior to Repayment Period expiration will be paid to DOE" result in non-uniform terms and uncertain repayment schedule. Thus, the following sentence is added in Article V to make the payment timing more definitive: "For transactions subject to repayment pursuant to Article IV, repayment shall accrue and be owed in the year the contract for installation of the Demonstration Technology is signed." 2) Since technology licensing is carried out by KBR and the repayment is projected mainly from this source, it is reasonable to expect KBR also to be a signatory for the Repayment Agreement. This point was made at the April 8 meeting at NETL in Morgantown. KBR is receptive to this request. Thus, KBR is included as a signatory in the Repayment Agreement. 3) In item (iii) of Basis for Payment (b) (4) was stated in the original statement. Typically in Repayment Agreements (b) (4) DOE has been using kWe and kWt terminology to facilitate equity for different applications. Thus, (b) (4) is used in view of the possibility of chemicals only plant or electricity & chemicals plant etc. (b) (4) (b) (4) There will be some additional comments (e.g., responses to questions highlighted by Rebecca Williams). Two files are attached: with comments &without comments. SoCo FOIA Response 000358 >>>"Pinkston, Tim E." 6/14/2006 4;03 PM>>> Attached are Rebecca's edits to the cooperative agreement. She will call you tomorrow to discuss these changes. In addition to the changes shown in the document, the key personnel from KBR need to be added to the document. The recommended key personnel from J{BR are: (b) (4), (b) (6) We will resend the repayment agreement tomorrow. I need to confirm that we edited the most recent version. Please call Rebecca if you have questions. > ________________________________________ >From; Williams, Rebecca G. > Sent:Tuesday, June 14, 2006 12:65 PM > To:Pinkston, Tim E.; York, Julia L.; Henderson, Charles W.j Morton, >Frank C. > Subject:Draft of Cooperative Agreement from RGW to Mundorf June > 14 Plus Repayment Plan Rev. by SCS June 14 > > Tim, could you forward the Cooperative Agreement provisions to Bill > Mundorf and Tom Russia] after you get the name of the KBR person to >insert~ Then Nelson wanted the Repayment to go to Sai, Tom, and > himself. Please note that the document I got from you on repayment is > not showing the changes in blue like the printed out version you gave > me does. It may be a draft with the accepted changes in it which is >fine and to which I have added my comments-- unless you have some. > > > <> > < > 2 SoCo FOIA Response 000359 OE·I'S2f•·IHNT.J2U(il Rrpoymrnt l'bn llnuth)'mtnl l'l>n 2.0 DRAFT REPAYMENT AGREEMENT In consideration of the United States Department of Enerm• (DOE) suppon for a clean coal technology demonsu:ation project under the DOE's Clean Coal I'ower Initiative, for which Southern Company Sen•ices, Inc. ami KBR (defined herein as the "ObligorJi") acknowledge:; thcyit. will receive substantial benefit, Obligor;i hereby agree:; to repay the Department of Energy in accordance with the terms and conditions set forth below. Article I. Geneml Objective 'l11e purpose of this Repayment Agreement is to set forth the conditions under which Obligor5_ shall repay to DOE and amount up to, but not to exceed, the DOE share paid under Co-operative Agreement No. DE-FC26-0SNT42391 N-Tll2- Article II. Definitions "Co-operative Agreement'' means the financial assistance award made by the United States Department of Energy (DOE) to Southern Cump:Hl)' Services, Inc (SCS), Instrument Number DErC26-0SNT4:?391 on , 2004, and subsequent nmendments. "Co-operative Agreement Recipient" means the organization that received the award of the Cooperative Agreement. "DOE Share" means the portion of the total project costs paid by DOE under the Co-operative Agreement. "Obligor" means the organization that is responsible foL· repayment under tlus Repayment 1\greement. Obligor includes the organization's successors and assigns. "Repn)•ment Period" means the petiod of time during which tltc Obligor is required to make payments under tlus Repayment1\greement. "Total Project Costs" means the tot:ll amount of allowable direct and indirect cost incurred and pnid, in part, b)' DOE under Co-operative Agreement. " KBR" means Kellogg Brown & Root, Inc. " Dcmonsu:ation Technology" shnll mean the KBR Transport Gasifier in its application for processing coal for the production of raw synthesis gas which may subsequently be further processed to produce electricity or chenucals. Article III. Term of this Repayment Agreement The Repayment Period shall begin at the end of the calendar year of the f1tst sale of the Demonstration Technolog~· ffillf.l " iHg tht Cotnmetei~ti--Gpel'ftting DMe of the-Hcmon:mariotl Usc or disclosure o f <11~ on this >heel i• ~ubj.:c1 tn the ''"rricriun on the opplit:>lion cm-cr •herr for thi• propO!~I. 2 SoCo FOIA Response 000361 Southcnl Comp.1ny Senices, Inc. IJJ\.f'S26-0.JN'I'4:!0ii1 June 21MH ll.l}tnt:tH to DOE doe~ not t:.cceed tht: B9~hm'e. Tltis Repayment Agreement may be terminated upon a determination by the Secretnf)' of Energy or designee that repayment places the Obligm· at a competitive disadvantage in domestic OL' international markets. Article IV. Basis for Repayment The annual amount of repayment to the DOE, by the Obligor, is to be comprised of the cumulath•e effect of the provisions in Article IV (i}, (ii), and (iii): (b) (4) m (i) Obligor shall pay w SCS fot· etttn~fer br-£G£ to DOE ftt'Hlmf:lunt-etttull to (b) (4)of the-licea~e fee.i ltnd/o:t: :t:oy:dty !\effi,tlly t:t'.tRinetl-b~m for licensing of the Demonstration Technology te-4:it:di'*rty user., After illltiflfyins; gtt~tr.tfttee. or \\'ftl'ffit\~ tc.lrwn.;ibtliti~urttil such time as all cost share obligation has been repaid according to this Repayment 1\grectnent.~Gl:-> .~h:tll pnr .lUeh fund.; t·eel'i·.•ed ft•om I
l)'t11<11f l'bn (iii) For any commercial application of the Demonstration Technology by Obligor~CS or its Affiliates for the production of chem..icals excluding this demonstration project, Ohligot·~b£.ftgret.~ re ~h:tll pay to DOE ifem fufltl!i t•t:.edveJ fn~m-iE!i A ftilintt::l a(b) (4) (b) (4) (b) (4) ntil such time as all cost share obligation has been repaid according to this Repayment Agreement. Such payment to DOE shall be prorated by Obligm~ or its Affilintes initial percentage ownership of such facility·ftfld-beeeffie-dtte-mu~,,yaal~ !ft DGH-dtt~e-ye:tHfl w·hieh the faeilitr':i t:otmnereiRl eref1tfit,n dRte eeCUl'!l ft~vided in Al'tiele-¥. Such obligation shall become due and payable to DOE ns described in Article IIJ. Article V. Schedule for Repayment For transnctinns subject to rep;l)'ll\ent pnrsuatH tn Article I\'. repnrmem shnll nccrue and be owed in the yent the contract fm instaUntion of the Demonstration Tedmologr js ~igned. Payments to DOE shall be due within 60 days after each onc-)•ear period following the effective date of this Reparmcnt Agreement. Article VI. Reporting and Record Retention Requirements (A) Annunl Report to DOE Within 60 days after the end of the of each one year period, the Obligor shall submit a written report to DOE which, for the one year period just elapsed, provides the applicable data described below: (I) The total dollar amount of repayment accruing to DOE (2) A description of each tmnsaction from which the repayment obligation accrued (3) The total amount paid to DOE for all years and the amount of the DOE share remaining to be paid in succeeding years under this Repayment 1\greement. [Regarding Commercialization, SCS makes hs general comment thereto at this place in the agreement since the commerci:llization plan is generally considered confidential, except for the reporting required by the below provision. SCS has identified a certain potential problem with commercialization as considered together will aU requirements of the Cooperative Agreement. SCS would lilution emu ~hproposol. SoCo FOIA Response 000363 Snuthcm Comp.11l)· ~nit•••, Inc. June :!IM~I PU-I'S2G·IHNT42tl(,J ltt1Ufi'IICI\I l'hn dming the project. The purpose of the Commercialization Report is to assist DOE to determine the benefit5 obtained from Gm•ernment support of technology development. The Commercialization Report is independent from the Annual Report required b}' the Repayment Agreement and is nor limited to the sale or licensing of "demonstration technology" as that term is defined in this Repayment .Agreement. The Commercialization Report 5hall include a discussion of the Recipients and its team member's efforts to commercialize the technology. The Commercialbmtion Report shall also include descriptions and locations (or proposed locations) of all significant technology, embodies in the demonstration project or derived from technology embodied in the demonstration project, that was sold or licensed during the preceding year (whether or not such transaction were subject to repayment under the terms of the Reparment Agreement). The Commercialization Report shall also include a discussion of any impediments to the cmnmercialization of the technology. TI1e Commerciali?.ation Report shall be due on December 31 of each year. (C) Period of Retention With respect to each annual report to DOE, the Obligor shall retain, for the period of time prescribed in this paragraph, all related financial records, supporting documents, statistical records, and any other records the Obligor reasonably considers to be pertinent to this Repayment Agreement. The period of required retention shall be from the date each such record is created or received by the Obligor until three years after one of the following dates, whichever is eadier: the date the related annual report is received by DOE; or the date tlus Repayment Agreement expires, or the final payment to DO~ is received. If any claim, litigation, negotiation, im•cstigation, audit, or other action involving the records stat·ts before the expiration of the three-year retention period, the Obligor shall retain the records until such action is completed and all related issues are resolved, or until the end of the three-year retention period, whichever is later. The Obligor shall not be re,tuired to retain :my records, which have been transmitted to DOE b}' the Obligor. (D) Authorized Copies Copies made by microfilm, photocopying, or similar methods may be substituted for original records. Records originally created by computer may be retained on an clectr01uc medium, provided such medium is "read only" or is pwtectcd in such a manner tl1at the electronic record can be authenticated as an original record. (E) Access to Records DOE and tl1e Comptroller General of the United States, or any of their authorized reprcsentath•cs, shall have the right of access to any books, documents, papers, or other records (including those on electronic media) wluch arc pertinent to this Repa}•tnent Agreement. ·n,e purpose of such access is limited to the making of audits, cxatninations, excerpts, and transcripts. The right of ncccss described in tlus paragraph shall last as long as the Obligor retains records, which are pertinent to this Repayment Agreement. (I') Restrictions on Public Disclosure Usc or o.li~ clu,;tuc of d•t~ on this shcu is subject tn tlu: rntri(tion nn I he ~pplicJtion corer llhrrt for thi• pmpoJ1I. s SoCo FOIA Response 000364 Southem Comp>O)' Scn;cu, Inc. June 21NH Dt::-I'S2G·O•INT42\I(•I 1\tp>)'mcnt l'bn The redernl E:eedom of Information Act (5 U.S.C. Section 552) does not apply to records the Obligor is rcttuh·cd to retain b)• the terms of this Repayment Agreement. Unless othenvise required by law or n court of competent jurisdiction, the Obligor shall not be required to disclose such records to the public. (G) flow Down of Records. Retention, and Access Ret;juirements Obligor shall include clauses substantinll)' similar to the record retention and nccess requirements set forth in sections (B) and (D) of this Article in all agreements when necessary to fulftll the Obligor obligations under this Repayment Agreement. Article VII. Defilult [Sec Rcbecca,s comment above at top of document]. If the Obligor fails to make payment within the time specified in Article V, or fnils to submit the annual report within the time specified in Article VI, Recipient shall be in default of this Repayment Agreement. If Obtigor fails to cure the default within 30 days after receipt of notice of the default from DOE, notwithstanding any provision of the Co-operative Agreement or Repa}•tnent Agreement to the conuat)', the total unpaid amount of the DOE share shall be i.mtnediatcl}' payable to DOE. Article VIII. Disputes Disputes arising under this Repayment .Agreement shall be subject to the (>I'Occdurcs set forth in 10 CFR 600.22 Disputes and Appeals. UNITED STATES DEPARTMENT OF ENERGY Signature: - - -- - - -- - - - - -- - - Name: Date: Title: Conu·acting Officer: OBLIGOR (Southern Company Services) Signature:-------------------Name: _ _ _ _ _ _ _ _ _ _ _ _Date: Title: OBLIGOR (KBR) Signntme: Name; Date: U:ll. SoCo FOIA Response 000365 Dunlap, Ann C. From: Sent: To: Subject: Attachments: "Williams, Rebecca G." Tuesday, July 05, 2005 2:20 PM Russia!, Thomas FW: SCS Insurance Summary Write-up - CCPI2 10924 DOE Insurance Write-up on Orlando RevS.doc -----Original Message----From: Henderson, Charles W. Sent: Friday, July 01, 2005 3:11 PM To: Williams, Rebecca G.; York, Julia L. Subject: FW: SCS Insurance Summary Write-up - CCPI2 FYI - 1 meant to include both of you on distribution. In my haste to finish I forget to add you to cc list. >Charles Henderson >Admin & Project Support Manager >Power Systems Development Facility >8-824-5844 (b) (6) > > ----Original Message----From: Henderson, Charles W. Sent: Friday, July 01, 2005 3:08PM To: Nelson Rekos; 'Sai Gollakota' Cc: Pinkston, Tim E.; Rush, Randall E.; Whatley, Larry; Haskew, Tim Subject: SCS Insurance Summary Write-up - CCPI2 Attached is the summary write-up of the Southern Company Services insurance program that you requested. Additional information has been provided, where appropriate, for the Orlando CCPI2 project. The SCS Risk Management Group developed this summary with input from the SCS CCPI2 project management team. Please call me if you have any questions concerning this information. SoCo FOIA Response 000366 Southern Company Services (SCS) Insurance Program And Considerations for the Orlando CCPI2 Project SCSINSURANCEPROGRAM (b) (4) .. SoCo FOIA Response 000367 SoCo FOIA Response 000368 SoCo FOIA Response 000369 SoCo FOIA Response 000370 SoCo FOIA Response 000371 SoCo FOIA Response 000372 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Thomas Russia! Wednesday, May 10, 2006 3:33 PM david.r.hill@hq.doe.gov; MASTERSON, MARY; Grant, William Taxation of DOE Funds 20060508145946053.pdf; SCS - Clean Coal DOE Funding- Tax Jssues_l.DOC b5 '! SoCo FOIA Response 000373 TROUTMAN SANDERS LLP ATTORNEYS AT LAW A LIVIf.O LIAIILU., •AIH,.CIUHII IIAIIK OF AMERICA PL ... ZA 800 PeACHTREE STREET II E • SUIT! 5200 ATlAIITA GEOROIA 30301•2218 WVJ\'f ltoutmanaandeta con TEL~PHO~E ; •o4•1U·3000 FACSIMILE: •o:-US-3000 Slilnley H. Hackett stanley hacJteHCIIOIIImansanders com Oltecl Dbll: 404·8115-31 S4 Okec1 Fax- 404·0112·65711 May4, 2006 .J. Petet Baumgarten, Esquire Intcmal Revenue Set vice Room 4238 CC:IT&A:B04 1111 Constitution Avenue, N.W Washington, DC. 20224 B. David Silber, Esquire SeniorTechnical Reviewe1 Intcmal Revenue Service Room 4312 CC:FIP:B02 1111 Constitution Avenue, N.W. Re: Southcm Powe1 Company/ Request for Ruling in connection with certain US. Department of Enetgy P10ject Funding Wushington,D.C. 20224 Dear Mcssts. Baumgruten and Silbet: Thank you for meeting with Roger Reignet and me on April 24, 2006, to discuss the ptoposed Request for Ruling involving the funding to be tcccivcd by Southcm Powet Company from the U.S Depattmcnt of Energy in connection with the ttanspott gasifier IGCC Project I will not belabor the points we discussed at the meeting, but would like to offct the following for your additional considetation: 1. While Rev. Rul. 80-235 can certainly be distinguished on its facts ftom the situation as to which we seck the "contingent loan" lette1 ruling, the substance of the Revenue Ruling is directly on point. Each situation involve.c; nn obligation to pay wttich is teal but which is subject to contingencies. The Revenue Ruling involves "calculation of basis" as opposed to "inclusion in income," but it would appear that these notions ate entirely comprunble - if an obligation is so contingent that it cannot be included in basis, then it should not be included in income. The Intemal Revenue Code should be intetpteted as symmetiical in this context. Revenue Ruling 80-2'35 was cited in all of the ptivate lette1 rulings we called to your attention, including 8646005, 9249016, 9244021, 9313025, and 9317005 . It also has been cited in other letter tulings, including 8702006, 8301001,200044004, and in Rev. Rut. 81-262 The point A lJ.. ANT 1\ • HONO KONO • L·ONDON • Nuw YORK • NORI'Ot.K • R ... l. UIOH RICHMOND • "J:"YSONS CORNBR • VIROINIA BBACII • WASHINOION, O . C. SoCo FOIA Response 000374 TROUTMAN SANDERS LLP ATTORNEYS AT LAW .A '-'"I'•D LIAIIIV fY t'AJIIIJirUfii"U Mr J. Pcte1 Bnumgmten Mr. B. David Silber May4, 2006 Page2 must be made that the Revenue Ruling is not an nbenntionnl statement of IRS position, but is policy of long-standing that has been applied in situations quite compnmble to that which we posed in out draft Request for Ruling 2. One spccilic inquiry you had at our meeting was how it would be determined whether the IGCC Project was successful or a failure . In othe1 words, what would be the determination point at which time the DOE funding would begin to be repaid? Although the Cooperative Agreement provides n Statement of Objectives und a number of "Deliverables" fat each phase of the Demonstration P10ject (see Cooperative Agreement Attachment A), the ultimate test of commereiality will be whether the technology is in fact ~old or licensed to thitd patties Southem Power Company (and Southem Company Services) have a conhactunl obligation to pursue commercialization, which obligation is enforceable by DOE. However, whether the demonstration technology is ultimately commercialized will depend on n vruicty of factots including nvnilabiHty and cost of nltemntives, prevailing coal and gas pticcs, the regulntoty environment, energy demand, and other factots We believe the repayment obligation is a substantial commitment and understand that DOE also views it as such In this regatd, in the near futme, I will endeavm to set up a telephone conference call between you, me and Thomas J. Ru~sial, Chief Counsel, DOEINETL, who was involved in negotiating the Cooperative Agreement, and has volunteeted to provide to you the DOE's perspective on the substantiality of the repayment obligation under the Cooperative Agreement I 3. To the extent we may not have adequately described the IGCC Project and the significance of the advanced gasifier technology to our Nation's energy policy, please find enclosed n copy of an article ftom the May-June, 2006 issue of Harvard Magazine. The article notes that in one fashion or another, the only energy source tcalislically available to meet out Nation's energy needs for the balance of this century is coni. The article includes a diagram of an IGCC plant. Note that the technology involved with the ttanspott gasifier IGCC Project is an advancemellt over the technology depicted in the nrticle. For example, the TRIG* technology is air-blown, not oxygen blown, will produce less waste by-products, and is projected to be less expensive to build and ope1ate than the existing technology depicted in the Biticle. " My point in calling the article to your nttention is simply to emphasize that the significance of coal-based technology to our national enetgy policy hns not only been endorsed by the Ptesident as well as the Congress, but is recognized by the private sector, including academia While yout focus uppropriately may be on technicalities of federal income tax law, we hope the m.s will not lose sight of the broader public policy, and to the extent there is discretion, we would mge that it be exercised on the side of suppotting the broader public policy. At the April 24 meeting, we all noted the incongruity of the conflicting notions of the repayment SoCo FOIA Response 000375 TROUTMAN SANDERS LLP ATTORNEYS AT LAW ,_ UUitiO LIAtiUIW' ~£111fU.-IHIJ' Mt J. Petet Baumgarten Mt . B. David Silber May4,2006 Page3 obligation being too contingent for the funding to receive conlingentloan treatment, yet too substantial for the funding to receive contribution to capital treatment. This conflict poses a classic "Catch-22" and results in a tax policy that makes little sense from either a fiscal otan energy policy standpoint From a fiscal standpoint, a repayment po:~sibility is penalized (taxed), .suggesting that the better fiscal policy is simply to give the funds with no possibility of repayment. F10m an energy standpoint, the result of the proposed tax policy is that one branch of government is providing funding to encourage activity suppottive of a public pu1pose (which would not happen without the funding), while anothet branch of govemment is reducing that funding . The vety condition that is fiscally sound- requiting at least some possibility of repayment - is cited as the critical factor that makes the funding neither a contingent loan not a contribution to capitnl, and thw; fully taxable. At a minimum, we believe that the Deprutrnent ofTreu.su1y and the Depattrnent of Energy need to jointly considet this matter and hopefully detetmino that a tax policy should be adopted which will suppott the energy policy. Thunk you again, and we look fotwatd to further discussions regarding this matter. Very truly youts, ~ ~ \~Lttt- Stanley H. Hackett Attachment cc: Thomas J. Russia!, Esquire / Chief Counsel U.S . Department of Energy National Enexgy Technology Laborataty MaiJ Stop 922-M212 P.O. Box 10940 Pittsburgh, PA 15236-0940 SoCo FOIA Response 000376 TROUTMAN SANDERS LLP ATTORNEYS AT LAW A l.l .. lfiD \.t.at Llf., ''-ltlllill'"._tiU M.t . J. Peter Baumgattcn B. David Silber Mr~ May4,2006 Pnge4 Patrick T McCroarty, Esquire Internal Revenue Set vice Room5115 CC:PSI:BOS 1111 Constitution Avenue, N.W Washington, D.C 20224 SoCo FOIA Response 000377 TROUTMANSANDERSLLP MEMORANDUM TO: Thomas J. Russia!, Esq. Chief Counsel U.S. Department of Energy National Energy Technology Laboratory FROM: Troutman Sanders LLP RE: SCS/DOE Pre-submission Conference DATE: May 4, 2006 Southem Company Services, Inc. ("SCS") and Kellogg Brown and Root, Inc. ("KBR") have entered into an arrangement with Department of Energy ("DOE") to share the cost of building a coal gasification plant designed as a fuel somce for a combined cycle electrical generating facility to be located in Orange County, Florida (the "Project"). Pmsuant to the terms of the Cooperative Agreement and Repayment Agreement (the "Agreements"), the DOE has agreed to provide funds for up to $235 million of the Project costs in three phases. Prim to the end of each phase, SCS must apply for additional funding for the next phase which may be approved by the DOE based upon progress towards meeting the objectives of the Project, availability of funds, as well as other factors. Title to the Project will generally vest in an affiliate of SCS and the Orlando Utilities Commission ("OUC"), (b) (4) respectively, except for certain assets, which will vest (b) (4) in OUC. As part ofthe Agreements, the Government obtains the entire right, title and interest throughout the world in any SCS invention conceived of or SoCo FOIA Response 000378 first actually reduced to practice in the course of ot· under the Cooperative Agreement to build, demonstrate and commercialize the gasification technology utilized by the Project. The Cooperative Agreement grants to SCS a revocable, nonexclusive, royalty free license in each patent application filed in any country on such inventions. The Government also obtains limited and unlimited rights to certain data related to the Project involving such things as computer data bases, training materials, operating manuals, etc. In addition to any other rights granted to the Govcmmcnt under the Cooperative Agreement, SCS agrees to negotiate in good faith with a third party purchaser to construct a commercial-size facility using the gasification technology developed and demonstrated by the Project. This third party eonstmction agreement would include licensing agreements for the patented technology developed by the Project. If SCS and such third party cannot reach an agreement on terms after two years of negotiations, the third party cun go to court to force such an agreement on reasonable terms and conditions. The foregoing docs not apply if the DOE is satisfied that SCS is supplying tJ .S. Market needs for the Project teclmology at reasonable prices. Under the terms of the Repayment Agreement, SCS and KBR are individually liable to repay any DOE funding provided under the tcnns of the Cooperative Agreement from certain revenue strains generated from the license, sale or use of the Project technology. The Repayment Period is 20 years from the date the Cooperative Agreement is terminated, which, if the gasification facility is completed, is (b) (4) after the beginning of commercial operation. KBR agrees to pay the DOE (through SCS) (b) (4) of any license fees or royalties retained by KBR from licensing the Project technology to third party users for the production of electticity, steam, chemicals or fuels. In the event 164162J_ l.POC 2 SoCo FOIA Response 000379 SCS directly enters into such licensing agreements with third parties, SCS agrees to pay the DOE (b) (4) of such fees and royalties. If, under the terms of the business arrangement with a third party, no charge is made by KBR or SCS tor the third party's usc of the Project technology, KBR and SCS, as the case may be, agree to pay the DOE (b) (4) electric of installed capacity of the facility using the technology. JfSCS or its afliliates builds a gasification facility (othe1· than the Project) using the Project technology, SCS agrees to pay the DOE (b) (4) of initial, actual tested perfonnance of the facility. Payment by KBR or SCS, as the case may be, of the (b) (4) portion of any license ot·royalty of the technology is required for the entire license term if the license agreement begins during the Repayment Period yet extends beyond the Repayment Period. Similarly, payment by SCS of installed capacity using the technology is required if the ground breaking for an SCS facility occms at any time during the Repayment Period, regardless of the commercial operation date. Separate repayment provisions apply to the usc of the Project technology to produce chemicals and fuels and are based upon a dollar amount per volume of production capacity of the respective facility. For a period of five years alter the completion of the Project, SCS and KBR are obligated to report to the DOE on theil· progress and success in marketing the technology developed from the Project. The purpose of the report is to assist the DOE in determining the benefits obtained from the Govemment's funding of a portion ofthe Project. SCS and KBR are required to discuss their efforts to commercialize the technology, i.e., enter into license and royalty agreements, build and sell gasification facilities using the technology, etc. SCS and KBR arc required to provide descriptions l64162J_l.DOC 3 SoCo FOIA Response 000380 and locations of all technology that was sold or licensed during the preceding year as well as any impediments to the commercialization of the technology. In the event of default for failure to make payment within the tenus specified in the Repayment Agreement, or the failure to pi'Ovide the required reports, the defaulting party is obligated to pay the DOE $1 00 per day for each day of default. The Agreement does not preclude the DOE from pursuing any other remedy against the defaulting party for repayment of moneys due, including interest thereon in accordance with applicable statutes and regulations. The general terms of the Cooperative Agreement and the Repayment Agreement between SCS, KBR and the DOE are not unique. Between July 31, 1992 and January 5, 1993 the IRS issued five Private Letter Rulings on materially identical facts: PLR 9244021, 9249016, 9313025, 9313026, and 9317005. In each of these rulings, the taxpnyet· was to receive funds fmm a government agency in order to defray the cost of developing new technology. In each case, the taxpayer was required to repay the agency funds from revenues generated fmm the sale or license of the technology generated fmm the Project, the requirement for repayment ended after a fixed period of time and no interest was due on any of the agency funds advanced. In each ruling, the IRS concluded that the agreements between the taxpayer and the agency established a debt obligation running from the taxpayer to the agency. Because the taxpayers' obligations to repay were contingent solely on revenues generated by a commercially untested process or technology, the IRS ruled that the taxpayer could not claim basis in any assets acquired from the funds until repayments were actually made. In none of the Rulings were the taxpayers considered to have taxable income upon receipt of the agency funds. 164162l_ I.DOC 4 SoCo FOIA Response 000381 All five of the rulings relied upon Revenue Ruling 80-235 as authority foa· the position that a conditional debt obligation does not create basis until repayment is made. In Revenue Ruling 80-235, an individual claimed to have developed a process fm· conversion of coal into synthetic fuel. A partnership entered into a constl'llction contract with the individual to build the conversion facility. The purchase price for the facility was made in the form of a I 0 year interest bearing non-recourse note secured by the tobe-built facility and payable out of the net revenue generated li·om the operation of the facility. In any event, the note was due at the end of its ten year term. On these facts, Revenue Ruling 80-235 holds that because repayment of the obligation was speculative, in that there must be adequate cash 11ow from the partnership before a principal payment is made, the paa·tnership could not include the note as basis in the facility. According to the Revenue Ruling, "because payment under the Purchase Note is contingent upon future cash llow the Purchase Note is a contingent liability" for basis purposes. Implicit in this Ruling is the holding that the individual's transfer of the assets to the partnership was not a taxable event. If it had been, the partnership would clearly have had basis equal to the amount recognized as income, i.e., the fair mat·ket value of the facility received. On April 25, 2006, Stanley Hackett and Roger Rcigner, attorneys with law linn of Troutman Sanders LLP, met with representatives of the IRS on behalf ofSCS. The purpose of the meeting was to discuss a dran Private Letter Ruling request submitted by the law firm asking the IRS to mle that the amounts to be received by SCS from the DOE for the Project would not be subject to federal income tax on the grounds that the · amounts represented non-taxable contingent loans. In addition, the draft request asked 1641623_l.I>OC 5 SoCo FOIA Response 000382 that the IRS rule that any amounts remaining unpaid at the end of the Repayment Period be treated as non-shareholder contributions to the capital of SCS, and also not subject to federal income tax. Allending the meeting on behalf of the IRS were Pete Baumgarten, Branch 4, Income Tax and Accounting, David Silber, Branch 2, financial Institutions and Products, Jonathan Silver, Drancl1 2, Financial Institutions and Products, Steve Toomey, Branch 4, Income Tax and Accounting and Patrick McGroarty, Branch 5, Pass-Throughs and Special Industries. After discussing the principle provisions of the Agreements as they related to the funds provided by the DOE to the Project, the nature of the Project Tcclmology and the SCS and KBR repayment obligations, the IRS representatives addressed the tax issues raised . First to speak was Mr. Silber fi·mn financial Industries and Products who expressed his concem that the an·angements described were too fact intensive to be the subject of a Private Letter Ruling. Mr. Silber admitted that he was aware of several Private Letter Rulings that had been issued in the early 1990's but had no recollection of having been involved in those rulings himself. He expressed some doubt as to whether his Branch had been consulted at all, given that the Rulings were issued by Income Tax and Accounting, not Financial Institutions and Products. Mr. Silber went on to say that if he were required to rule, for example, upon a request for Technical Advice, he would rule that the Agreements do not create a non-taxable debt obligation because repayment is too speculative. Mr. Silber noted that no interest was due under the Agreements and it was simply too uncertain that any amount would be repaid to the DOE. 164162l_ I.DOC 6 SoCo FOIA Response 000383 At that point the conversation turned to whether the DOE provided amounts should be treated as non-shareholder contributions to SCS's capital at the outset rather than when any amount remained unpaid at the end ofthe repayment obligation. Mr. McGroarty responded to this question in the negative on the grounds that, in his view, a non-shareholder contribution to capital cannot have any obligation to repay, contingent or otherwise. Mr. McGmnrty's position presumably stems li·otn his reading of' U.S. v. Chicago. Burlington & Quincy R.R. Co., 93 S. Ct. 2169 (1973) which denied a depreciation deduction for assets acquired from state contributed funds. Under pre-54 law, shareholdet· and non-shareholder contributions to the capital of a corporation were treated alike. The corporation received the funds tax-ft·cc and received basis and depreciation deductions with any property acquired. Brown Shoe Co. v. Commissioner, 70 S. Ct. 820 ( 1950). The question of whether a payment by a non-shareholder to a corporation was a contribution to capital focused on the motives of the transferee. If the tmnsfer was for the Jllll1lOSe of benefiting the community at lat·ge, the transfer was treated as a nonshareholder contribution to capital under Brown Shoe. On the other hand, if the purpose of the transler was to enable the tmnsfem1· to receive services from the transferee, the transfer was a payment for future services and not a contribution to capital. Dctl'Oit Edison Co. v. Commissioner, 63 S. Ct. 902 (1943) (payment by customers for electric line extensions were the price of the electric service). In either case, the receipt of the funds was not a taxable event under pre-1954 law as either a contribution to capital or as a contribution in aid of construction. (The Code now pmvides that the latter is specifically subject to tax except in cet·tain select circumstunces.) However, in the case 1641623_1.DOC 7 SoCo FOIA Response 000384 of a non-shareholder contribution to capital, the corporation received depreciable basis for the assets acquired with the funds, while in the latter case, the corporation did not. The Court in Chicago Burlington was called upon to resolve a special situation involving a corporation that claimed pre-1954 Code basis for facilities constructed at railroad crossings with government fi.mds provided for the purpose of improving public safety and the country's highway systems. The railroad argued that it was no different from the taxpayer in Brown Shoe that received fi.mds from community groups to build facilities in their neighborhoods which would improve the tax base and provide jobs. Analyzi_n g Brown Shoe, Detroit Edison, and Edwards v. Cuba Railroad, 268 U.S. 628 (1925) (government contribution for railroad constmction was not taxable income) the Court concluded that allowing a corporation to receive non-shareholder contributions to capital free of tax and then include those funds in depreciable basis "produced a seemingly anomalous result." Noting that the 1954 Code changed this result by specifically providing that property received from non-shareholders as a contribution to capital received zero basis, the Court sought to determine the nature of the govermnent subsidies to Chicago Burlington for depreciable basis purposes. Jn determining that Chicago Burlington did not have basis in its pre-1954 assets even under pre~ 1954 law, the Court looked not only at the motivation of the transferor but at the usc of the funds by the tmnsferee corporation as well. In order to claim depreciable basis for assets acquired with non-shareholder provided funds, the Court looked at the following factors: (1) whether the funds become a pcm1anent part of the transferee corporation's working capital; (2) whether the transfer is a direct payment for a specific quantifiable service provided by the transferee corporation for the transferor; (3) whether 164162J_I.DOC 8 SoCo FOIA Response 000385 the funds are bargained for; (4) whether the assets received or acquired will foreseeably result in a benefit to the transferee corporation in an amount commensurate with their value; and (5) whether the assets are employed in or contribute to the production of additional income, thereby assuring theit· value in that respect. According to Mr. McGroarty, SCS fails the first of these Chicago Bul'lington tests because the DOE funds will (or may) not become a permanent part ofSCS's working capital because the funds may be required to be repaid under the terms of the Repayment Agreement. Mr. MeGronrty readily acknowledged that his position was seemingly at odds with Mr. Silber's, i.e., the DOE repayment obligation is too contingent to be treated as debt yet too real to treat the DOE funds as a non-shareholder contribution to SCS's capital. Mr. McGroarty also acknowledged that if the contingent repayment obligation was removed the DOE funds would satisfy the criteria for a non-taxable contribution to capital. The current IRS position on the taxability of the amounts received by SCS ti·om the DOE is obviously bad policy from a government funding prospective because it reduces the amount of DOE funds available lbr the Project, effectively taking the money from one government agency and giving it to another. It is also poor fiscal policy because it discourages the DOE from seeking to negotiate awards with repayment provisions in order the satisfY the IRS's interpretation of the non-shareholder contribution to capital rules. The IRS's position on the contingent debt question is also not a required conclusion under the law as evidenced by the five Private Letter Rulings in 1992 and 1993 that held otherwise. Finally, the IRS position on non-shareholder contributions to capital is based upon a Supreme Court case that dealt with a question of depreciable basis 1641623_ l.llOC 9 SoCo FOIA Response 000386 under pre-1954 Code law, not taxable income. If there had been any question that the govemment funding in Chicago Burlington had been taxable income to the railroad, the basis issue would have been moot. In short, there is ample authority for the IRS to rule that the funds provided by the DOE to SCS to dcfi·ny the cost of developing clean coal technology are not taxable income to SCS and that the IRS's refusal to do so is at odds with national energy policy, environmental policy, liscal policy, as well as good tax policy. 164162J_I.DOC 10 SoCo FOIA Response 000387 From: Sent: To: Cc: Subject: Attachments: Madden, Diane R. Tuesday, February 06, 2007 1:01 PM Gollakota, Sai V. Markel, Kenneth; Cutright, Ron; Russial, Thomas Southern Company Continuation Application for BP2 OGP CA BP 2.pdf Sal, Attached for your review Is a PDF copy of the Continuation Application for Budget Period 2 for the Orlando Gasification Project for Cooperative Agreement DE-FC26-06NT42391. After you have had a chance to take a look at the material, give me a call and we can discuss what needs to be done. Diane SoCo FOIA Response 000388 Randall E. Rush Southern Company Generation D1rector Power Systems Development Fac1flty Research &Environmental Affairs Post Off ce Box 1069 Wilsonv1 le A abama 35186 Tel 205 670 5842 Fax 205 670 5843 rerush@southernco com SOUTHERN C\ COMPANY Enagy to Serve Your World" January 30, 2007 Mr. William R. Mundorf Contract Specialist Acquisition and Assistance Branch B Department of Energy - NETL 626 Cochrans Mill Road P.O. Box I0940 Pittsburgh, PA 15236-0940 RE: Orlando Gasification Project (OGP) DOE Cooperative Agreement Number DE-FC26-06NT42391 Continuation Application for Budget Period 2 Dear Mr. Mundorf: Three copies of the OGP Continuation Application for Budget Period 2 are enclosed for DOE's review. Budget Period 2 begins on April I , 2007 and goes through May 31, 20 I0. A completed Standard Form 424A Budget Information- Non Construction Programs can be found in Section 5 of the application. The activities during the Project Definition Phase were contract implementation with the major participants, environmental permitting, capacity need determination, and Front End Engineering Design. The objectives in all of these areas have been met. The Cooperative Agreement with DOE and subcontracts with (b) (4) have been signed. The Site Certification (Florida permitting) process is complete and the necessary permits are in place for construction to begin. The Florida Public Service Commission issued the final order approving the Petition for Need on May 31, 2006. The major FEED activities have been successfully completed and the conceptual design was validated. SoCo FOIA Response 000389 Mr. William Mundorf January 30, 2007 Page2 The project is ready to move forward to Budget Period 2 pending final financial approval of the project by Southern Power and approval of the NEPA process with a Record of Decision (ROD) that is expected in the first half of March, and DOE's approval of this Continuation Application. We plan for all of these final decisions to be made by March 31, 2007, and then immediately begin the activities for Budget Period 2. SCS requests that this continuation application be reviewed as soon as possible so that negotiations can be completed in time for detailed design and procurement activities to begin on April I in support of meeting the June I, 20 I 0 Commercial Operations Date. Sincerely, Enclosures Cc: Department of Energy - NETL Diane Madden Southern Company Services Robert Carter Charles Henderson Chris Hobson (w/o encl.) Frank Morton Tim Pinkston Randall Rush Project File SoCo FOIA Response 000390 DEMONSTRATION OF A 285 MW COAL-BASED TRANSPORT GASIFIER ORLANDO GASIFICATION PROJECT CONTINUATION APPLICATION BUDGET PERIOD 2 April I, 2007 -May 31, 20 I 0 Cooperative Agreement No. DE-FC26-06NT42391 U.S. Department of Energy National Energy Technology Laboratory Submitted by: Southern Company Services, Inc. Binningham, Alabama January 2007 Restricted Use Notice "This proposal or quotation includes data that shall not be disclosed outside the Government and shall not be duplicated, used, or disclosed, in whole or part, for any purpose other than to evaluate this proposal or quotation. If, however, a contract is awarded to this offeror or quater as a result or in connection with the submission of this data, the Government shall have the right to duplicate, use or disclose the data to the extent provided in the resulting contract. This restriction does not limit the Government's right to use infonnation contained in this data if it is obtained from other sources without restriction. The data subject to this restriction are contained in sheets marked with restrictive legends." SoCo FOIA Response 000391 Southern Company Services, Inc January 2007 DE· FCl6·06NT42391 I 0 Introduction 1.0 Introduction and Executive Summary Executive Summary of Project Status The activities during the Project Definition Phase were contract implementation with the major participants, environmental permitting, capacity need determination, and Front End Engineering Design. The objectives in all of these areas have been met. Southern Company Services, Inc. (SCS) has signed the Cooperative Agreement with DOE and and subcontracts with (b) (4) (b) (4) have been signed. The Site Certification (Florida permitting) process is complete and the necessary permits are in place for construction to begin. The Florida Public Service Commission issued the final order approving the Petition for Need on May 31, 2006. The major FEED activities have been successfully completed and the conceptual design was validated. The project is ready to move forward to Budget Period 2 pending final financial approval of the project by Southern Power and approval of the NEPA process with a Record of Decision (ROD) that is expected in the first half of March, 2007. Project Summary SCS, in a team effort with Southern Power Company - Orlando Gasification, LLC (SPCOG), OUC, and KBR, will design, construct, and operate a coal-based 285-MW Integrated Gasification Combined Cycle (IGCC) power plant to demonstrate Transport Reactor Integrated Gasification (TRIGTM) combined cycle technology. The TRIGTM plant, to be located at the Stanton Energy Center near Orlando in Orange County, Florida, will have two main islands: a Gasification Island and a Combined Cycle Island. The Gasification Island will use air-blown transport gasifier technology to generate syngas from U.S. coal (e.g., Powder River Basin coal). The syngas, cleaned in the Gasification Island, will be used for fueling the Combined Cycle Island, a new combined cycle power generating facility, planned for installation in June 20 I0 by OUC and SPCOG. Except for the incremental items required for syngas operation, the Combined Cycle Island, which includes a gas turbine, heat recovery steam generator, and a steam turbine, will be built without DOE funds. The Gasification Island, which includes the fuel handling, Transport Gasifier, syngas clean up system, and ash handling will be jointly owned by SPCOG and OUC and will be cost shared by DOE. In addition to demonstrating a first-of-a-kind gasification system with efficiency, capital cost, and operating cost advantages, this technology has substantial advantages with low-rank coals. The project also demonstrates advanced technologies for particulate removal using high temperature-high pressure filters, solids removal, mercury removal, and operation of a sulfur removal system for syngas cleanup. The project has the following four phases: (i) Project Definition, (ii) Detailed Design, (iii) Construction, and (iv) Demonstration. Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal I-I SoCo FOIA Response 000392 DE-FC26-06NT42391 I 0 Introduction Southern Company Services, Inc January 2007 Process Description The Transport Gasifier was developed by Southern Company and KBR based on KBR' s catalytic cracker technology which has been used for decades in petroleum refineries, KBR's pilot plant work, and the operating experience at the Power System Development Facility. The gasifier operates at considerably higher circulation rates, velocities, and riser densities than a conventional circulating bed, resulting in higher throughput, better mixing, and higher mass and heat transfer rates. The transport gasifier offers a simpler, more robust method for generating power from coal than other available alternatives. It operates at a temperature below the melting point of ash, providing the potential for more reliable operation than stagging gasifiers. It is unique among coal gasification technologies in that it is cost-effective when handling low rank coals and when using coals with high moisture or high ash content. These coals make up half the proven U.S. and worldwide coal reserves. In addition, the transport gasifier is the only gasification technology capable of both air- and oxygen-blown operation. For power generation it will normally be configured to operate air-blown, but it can operate equally well oxygenblown. This inherent flexibility will allow it to readily adapt to applications beyond power generation, including chemical production and future carbon dioxide management requirements. The Orlando Gasification Project is designed to gasify Powder River Basin sub-bituminous coal with steam and air to produce syngas. Process air is primarily supplied by an air compressor, with the remainder extracted from the Combustion Turbine located in the power island. The syngas is cooled in the Primary Syngas Cooler to produce high pressure superheated steam which is exported to the power island for the HP Steam Turbine. The syngas is then routed to the Particulate Control Device, where the fine ash is removed. Before the particulate-free syngas leaving the particulate filters can be burned in the gas turbine, the sulfur, mercury, and nitrogenous-compound content must be reduced to ensure environmental compliance. The syngas is cooled which facilitates removal of almost all the nitrogenous compounds, chloride, and fluoride present along with lesser amounts of C02, H2S and COS. The cooled syngas flows through a COS Hydrolysis Unit and a Mercury Removal Reactor before entering the Desulfurization Unit. In this process the syngas is contacted with a solvent which removes essentially all of the H2S from the syngas stream. The "sweet" syngas leaves the contactor and is heated before it is com busted in the Gas Turbine. The Combustion Turbine is aGE 7F turbine, modified for syngas service but also has the capability of being fired by natural gas. The exhaust from the Combustion Turbine is cooled in a Heat Recovery Steam Generator (HRSG). The steam generated in the HRSG and the export steam from the gasification island is combined and routed to the steam turbine in the power island. Project Objectives The overall project objectives are to design, construct, and operate a Transport Gasifier based advanced integrated gasification combine cycle power plant that uses U.S. coal to generate 285MW (net) electricity. The sub-objectives of the project include: I. To design, build, and operate a state-of-the-art coal Gasification Island utilizing KBR Transport Gasifier technology and integrate it with a Combined Cycle Island. Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 1-2 SoCo FOIA Response 000393 DE·FC26-06NT42391 1 0 Introduction Southern Company Servtcc:s, Inc JanWiry 2007 2. To design, construct, and operate an advanced cleanup system that includes a sulfur removal system, high-temperature, high-pressure particulate filter system, selective catalytic reduction, and a mercury removal system. 3. To demonstrate high availability, high thermal efficiency, low cost, and low emissions of the TRJGH·1 electricity generation system in commercial operating mode. 4. To develop an effective commercialization strategy to accelerate the TRJGTM technology penetration in the U.S. and international markets. 5. Through reports and conference presentations, disseminate information on the development of the TRJGTM technology. Project Structure The demonstration project will be conducted in four phases: Phase I. Project Definition (Budget Period I): This phase includes front end engineering design (FEED), environmental permitting activities, simulated syngas combustion tests, NEPA analysis, and the final project decision to proceed with the construction of the facility. Phase II. Detailed Design (Budget Period 2): This phase includes detailed design engineering and equipment procurement. The term of Phase II has been changed so that Phase II now runs concurrently with Phase III until both phases end with the Commercial Operation Date (COD). Detailed Design will be completed in the same time frame as estimated in the Proposal, but Phase II will continue throughout the construction period so that the engineering support of construction will be part of the design phase and all engineering costs will clearly be segregated from construction costs. Otherwise, the Project Management Plan remains unchanged. Phase Ill. Construction (Budget Period 2): This phase includes Gasification Island construction, installation, commissioning, startup, integration with the Combined Cycle Island, and continued engineering and environmental activities. Phase IV. Demonstration (Budget Period 3): This phase includes the commercial operation and maintenance of the TRJGTM demonstration plant with the execution of the test plan. The operating period for the demonstration plant is 48 months. Following demonstration, data analysis and process evaluations will be completed and final reports will be prepared to characterize the technical, environmental, and economic performance of the TRIG™ plant for power generation. Project Status and Accomplishments All the objectives for Budget Period I were achieved. The major areas of activity were implementing contracts with the major participants, environmental permitting, capacity need determination, simulated syngas combustion test and Front End Engineering Design. Use or d1sclosure of data on th1s sheet is sub;~t to the restnct1on on the t1tle page of this proposal 1-3 SoCo FOIA Response 000394 DE-FC26-06NT42391 Southern Company Services, Inc January 2007 1.0 Introduction (b) (4) Contracts The Cooperative Agreement with DOE and subcontracts with signed within schedule as a result of exceptional cooperation among all parties. have been Environmental The OGP Environmental Team began working on environmental activities in early 2005. The majority of the work activities were in the areas of support of the NEPA process and the Supplemental Site Certification Application preparation (SCA). The NEPA process has progressed to the point that the final EIS has been distributed to stakeholders and filed with the EPA. Only a final review period and the Record of Decision remain. The SCA process is complete and the necessary permits are in place for construction to begin. Site Certification Application The SCA provides the required information and analysis for agency review, including the Prevention of Significant Deterioration (PSD) permit as required by the Clean Air Act and delegated to the Florida Department of Environmental Protection (FDEP), leading to the approval and certification of the unit. Preparation of a SCA began in October 2005. Informational and technical meetings with stakeholders and parties to the application were conducted in December 2005, and January and February 2006. Other site certification milestones are shown below. SCA Milestones 02/17/06 OUC filed SCA with the FDEP 02/27/06 FDEP determines SCA is complete. 02/28/06 FDEP requests an Administrative Law Judge (ALJ) and furnishes list of those affected or other agencies entitled to notice. 02/28/06 ALJ appointed. 03/03/06 FDEP files SCA with the Division of Administrative Hearings (DOAH). 03/06/06 OUC issues SCA. FDEP files proposed schedule for review ofSCA. 03/10/06 FDEP to publish Notice of Application Filing. 03/14/06 Deadline for OUC to publish newspaper notice of filing SCA. 03/31/06 Agencies submit sufficiency questions to FDEP. 04/10/06 FDEP issues written determination on OUC SCA sufficiency. 04/13/06 Non-agency parties' deadline for Notice of Intent to be a party. 04/20/06 Affected agencies issue preliminary statements of issues. 05/18/06 Agency statements of nonprocedural requirements or other relief necessary for certification due. 05/22/06 Agencies submit reports to FDEP. 06/07/06 Deadline for FDEP to publish Notice of the Certification Hearing. 06/19/06 FDEP issues Staff Analysis. Deadline for Motions to Intervene. 07/17/06 Certification hearing before ALJ in Orange County. 08/18/06 ALJ issues Recommended Order. I 0/31/06 ALJ issues order relinquishing jurisdiction to FDEP to draft Final Order 12/08/06 FDEP issues Final Order granting Site Certification 12/22/06 FDEP issues final PSD permit Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 1-4 SoCo FOIA Response 000395 Snuthcm Cnmpany Services, Inc January 2007 DE·FC26-06NT4239l I 0 Introduction Need Determination Electrical power plants that are subject to the Florida Electrical Power Plant Siting Act (Siting Act) are required to obtain a need determination from the Florida Public Service Commission (PSC). In making its determination of need, the FPSC took into account the need for electric system reliability and integrity, the need for adequate electricity at a reasonable cost, and whether the proposed plant was the most cost-effective alternative available. The PSC also considered conservation methods taken or reasonably available to the applicant that might mitigate the need for the proposed plant. The need determination process is a justification of capacity additions. The PSC issued the final order approving the Petition for Need on May 31, 2006. The milestones for the Need Determination are shown below. Need Determination Milestones 02/22/06 Petition for Need Filed with PSC 02/22/06 Testimony and Exhibits filed with PSC 02/27/06 Notice of Commencement issued by PSC 03/24/06 Intervener testimony and exhibits due 03/31/06 PSC Staff testimony and exhibits due 04/07/06 Rebuttal testimony and exhibits due by all parties 04/24/06 PSC pre-hearing statements 05/05/06 PSC discovery deadline 05/08/06 PSC pre-hearing conference 05/22/06 Need Determination hearing 05/31/06 PSC issued the final order approving the Petition for Need Syngas Combustion Tests (b) (4) is scheduled to begin the simulated syngas combustion tests for the combustion turbine in February 2007. A validated combustion system will be delivered (b) (4)that is ready for commercial operation. The combustion system will be configured and optimized for the syngas that has been specified for the Transport Gasifier. (b) (4) successfully tested syngas having lower heating value than the design syngas for OGP at F-class conditions. Front End Engineering Design The major FEED activities have been successfully completed. The status of each FEED activity is shown below: • • • • • • • • • • • Process Design Basis and Description - Complete Battery Limit Conditions- Complete Process Flow Diagrams- Complete Heat & Material Balances- Complete Emission/Effluent Summaries- to be completed 1Q2007 P&IDs- Complete Relief Valve Summaries- Complete Index of Piping Material Classes- Complete Instrument Process Data Summary-To be completed I Q200 Piping Line List- Complete Equipment List- Complete Use or disclnsure of data nn this sheet is subject to the restrict inn on the title page of this proposal 1-5 SoCo FOIA Response 000396 Southern Company Services, Inc. January 2007 • • • • • • • • • • • • • • DE-FC26-!16NT42391 l 0 Introduction Equipment Sizing- Complete Equipment Datasheets- Complete Preliminary Plant Layout- Complete Preliminary 3D model- Complete Electrical Motor List- Complete Electrical Single Line Diagram- Complete Preliminary Utility Summary- Complete Chemical and Catalyst Summary -Complete Process Control Diagrams -Complete Mechanical and Thermal Design of the Gasifier -Complete Bid inquiries on Long-lead Equipment -Complete Desulfurization vendor selection -Complete Cost Estimate -Complete Hazop- To be completed I Q2007 (b) (4) The process design was reviewed by a group of IGCC experts from and DOE, and comments were addressed but no significant design changes were identified. In addition, an extensive Technical Risk Assessment of the technology was conducted by Southern Company with the conclusion that no significant technology weaknesses were identified and risk mitigation strategies as planned seem reasonable and appropriate. Integration of the combustion turbine with the combined cycle was completed (b) (4) and no concerns were identified. After completing FEED, the overall TRIG™ design was validated and no deficiencies were identified. Use or d1sclosurc of data on th1s sheet 1s subJect to the restnction on the IItle page ofth1s proposal 1-6 SoCo FOIA Response 000397 Southern Company Services, Inc January 2007 DE-FC26-06NT42391 2.0 Statement of Project Objectives 2.0 Statement of Project Objectives The overall scope of the Statement of Project Objectives from the Cooperative Agreement remains unchanged. The only change to the Statement of Project Objectives is an administrative change to move the engineering support of construction from Phase Ill to Phase II so that all engineering costs clearly will be segregated from construction costs. With this change Phase II will continue until the Commercial Operation Date. Use or disclosure of datil on this sheet is subject to the restriction on the title page of this proposal 2·1 SoCo FOIA Response 000398 Southern Company Services, Inc January 2007 DE-FC26-06NT42391 3.0 Management Plan 3.0 Management Plan The Management Plan will remain unchanged except for the administrative changes described under the Statement of Project Objectives section of this document, the updates to the cost & labor baselines that will result from the final negotiation of this continuation application, and the schedule changes that resulted from the detailed information developed during FEED. The revised schedule is attached. Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 3- 1 SoCo FOIA Response 000399 DE-FC26-06NT42391 3 0 Mnnag=cnt l'lan Southern Company ServiCes, Inc January 2007 21105 Ill 2DGI Ill ZGD7 Ill Ill - Ill 21101 Ill 21111 Ill 21L1t Ill 312 2tU 21113 111111 Ill Ill Ill 21111 Ill Jl 21111 21117 II Ill Ill II II (b) (4) _____ . s.rtom 01JAN)4 28NOV14 DltaDatt 01JANJ7 Run D~ 2SJAN07 12:14 nm~M~ra Sv-;lems Inc ~hDIIIe I EutyB1r Prov••S.r ftHJO (b) (4) Usc or uisclnsurc nf uJta nn thts sheer is subjt.:ct 111 rhc n:stnctmn on the rille P"b"' nf thiS pmpoS3I 7 I -ll (b) (4) SoCo FOIA Response 000428 Southern Company Ecru-ices. Inc. January, 200? A Use or disclosure of dam an. 111% Shut is. suhicct In the msmict'mn On rill: lirk mg: Of this proposal Suction - 505 Cost In?onnaticn SoCo FOIA Response 000429 SOUTHERN COMPANY SERVICES, INC. JANUARY 2007 Df·FC2&-0IINT42391 I!UOGETDEfAIL QIIINjQ() CIAU'ICA110H PftQJECT (b) (4) PEAIOO DETAUD~ PIWIE CIW'IIJ.CI7 (b) (4) Use or disdosure of dtla on this thnt is subjeoct to th~ rt51/tc:llon on l'le-11• page ol1his pt»pDHI (b) (4) 7.t ·13 SoCo FOIA Response 000430 SOU1l<£RN COMPANY SERVICES. INC. JANUARY 2007 OE-I'c~4230t BUDGET OETAL DAINIDOQAIIFICiillOfl PIIOJI!CT (b) (4) IKJDCIET PS!IOO 1WO ~eiHI7 OETM.EOIIESIGII PIWIE (b) (4) Use or disdosute or 11111 on this 1tMtet ts subjed to lhe restridion on Ule page o1this propos.~l (b) (4) "le SoCo FOIA Response 000431 SOUlliEAN COMPANY SERVICES, INC. JANUARY 2007 DE-FC2S-06NT42301 BUDGET OETAL -..v«PAH1 SEIMCES, IHC. DE~C28-0&NT42311 JANUARY 2007 BUDGET DETAL ORi.Nix)CiAiifiiiA'I'IOiii'IIQ.iecr (b) (4) BUDOE1' I'EIIioo TWO ~&Sl'oU!T.tlP- (b) (4) UM 01 diSCIDSun~ ot data on ltus &heel ts sUIIjed lo the NSirlaion on lhe 1,.11 page Df this PfOPOUJ (b) (4) 71·19 SoCo FOIA Response 000436 SOUTHERN COMPANY SERVICES, INC. JANUARY 2007 OIUNOO~TIOII PftO.e:T (b) (4) aiioaEr P!RIOO 1WO ~~START-UP~ (b) (4) lt$e or di:Sd0$n of dal' on thiS SftHI ~ stJbiiHi Co lhe ,_SU1Cii0n DE-FC28-86NT423!itl BUDGET DETAL -- (b) (4) on lhelide page ot chis proposal SoCo FOIA Response 000437 SOIITMERN COUPAH'f SERVICES, INC. JANUARY 2007 OE· FC2&-0IIHT'2391 BUDGET DETAil -- OAlNIOO HUMY 2007 CMNIIO GMIPICAliOH PROJI!CT (b) (4) 8UDCII!T PEIIIOD 1WO ~&lrf.Am.WO- (b) (4) ow Of disdosurl of dlla on ua (b) (4) sheet 0 sutjtc:llo tM ~.,._ Dn thl We page of this procx~sat 7.3 - 4 SoCo FOIA Response 000479 SCiliTliEIUt COWANY 5£MVICIES, INC JANUARY 20117 DE·FC2G-OIINT.231t BUDGET DETAIL ClRI..ANDO o.\IIIPICA110H PRQECT (b) (4) - IIUDOET PEIIIOO 'I'Ml (b) (4) a• Use Dl dddosute d81a on tbis sheet Is .ui:JiKl Ia the rntnalon on the title page ot lhG praposal (b) (4) 7.3-5 SoCo FOIA Response 000480 Southern Company Services, Inc. Escalaled dollars Budget Period 2 (b) (4) Account 1 Description Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ SUb contractS TotalS (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal ' Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote (b) (4) 7.3-6 SoCo FOIA Response 000481 Southern Company Services. Inc. Janua~2007 (b) (4) Account I Description Escalaled dolars Budget Period 2 Cost Basis' OE-FC26-06NT42391 Budget Detail Quantily UM Unit Cost LaborS Material$ Sub contract$ Total$ (b) (4) Use Of disclosure of data on this sheet is subject to the restriction on lhe title page or this proposal 'Cost Basis: EE- EngifiBering Estimate, BQ- Budget Quole, QU • Quole 7.3-7 (b) (4) SoCo FOIA Response 000482 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget DelaY Quantity UM Unit Cost LaborS Material$ Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.3-8 (b) (4) SoCo FOIA Response 000483 Southern CDmpany Services, Janua~2007 trn:. (b) (4) Account I Description Escalated dolars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost LaborS Material$ Sub contractS Total$ (b) (4) Use or disdosure or data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU - Quote 7.3-9 (b) (4) SoCo FOIA Response 000484 Southern Company Services, Inc. Escalated dollars BudgetPeriod 2 (b) (4) Account/Description Cost Basis• DE-FC26·06NT42391 Budget Detail Quantity UM Unit Cost Labor$ Material$ Sub contrad $ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ ·Budget Quote, QU • Quote 7.3·10 (b) (4) SoCo FOIA Response 000485 Southern Company Services, Inc. Jaouat2007 (b) (4) Account/Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ MaterialS Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ ·Budget Quote, QU · Quale 7.3. 11 (b) (4) SoCo FOIA Response 000486 Southern Company Services. Inc. Janua~2007 (b) (4) Account I Description Escalated dolars Budget Period 2 Cost Basis' DE·FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE - Engineering Estimate, BQ • Budget Quote, QU • Quote 7.3. 12 (b) (4) SoCo FOIA Response 000487 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis• DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost Labor$ MaterialS Sub contractS TotalS (b) (4) Use Of discloStR of data on this sheet is subjed to the restriction on the title page of ttis proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU - Quote 7.3-13 (b) (4) SoCo FOIA Response 000488 Southern Company Services, Inc. January 2007 Escalated dollars Budget Period 2 (b) (4) Cost Basis* Account / Description DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor $ Sub contract $ Material $ Total $ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE Engineering Estimate, BQ - - Budget Quote, QU 7.3- 14 - Quote (b) (4) SoCo FOIA Response 000489 Soulhem Company Services. Inc. January 2007 (b) (4) Account I Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• SUb Quanlily UM Unit Cost LaborS Material$ contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU - Quole 7.3 - 15 (b) (4) SoCo FOIA Response 000490 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM UnitCosl Labor$ Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheells subject to the restriction on the lille page of I his proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, OU- Quote 7.3-16 (b) (4) SoCo FOIA Response 000491 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Cost Basis" Account I Description I DE-FC26-06NT42391 Budget Detail Quanlity UM UniiCost LaborS Sub contractS MaterialS l TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ- Budget Quole, QU- Quote 7.3-17 (b) (4) SoCo FOIA Response 000492 Southem Company Services, Inc. DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis* Quantity UM Unit Cost LaborS Material$ Sub contract $ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ - Budget Quote, QU · Quote 7.3 -18 (b) (4) SoCo FOIA Response 000493 Southern Company Services. Inc. January 2007 (b) (4) Account f Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.3-19 (b) (4) SoCo FOIA Response 000494 Southern Company SeiVices, Inc. DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis' Quantity UM Unit Cost LaborS Material$ Sub contract$ Total $ (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal 'Cost Basis: EE • Engineering Estimate. BQ ·Budget Quote. QU · Quote 7.3-20 (b) (4) SoCo FOIA Response 000495 Southern Company Services, Inc. Janua~2007 (b) (4) Account I Description Escalaled dollars Budget Period 2 Cos I Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote, QU- Quote 7.3-21 (b) (4) SoCo FOIA Response 000496 Southern Company Services, Inc. Janua~ 2007 (b) (4) Account/Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unil Cost Labor$ Material $ Sub contract $ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.3-22 (b) (4) SoCo FOIA Response 000497 Southern Company Services, Inc. Janua~2007 (b) (4) Account/DescripUon Escalated dollars Budget Period 2 Cost Basis* DE-FC26-00NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering EsUmale, BQ • Budget Quote, QU - Quote 7.3 . 23 (b) (4) SoCo FOIA Response 000498 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ MaterialS Sub contractS TotalS (b) (4) Use or disclosU(e of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ - Budget Quote, QU - Quote 7.3-24 (b) (4) SoCo FOIA Response 000499 Southern Company Services, Inc. Janua62007 (b) (4) Account/ Descriplion Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantily UM UnitCosl LaborS Malerial S Sub conlract S Total$ (b) (4) Use or disclosure of data on !his sheet is subject to lhe restriction on the title page of this proposal • Cost Basis: EE- Engir.eering Estimate, BQ - Budget Quote, QU -Quote 7.3-25 (b) (4) SoCo FOIA Response 000500 Soulhem Company Services, Inc. DE-FC26-06NT42391 Budget Detail Escalated dollars BudgetPeriod 2 (b) (4) Account/Description Cost Basis* Quantity UM Unit Cost Labor$ Material $ Sub contract$ Total$ I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate. BQ - Budget Quote, QU - Quote 7.3-26 (b) (4) SoCo FOIA Response 000501 Southem Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Descfiplion Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS Material$ Sub contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU -Quote 7.3 - 27 (b) (4) SoCo FOIA Response 000502 Southern Company Services, Inc. January 2007 (b) (4) Account I Description DE-FC26-06NT42391 Budget Detal Escalated dolars Budget Period 2 Cost Basis" Quantity UM Unit Cost Labor$ Material S Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate. BO - Budget Quote, OU - Quote 7.3-28 (b) (4) SoCo FOIA Response 000503 Southern Company Services, Inc. January 2007 (b) (4) Account I DescripUon OE-FC26-06NT42391 Budget Detail Escalated dollars BudgetPeriod 2 Cost Basis• QuanUty UM Unit Cost Labor$ Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.3 - 29 (b) (4) SoCo FOIA Response 000504 Southern Company Services, Inc. (b) (4) Account I Description Escalated dolars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page or this proposal • Cost Basis: EE - Engineering Estimate, BQ • Budget Quote. QU • Quote 7.3. 30 (b) (4) SoCo FOIA Response 000505 Southern Co~any Services, Inc. (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26·06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS Total$ I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the tiUe page of this proposal • Cost Basis: EE • Engineering Estimate. BQ - Budget Quote, QU - Quote 7.3-31 (b) (4) SoCo FOIA Response 000506 Southern Company Services. Inc. (b) (4) Account/ Description Escalated dolars BudgetPeriod 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM UniiCost LaborS Material$ Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.3 - 32 (b) (4) SoCo FOIA Response 000507 Southern Company Services, Inc. Escalated dollars BudgeiPeriod 2 (b) (4) Account/Description Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contract$ Total$ j (b) (4) Use or disclosure of data on this sheet is subject to the restriclion on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU- Quote 7.3-33 (b) (4) SoCo FOIA Response 000508 Soulhem Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/ DescripUon Cost Basis" DE-FC26-06NT42391 Budget Detail Quanlily UM UniiCosl LaborS MaterialS Sub contractS TolaiS (b) (4) Use or disclosure of data on lhis sheet is subject to the restricUon on the Iitie page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU • Quole 7.3-34 (b) (4) SoCo FOIA Response 000509 Soulhem Company Services, Inc. January (b) (4) Account/DescripUon Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ Material$ Sub contract$ Total$ (b) (4) Use or disdosure of data on this sheet is subject to the restriction on the title page ol this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Ouole. QU- Quote 7.3. 35 (b) (4) SoCo FOIA Response 000510 SounERN CC»>PAH'f SERVICES, INC OE·FC26-0&NT.tZltl BUDGET DETAIL J.AHUAif.Y ;pool DRI.MIIO~liONPIIOJECT (b) (4) CONSniUCT10H & START-UP PIIAIE (b) (4) Use or dlsdosunt o1 dlla on lbis ~Met b subjed lo 1M reWid.an . . ,..,._011hiSpOpOsa1 (b) (4) 7.4 · 1 SoCo FOIA Response 000511 SOUTHERN COIIPAHY SERVICES. INC JANUARY 2007 ORI..AHDOGAIIFICo'.llOH I'IIOII!CT (b) (4) IIUDGI!T l"aaiiO 1WO CONSTliUCT10H & STARr.uP PHASE (b) (4) (b) (4) UH 01 dlsc:IIHute of dlla an lhis ihftt is IYtJied IO the restridiOn on lhe tJtie ~ ot this popoul 7~ 2 SoCo FOIA Response 000512 SOVTHERH COUPAHY SERVICES. INC JANUARY lOOT (b) (4) DE·FC28-0&NT..2llt BUDGETOETioll. OALN«3ny Services, Inc. Janual)' 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis· DE-FC26-o6NT42391 Budget Detail Sub Quantity UM Unit Cost Labor$ Materials contractS Total$ I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ • Budget Quale, QU - Qu 5-268 (b) (4) SoCo FOIA Response 000791 Southern Company Services, Inc. January 2007 (b) (4) Account I Descriplion Escalaled dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quanlily UM Unit Cosl LaborS MaterialS Sub contract$ TotalS : (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 'Cost Basis: EE- Engineering Estimate, BQ - Budget Quote, QU ·Qu 5-269 (b) (4) SoCo FOIA Response 000792 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalaled dollars Budget Period 2 CosI Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU -Qu 5-270 (b) (4) SoCo FOIA Response 000793 Southern Company Services, Inc. January 2007 (b) (4) Accouol/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material S Sub contract $ TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page or this proposal 'Cost Basis: EE- Engineering Estimate, BQ ·Budget Quote, QU ·Qu -------- 5-271 (b) (4) SoCo FOIA Response 000794 Southern Company Servioes, Inc. Januaj' 2007 Escalated dollars Budget Period 2 (b) (4) Cost Basis• Acco..-.t I Oesaiption DE-FC26·06NT42391 Budget Detail Quantity UM Un" Cost LaborS MaterialS SUb contractS Tolal s (b) (4) (b) (4) • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote, QU • Qu Use or disclosure or data on this sheet is subject to the restriction on the title page or this proposal -- --- 5· 272 - - - SoCo FOIA Response 000795 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Accounl/ Descliption Cost Basis· DE-FC26·06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Qu 5-273 (b) (4) SoCo FOIA Response 000796 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Dela~ Quantity UM Unit Cost labor$ Material$ Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on lhe Iitle page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-274 (b) (4) SoCo FOIA Response 000797 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dolars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Deta~ Quantity UM labor$ Unit Cost MaterialS Sub contractS TotalS (b) (4) I Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal * Cost Basis: EE - Engineering Estimate. BQ - Budget Quote, QU - Qu 5-275 (b) (4) SoCo FOIA Response 000798 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) DE-FC26-06NT42391 Budget Detail Cost Accounl/ Description Basis" Quantity UM Unit Cost laborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Qu 5-276 (b) (4) SoCo FOIA Response 000799 Southern Company Senrices, Inc. January 2007 Escalaled dollars Budget Period 2 (b) (4) Cost Basis" Account/ Description DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the mte page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu - ·- 5-277 - (b) (4) SoCo FOIA Response 000800 Southern Company Senlices, Inc. January 2007 (b) (4) Account/ Descriplion Escalaled dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail QuanUty UM Unit Cost LaborS MaterialS Sub contract$ Tolal S (b) (4) Use or disclosure of data on this sheet is subject lo lhe restriclion on lhe lille page of lhis proposal • Cost Basis: EE ·Engineering Eslimale, BQ- Budge! Quole, QU- Qu 5-278 (b) (4) SoCo FOIA Response 000801 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE -Engineering Estimate, BQ • Budget Quote, QU- Qu 5-279 (b) (4) SoCo FOIA Response 000802 Southern Company Services, Inc. (b) (4) Account/DescripUon Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT423911 Budget Delail Quantity UM UniiCost LaborS Materials Sub contract$ Total$ (b) (4) Use or disclosure of dala on this sheet is subject to the restliction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu -- 5-280 (b) (4) SoCo FOIA Response 000803 Southern Company Services, Inc. January 2007 (b) (4) Account/Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ Material$ Sub contract$ TotalS (b) (4) Use or disdostxe of data on this sheet Is subject to the restriction on the tille page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ - Budget Quote, QU- Qu 5-281 (b) (4) SoCo FOIA Response 000804 Southern Company Services, Inc. Janua'Y 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basts• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor S Material S Sub contract$ Total S (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE · Engineering Estimate. BQ. Budget Quote. au- Qu 5-282 (b) (4) SoCo FOIA Response 000805 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars BudgetPeriod 2 Cost Basis• DE-FC26-06NT42391 Budget Deta~ Sub Quantity UM Unit Cost laborS MaterialS contractS TotalS (b) (4) Use Of disclosure or data on this sheet is subject to the restriction on the title page of this proposal L...-. --- - - - • Cost Basis: EE- Engineering Estimate, BO - Budget Quote, QU -Qu 5-283 (b) (4) SoCo FOIA Response 000806 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description Escalated doftars Budget Period 2 Cost Basis· DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS contracts TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ - Budget Quote, QU • Q 5-284 (b) (4) SoCo FOIA Response 000807 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Sub Material$ contract$ Total$ (b) (4) Use or disdostKe of data on lhis sheet is subject to lhe reslriction on the lille page of this proposal (b) (4) • Cost Basis: EE- Engineering Estimate, BQ ·Budget Quote, QU ·Quo 5-285 SoCo FOIA Response 000808 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis" OE-FC26·06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS contract S Total S (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU- Qu 5-286 (b) (4) SoCo FOIA Response 000809 Southem Company SeiVices, Inc. January 2007 (b) (4) Account I Desaiption Escalated dollars Budget Period 2 Cost Basis• DE·FC26-06NT42391 Budget Detail QuanUty UM Sub Unit Cost Labor$ MaterialS conlract S Tolal $ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU ·Qu 5-287 (b) (4) SoCo FOIA Response 000810 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalaled dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost Labors MaterialS Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal (b) (4) • Cost Basis: EE ·Engineering Estimate, BQ • Budget Quote, QU ·Quo 5 - 288 SoCo FOIA Response 000811 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalaled dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quanlily UM Unit Cost Labor$ Material S Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote. QU- Qu 5-289 (b) (4) SoCo FOIA Response 000812 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 Cost Basis* Account I Description DE-FC26·06NT42391 Budget Detail Sub Quantity UM Unit Cost laborS I Material$ contractS Total S I I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the litre page of this proposal * Cost Basis: EE - Engineering Estimate. BQ - Budget Quote, QU - Qu 5-290 (b) (4) SoCo FOIA Response 000813 Soulhem Company Services, Inc. January 2007 (b) (4) Account/ Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis" Quantity UM Unit Cost LaborS Material$ Sub contractS Tolal$ (b) (4) Use or disclosure of data on lhls sheel is subject to the restriction on the lille page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ ·Budget Quote, QU ·Qu 5-291 (b) (4) SoCo FOIA Response 000814 Southern Company SefVices. Inc. JanuiiiY 2007 (b) (4) Escalated dollars DE-FC26-06NT42391 Budget Detail Budget Period 2 Account/ Descriplioo CosI Basis* Sub QuanUty UM Unit Cosl LaborS MaterialS contractS TotalS (b) (4) Use or disclosure of data oo this sheet is subjed lo the restricllon oo the Iitie page of this proposal • Cost Basis: EE- Engineering EsUmale, BQ- Budgel Quote, QU- Qu 5 - 292 (b) (4) SoCo FOIA Response 000815 Southern Company Services. Inc. January 2007 (b) (4) Account I Description Escalated dollars BudgetPeriod 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS Materials contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE ·Engineering Estimate. BQ • Budget Quote, OU • Qu 5-293 (b) (4) SoCo FOIA Response 000816 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dolars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Dela~ Quantity UM Unit Cost LaborS MaterialS Sub contract$ Total$ (b) (4) Use or disdosure of data on this sheet Is subject to the restriction on the tille page of this proposal 'Cost Basis: EE • Engineering Estimate, BQ- Budget Quote, QU- Qu 5-294 (b) (4) SoCo FOIA Response 000817 Southem Company Services, Inc. (b) (4) Account I Description DE-FC26-06NT42391 Budget Deta~ Escalated do•ars Budget Period 2 Cost Basis• Quantity UM Unit Cost Labor$ Material S Sub contractS TotalS --- (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BO • Budget Quote, QU- Qu 5-295 (b) (4) SoCo FOIA Response 000818 Southern Company Services. Inc. DE-FC2S-06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• Quantity UM Unit Cost LaborS MaterialS Sub COlllract $ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ- Budget Quote, QU ·Qu 5-296 (b) (4) SoCo FOIA Response 000819 Southern Company Services, Inc. (b) (4) Aci:OUfll/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Oetait Quantity UM Unit Cost LaborS Material$ SUb contrad $ Total S (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote, QU- Qu 5-297 (b) (4) SoCo FOIA Response 000820 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS contracts TotalS (b) (4) Use or disdosure of data on this sheet is subject to the restlictlon on the title page of this proposal ' Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5·298 (b) (4) SoCo FOIA Response 000821 Southern Company Services, Inc. January 2007 (b) (4) Accoool/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contractS Total S (b) (4) Use Of disclosure of data on this sheet is subjecllo the restriction on the title page otthls proposal • Cost Basis: EE -Engineering Estimate, BQ- Budget Quote, QU- Qu 5 - 299 (b) (4) SoCo FOIA Response 000822 Southern Company Services. Inc. Escalated dolars Budget Period 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Oeta~ Quantity UM Unit Cost LaborS Material$ Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote, QU- Qu 5-300 (b) (4) SoCo FOIA Response 000823 Southem Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE·FC26-06NT42391 Budget Detail SUb Quantity UM Unit Cost LaborS Malerial $ contract S TotalS (b) (4) Use or disclosure of dala on lhis sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimale, BQ • Budget Quote, QU - Qu 5 · 301 (b) (4) SoCo FOIA Response 000824 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis" DE·FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the tille page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ • Budget Quote, QU -Qu 5-302 (b) (4) SoCo FOIA Response 000825 Southem Company SeiVices, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• OE-FC26-06NT42391 Budget Detail Quantity UM Sub Unit Cost LaborS Material S contrad S TotalS (b) (4) Use or disclosure of data on this sheet is subjed to the restridion on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU- Qu 5-303 (b) (4) SoCo FOIA Response 000826 Southern Company Services, Inc. January 2007 (b) (4) Account/DescripUon Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS Total S (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE - Engineering Estimate, BQ- Budget Quote, QU- Qu 5-304 (b) (4) SoCo FOIA Response 000827 Southern Company Services. Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis' DE-FC2S-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page olthis proposal 'Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU ·Qu 5-305 -- (b) (4) SoCo FOIA Response 000828 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description DE-FC26-06NT42391 Budget Oela~ Escalated dollars Budget Period 2 Cost Basis" Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ ·Budget Quote, QU- Qu 5-306 (b) (4) SoCo FOIA Response 000829 Southern Company Services, Inc. Janua~2007 Escalaled dollars Budget Period 2 (b) (4) Cost Basis• Account/ Description DE-FC26-06NT42391 Budget Detail Quantity UM UnltCost LaborS MaterialS Sub contrad s Total$ I (b) (4) Use or disdosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Eslimate, BQ - Budget Quale, QU • Q - - -- -- 5· 307- - - (b) (4) SoCo FOIA Response 000830 Southern Company Services, Inc. DE·FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis' Quantity UM UnilCost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 'Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU ·Qu 5-308 (b) (4) SoCo FOIA Response 000831 Southern Company Services. Inc. Janual)' 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate. BQ- Budget Quote. QU ·Qu 5-309 (b) (4) SoCo FOIA Response 000832 SOUthern Company Services,-lnc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis* OE-FC2S-06NT42391 Budget Detail SUb Quantity UM Unit Cost LaborS MaterialS conlract S TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ • Budget Quote, QU · Qu 5 ·310 (b) (4) SoCo FOIA Response 000833 Southern Company Services, toe. January 2007 (b) (4) Account I Description Escalated dolars BudgetPeriod 2 Cost Basis• DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU - Qu 5-311 (b) (4) SoCo FOIA Response 000834 Southern Company Services, Inc. Janua~2007 (b) (4) Account I Description Escalated dolars BudgetPeriod 2 Cost Basis• DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost Labor$ MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU -Quo 5-312 (b) (4) SoCo FOIA Response 000835 Southern Company Services, Inc. January 2007 (b) (4) Account I Description DE-FC26-06NT42391 Budget Deta~ Escalated dolars Budget Period 2 Cost Basis• Quantity UM Unit Cost LaborS Material S Sub contracts TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate. BQ ·Budget Quote, QU ·Qu 5 . 313 (b) (4) SoCo FOIA Response 000836 Southem Company Services. Inc. Janual)' 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS Total$ I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal * Cost Basis: EE - Engineering Estimate. BQ - Budget Ouole. QU - Qu 5-314 (b) (4) SoCo FOIA Response 000837 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis' Sub Quantity UM Unit Cost LaborS MaterialS contracl $ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the tille page of this proposal • Cost Basis: EE • Engineering Estimate, BQ ·Budget Quote, QU ·Qu 5· 315 (b) (4) SoCo FOIA Response 000838 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description Escalated dolars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS Materials contractS TotalS I (b) (4) Use or disclosure of data on thls sheet is subject to the restriction on the title page of this proposal '--- • Cost Basis: EE • Engineering Estimate, BQ- Budget Quole, QU • Q 5-316 (b) (4) SoCo FOIA Response 000839 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE·FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub con&rad S TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page ot this proposal ...._. • Cost Basis: EE- Engineering Estimate, BQ - Budget Quote. QU -Qu 5-317 (b) (4) SoCo FOIA Response 000840 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalaled dollars Budget Period 2 Cost Basis• DE-FC26·06NT42391 Budget Detail Quanlily UM Unit Cost LaborS MaterialS Sub contrac1 $ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ - Budget Quote, QU - Qu 5. 318 (b) (4) SoCo FOIA Response 000841 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26·06NT42391 Budget DelaY Quantity UM Unit Cost LaborS Materials Sub contract$ Total$ (b) (4) Use or disctosure of data on this sheet is subject to lhe restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU - Qu 5 - 319 (b) (4) SoCo FOIA Response 000842 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Unit Cost Quantity UM Labors MaterialS Sub contractS Tolal S I (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page of this proposal (b) (4) • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quo 5-320 SoCo FOIA Response 000843 Southem Company Services. Inc. Janu:;'l2007 (b) (4) Escalated dollars Budget Period 2 DE-FC26-06NT42391! Budget Detail 1 Account/ Description Cost Basis" Quantity UM Unit Cost LaborS Materials Sub cootrad$ Total$ I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-321 (b) (4) SoCo FOIA Response 000844 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS cofllrad S TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restridion on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-322 (b) (4) SoCo FOIA Response 000845 Southern Company Services, Inc. JanuaJY 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost labor$ Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal 'Cost Basis: EE • Engineering Estimate, BQ ·Budget Quote, QU ·Qu 5·323 (b) (4) SoCo FOIA Response 000846 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dolars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Oela~ Quantity UM Unit Cost laborS Material S Sub contractS Total S I (b) (4) Use or disclosure of data on this sheet is subject to the restrictlon on the title page of this proposal • Cost Basis: EE • Engineering EsUmate, BQ • Budget Quote, QU • Qu 5 · 324 (b) (4) SoCo FOIA Response 000847 Southern Company Services. Inc. January 2007 (b) (4) Account I Description Escalated dollars Budgel Pefiod 2 Cost Basis' DE-FC26-06NT42391 Budgel Detail Quantity UM Unit Cost LaborS Matefial S Sub contractS TotalS (b) (4) Use or disclosure of data on lhls sheet Is subject to the restriction on the title page of this proposal 'Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Qu 5 - 325 (b) (4) SoCo FOIA Response 000848 Southern Company Services, Inc. January2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Oela~ Quantily UM UnilCosl Labor$ Material S Sub contract$ Tot al$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on lhe tille page of this proposal ' Cost Basis: EE - Engineering Estimate, BQ • Budget Quote, QU - Qu 5-326 (b) (4) SoCo FOIA Response 000849 Southem Company Setvices, Inc. January 2007 (b) (4) Accounl/ Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis* Quantity UM Unit Cost LaborS MaterialS Sub conlrad S Totals (b) (4) Use or disclosure of data on this sheet is subject to lhe reslriction on the tille page of this proposal (b) (4) • Cost Basis: EE. Engineering Estimate, BQ- Budget Quote, QU ·Quo 5-327 SoCo FOIA Response 000850 Southern Company-Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars BudgetPeriod 2 Cost Basis• OE-FC26-06NT42391 Budget DelaY Quantity UM Unit Cost laborS MaterialS Sub contractS TotalS (b) (4) Use or disctosure of data oo this sheet is subject to the restriction on the title page of this proposal (b) (4) • Cost Basis: EE • Engineering Estimate. BQ ·Budget Quote, OU- Qu 5-328 SoCo FOIA Response 000851 Southern Company Services. Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis' DE-FC26-06NT42391 Budget DelaY Sub Quantity UM Unit Cost Labors Material S contracts TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restrictioo on the title page of this proposal ' Cost Basis: EE ·Engineering Estimate, BQ - Budget Quote, OU • Qu 5-329 (b) (4) SoCo FOIA Response 000852 Southern Company Services. Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Desaiption Cost Basis* DE-FC26·06NT42391 Budget Detail Sub Quantity UM Unit Cost Material$ LaborS contractS Total S I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate. BQ - Budget Quote, QU - Qu 5 ·330 (b) (4) SoCo FOIA Response 000853 Southern Company Services, Inc. January 2007 (b) (4) Escalated doUars Budget Period 2 Cost Basis• Account I Description DE·FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Materials I I Sub contractS Totals I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE. Engineering Estimate, BQ- Budget Quote, QU- Q - 5-33.!_ (b) (4) SoCo FOIA Response 000854 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 DE-FC26-06NT42391 Budget Detail Cost Account I Description Basis· Quantity UM Unit Cost LaborS MaterialS Sub contrad S TotalS (b) (4) Use 01' disclosure of dala on this sheet is subJect to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU ·Qu 5-332 (b) (4) SoCo FOIA Response 000855 Southern Company Services, Inc. January 2007 (b) (4) Account/Description Escalated dollars BudgetPeriod 2 Cost Basis• DE-FC26-D6NT42391 Budget Detail Quantity UM Unit Cost laborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page or this proposal • Cost Basis: EE- Engineering Estimate, BQ - Budget Quote, QU- Qu 5-333 (b) (4) SoCo FOIA Response 000856 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 DE-FC26-06NT42391 Budget Detail Cost Account/Description Basis· Quantity UM Un" Cost Labor$ MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote. QU ·Qu 5-334 (b) (4) SoCo FOIA Response 000857 Southern Company Services. Inc. January 2007 (b) (4) Account I Descripllon Escalaled doMars BudgeiPeriod 2 Cost Basis" DE-FC26-06NT42391 Budget DetaM Quantity UM Unit Cost LaborS Materials Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the lille page of lhis proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Q 5-335 (b) (4) SoCo FOIA Response 000858 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26·06NT42391 Budget Detau Sub Quantity UM Unit Cost LaborS MaterialS contractS TotalS (b) (4) Use or disclosure of data on this sheet Is subject to lhe restriction on lhe title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote. QU- Q 5-336 (b) (4) SoCo FOIA Response 000859 Southern CDI1lpany Services, January 2007 toe. (b) (4) Account I Desctiplion Escalated dolars Budget Period 2 Cost Basis• DE·FC26-06NT42391 Budget DetaW Sub Quantity UM Unit Cost LaborS MaterialS contrad S Total$ I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ- Budget Quote, QU · Qu 5-337 - (b) (4) SoCo FOIA Response 000860 Southern Company Services, Inc. DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis" Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal (b) (4) • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-338 SoCo FOIA Response 000861 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 DE-FC26-06NT42391 Budget Detail Cost Account I Description Basis" Quantity UM Unit Cost LaborS MaterialS Sub contrad $ TotalS (b) (4) Use or disclosure of data on this sheet is subjed to lhe restriction on lhe title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU ·Qu 5-339 ---- (b) (4) SoCo FOIA Response 000862 Southern Company Services, Inc. January 2007 (b) (4) Account/Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contractS Tolal S (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Q 5-340 (b) (4) SoCo FOIA Response 000863 Southern Company Services. Inc. January 2007 (b) (4) Accoooll Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ Tolal S (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the lille page of this proposal ' Cost Basis: EE- Engineering Estimate, BQ • Budget Quote, QU- Qu 5-341 (b) (4) SoCo FOIA Response 000864 Southem Company SeiVices, Inc. January 2007 (b) (4) Account/ Description Escalated donars Budget Period 2 Cost Basis• OE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS SUb contract$ TotalS (b) (4) Use or disctostn! of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE. Engineering Estimale, BQ- Budget Quote, QU- Qu 5-342 (b) (4) SoCo FOIA Response 000865 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 DE-FC26-06NT42391 Budget Detail Cost Accounl/ Description Basis• Quantity UM Unit Cost laborS Material S Sub contract S TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU • Q 5-343 (b) (4) SoCo FOIA Response 000866 Southern Company Services. Inc. Janua~2007 (b) (4) Account I Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• Sub Quantity UM Unit Cost Labor S Material $ contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ -Budget Quote, OU -Qu 5-344 (b) (4) SoCo FOIA Response 000867 Southern Company Services. Inc. January 2007 (b) (4) Account I Description Escalated doftars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS Material S contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BO- Budget Quote, OU ·Qu 5-345 (b) (4) SoCo FOIA Response 000868 Southern Company Services, Inc. January 2007 (b) (4) Account I Descriplion Escalaled doUars Budget Period 2 CosI Basis· DE-FC26-06NT42391 Budget DetaU Quantily UM Unit Cosl LaborS Material$ Sub contract$ Tolal S (b) (4) Use Of disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ - Budget Quote, QU -Qu 5-346 (b) (4) SoCo FOIA Response 000869 Southern Company Services, Inc. January 2007 (b) (4) Account I Desaiption Escalated do•ars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet IS subject to the restriction on the title page of this proposal (b) (4) • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote, QU- Quo 5-347 SoCo FOIA Response 000870 Soulhem Company Services, Inc. January 2007 (b) (4) Account/ Description Escalaled dollars Budgel Peliod 2 Cost Basis" DE-FC26-06NT42391 Budgel Detail Quantity UM Unit Cost Labof$ Materials Sub contracts Tolal S t (b) (4) Use or disclosure of dala on this sheet is subject lo the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ - Budgel Quote, QU - Ou 5-348 (b) (4) SoCo FOIA Response 000871 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 DE-FC26-06NT42391 Budget Detail Cost Accooot I Description Basis" Sub Quantity UM Unit Cost LaborS MaterialS contractS TotalS (b) (4) Use « disclosure or data on this sheet is subject to the restriction on the title page or this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU • Q 5-349 (b) (4) SoCo FOIA Response 000872 Southern Company Services, Inc. Escalated dollars BudgetPeriod 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of dala on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Q 5-350 (b) (4) SoCo FOIA Response 000873 Southern Company Sei'Vices, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contracts TotalS (b) (4) Use « disclosure of data on thls sheet is subject to the restriction on the Iitie page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU • Qu 5-351 (b) (4) SoCo FOIA Response 000874 SOUthern Company Services, Inc. (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page or this proposal (b) (4) • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Quo S-3S2 SoCo FOIA Response 000875 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26·06NT42391 Budget Detail Quantity UM Sub Unit Cost LaborS MaterialS contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Qu 5-353 (b) (4) SoCo FOIA Response 000876 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 Cost Basis' Account/ Description DE-FC26-06NT42391 Budgel Detail Quantity UM Unit Cost LaborS MaterialS Sub contrad S Total$ I (b) (4) Use or disdosiJI! of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE. Engineering Estimate, BQ ·Budget Quote, QU ·Qu 5-354 (b) (4) SoCo FOIA Response 000877 Southem Company Services. Inc. Janual)l2007 (b) (4) Escalated dollars Budget Period 2 Cost Basis• Account/ Description DE·FC26·06NT42391 Budget Detail SUb Quantity UM Unit Cost LaborS MaterialS conlracl S Total S I (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ- Budget Quote, QU- Q 5-355 (b) (4) SoCo FOIA Response 000878 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ ·Budget Quote, QU- Qu 5-356 (b) (4) SoCo FOIA Response 000879 Southern Company Services, tnc. January 2007 (b) (4) Account/ Description Escalated dollars BudgetPeriod 2 Cost Basis' DE-FC26-06NT42391 Budget Deta~ Quantity UM LaborS Unit Cost MaterialS I I Sub contractS TotalS I (b) (4) Use or disdosUie or data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE • Engineering Estimate, BQ ·Budget Quote, QU ·Qu 5-357 (b) (4) SoCo FOIA Response 000880 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail SUb QuanUty UM Unit Cost LaborS MaterialS conlract S Total S - (b) (4) Use or disclosure of data on this sheet Is subject to the restrk:tlon on the Iitie page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote, QU- Qu 5-358 (b) (4) SoCo FOIA Response 000881 Southern Company Services, Inc. January 2007 Escalated dollars Budget Period 2 (b) (4) Cost Basis' Account/Oescripfion I DE-FC26-06NT42391 Budget Detail Quanfity UM Unit Cost LaborS Sub contractS MaterialS TotalS I I (b) (4) Use or disdosure of data on this sheet is subject to the restriction on the title page of this proposal - - - - - - • Cost Basis: EE • Engineering Estimate, BQ - Budget Quote, QU • Qu - - --- - - 5-359 - - (b) (4) SoCo FOIA Response 000882 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS contrad S Totals (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budge! Quote, QU- Qu 5-360 (b) (4) SoCo FOIA Response 000883 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) DE-FC26·06NT42391 Budget Detail Cost Account I Description Basis· Quantity UM Unit Cost LaborS Material S Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on I he title page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ • Budget Quote. QU • Qu 5-361 (b) (4) SoCo FOIA Response 000884 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS contractS Total S I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-362 (b) (4) SoCo FOIA Response 000885 SOOihem Company Services. Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS MaterialS Sub contractS TotalS (b) (4) Use or disdostxe of data on this sheet is subject to the restriction on the title page of this proposal 'Cost Basis: EE · Engineering Estimate, BQ- Budget Quote, QU- Qu 5-363 (b) (4) SoCo FOIA Response 000886 Southern Company Services, Inc. January 2007 (b) (4) Account/ DesCfiption Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budgel Detail Quanlily UM UniiCosl LaborS MaterialS Sub conlracl S Total$ I (b) (4) Use or disclosure of data on this sheet is subject to lhe restriction on the lille page of this proposal • Cost Basis: EE- Engineering Estimate, BQ -Budget Quote, QU -Qu 5-364 (b) (4) SoCo FOIA Response 000887 Southern Company Services. Inc. Januaj2007 (b) (4) Account/ Description Escalated doUars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM UniiCost laborS MaterialS contractS Total S (b) (4) Use or disclosure of data oolhis sheet Is subject to the restriction oo the tille page of this proposal - • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-365 (b) (4) SoCo FOIA Response 000888 Southern Company SefVices, Inc. January 2007 Escalated dollars Budget Period 2 (b) (4) Cost Basis' Account I Description DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS I (b) (4) Use or disclosure of data on this sheetts subject to the restriction on the title page of this proposal - -- - -- • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Qu - - - - 5-366 - - (b) (4) SoCo FOIA Response 000889 Southern Company Services, Inc. January 2007 (b) (4) Account I Description OE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis' Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) I Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal (b) (4) ' Cost Basis: EE • Engineering Estimate, BQ - Budget Ouole, QU • Ouo 5· 367 SoCo FOIA Response 000890 Southern Company Services, Inc. January 2007 (b) (4) Accoool/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Sob Quantity UM Unit Cost LaborS MaterialS contractS TotalS (b) (4) Use 01" disclosure of data on this sheet is subject to the restriction on the mte page of this proposal ' Cost Basis: EE- Engineering Estimate, BQ • Budget Quote, QU • Qu 5-368 (b) (4) SoCo FOIA Response 000891 Southern Company Services, Inc. January 2007 (b) (4) Account/Description Escalaled dollars Budget Period 2 Cost Basis• DE·FC26-06NT42391 Budget Detail Quanlity UM Unit Cost LaborS MaterialS Sub contrad $ TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ - Budget Quote, QU • Qu 5-369 (b) (4) SoCo FOIA Response 000892 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS Materials contracts TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ·Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU -Qu 5-370 (b) (4) SoCo FOIA Response 000893 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS Material$ contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate. BO- Budget Quote. OU- Qu 5-371 (b) (4) SoCo FOIA Response 000894 Southern Company Selvices, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of dala on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU • Qu 5-372 (b) (4) SoCo FOIA Response 000895 Southern Company Services. Inc. (b) (4) Escalated dDiars DE-FC26-06NT42391 Budget Delail Budget Period 2 Account/ Description Cost Basis• Quantity UM UniiCost LaborS MaterialS Sub contractS Tolal $ (b) (4) Use or disclosure of data on this sheet is subject to the restriclion on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-373 (b) (4) SoCo FOIA Response 000896 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• OE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contrad S TotalS (b) (4) Use 01' disclosure or dala on lhis sheel is subject lo I he reslridion on lhe tille page of lhis proposal (b) (4) • Cosl Basis: EE • Engineering Eslimale, BQ • Budget Quote. QU - Qu 5-374 SoCo FOIA Response 000897 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• Sub QoanUty UM Unit Cost LaborS Material$ contractS Total$ --- (b) (4) Use or disclosure or data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU • Oo 5-375 (b) (4) SoCo FOIA Response 000898 Southern Company Services, Inc. JanuiiiY 2007 (b) (4) Escalated dollars DE-FC26-06NT42391 Budget Deta~ Budget Period 2 Account I Description Cost Basis" Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-376 (b) (4) SoCo FOIA Response 000899 Southern Company Services, Inc. January 2007 Escalated dollars Budget Period 2 (b) (4) Cost Basis• Account I Description OE-FC26-06NT423911 Budget Detail I Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ- Budget Quote, QU- Qu - - - - - 5-377 - - (b) (4) SoCo FOIA Response 000900 Southern Company Services. Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE·FC26-06NT42391 Budget Detail QuanUty UM Unit Cost LaborS Material$ Sub contracts TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, 00 - Budget Quote, QU - Qu 5-378 (b) (4) SoCo FOIA Response 000901 Southern Company SeiVices, Inc. Janu~2007 (b) (4) Escalated dollars Budget Period 2 DE·FC26-06NT42391 Budget Detail Cost Basis" Account I Description Quantity UM Unit Cost Labor$ Material$ Sub contractS Totals (b) (4) I Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal I • Cost Basis: EE ·Engineering Estimate, BQ • Budget Quote, QU . Qu 5-379 (b) (4) SoCo FOIA Response 000902 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 Cost Basis• Account I Description DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS MaterialS Sub contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ ·Budget Quote, QU -Qu 5-380 (b) (4) SoCo FOIA Response 000903 Southern Company Services, Inc. January 2007 (b) (4) Escalated dolars Budget Period 2 Cost Basts• Account/OescripUon OE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disdoslKe of data on this sheet is subject to the restriction on the title page this proposal or • Cost Basis: EE ·Engineering Estimate, BQ • Budget Quote, QU- Qu 5-381 (b) (4) SoCo FOIA Response 000904 Southern Company Services, Inc. January 2007 (b) (4) Account I Oescriplion Escalated dollars Budget Period 2 Cost Basis· DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Materials Sub contrad S Totals (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal - - --- • Cost Basis: EE- Engineering Estimate, BQ -Budget Quote, QU -Qu 5-382 (b) (4) SoCo FOIA Response 000905 Southern Company Services, Inc. January 2007 (b) (4) Account I Oesaiplion Escalated dollars Budget Period 2 Cost Basis· DE-FC26-06NT42391 Budget Detail SUb Quanlily UM Unit Cost LaborS MaterialS contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restricllon on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ • Budget Ouote. QU • Qu 5. 383 (b) (4) SoCo FOIA Response 000906 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• OE-FC26-06NT42391 Budget Dela~ Quantity UM Unit Cost LaborS MaterialS Sub conlrad S TotalS (b) (4) Use Of disclosure of data on this sheet is subject to the restriction on the Iitle page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote. QU - Quo 5-384 (b) (4) SoCo FOIA Response 000907 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dolars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal "Cost Basis: EE ·Engineering Estimate. BO ·Budget Quote. OU - Qu 5-385 (b) (4) SoCo FOIA Response 000908 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• Quantity UM UniiCost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Qu 5 -3S6 (b) (4) SoCo FOIA Response 000909 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated donars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unil Cost Labors MaterialS contractS TotalS I (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate. BQ ·Budget Quote, QU ·Qu 5-387 (b) (4) SoCo FOIA Response 000910 SotJ\hem Company Services, Inc. January 2007 (b) (4) Account I Description Escalated doUars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budgel Delail Quantity UM Sub Unil Cost LaborS Material$ contractS TotalS (b) (4) Use or disclosure of data on lhis sheet is subject to ' Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu the restriction on the lille page of this proposal 5 - 388 (b) (4) SoCo FOIA Response 000911 Southern Company Services, Inc. Escalated dollars BudgetPeriod 2 Janua~2007 (b) (4) Account/ Description Cost Basis• DE·FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS Totals (b) (4) Use or disclosure of data on this sheet is subject to lhe restriction on the title page of this proposal - - - - - - • Cost Basis: EE · Engineering Estimate, BQ • Budget Quote, QU • Qu 5·389 (b) (4) SoCo FOIA Response 000912 Southern Company SeiVices, Inc. January 2007 (b) (4) Account/ Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis" Sub Quantity UM Unit Cost Labor S Material$ conlract S Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ- Budget Quote, QU • Q 5-390 (b) (4) SoCo FOIA Response 000913 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 Cost Basis" Account/Description DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contracts TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote. QU- Q 5-391 - - - - - - - - (b) (4) SoCo FOIA Response 000914 Southern Company Services, Inc. Janu~2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS i TotalS I I (b) (4) Use « disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE • Engineering Estimate, BQ - Budget Quote, QU - Qu 5-392 (b) (4) SoCo FOIA Response 000915 Southern Company Services, Inc. January 2007 (b) (4) Account I Description DE-FC26·06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis" Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subjeclto the restriction on the title page of this proposal (b) (4) • Cost Basis: EE • Engineering Estimate, 8Q • Budget Quote, QU - Qu 5-393 SoCo FOIA Response 000916 Southern Company Services. Inc. Janua~ (b) (4) Account I Description Escalated dolars BudgetPeriod 2 Cost Basis• DE·FC26-06NT42391 Budget Detail QuanUty UM Unit Cost LaborS MaterialS Sub conlrad S Tolal S I (b) (4) Use or disclosure of data on this sheet is subject to the restridion oothe lille page of this proposal (b) (4) • Cost Basis: EE • Engineering Estimate, BQ- Budget Quote, QU- Quo 5-394 - - SoCo FOIA Response 000917 Southern Company Services, Inc. January 2007 (b) (4) Account I Desaiption DE-FC2S..06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote. QU - Quo 5-395 (b) (4) SoCo FOIA Response 000918 Southern Company Senrices. Inc. January 2007 (b) (4) Escalaled dollars Budget Period 2 Cost Basis' Account/Description DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE- Engineering Estimate. BQ · Budget Quote, QU - Qu 5 - 396 (b) (4) SoCo FOIA Response 000919 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description DE-FC26-06NT42391 Budget Deta~ Escalaled dollars Budget Period 2 Cost Basis• Sub Quantity UM Unit Cost LaborS Materials contractS Total S (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the Iitle page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-397 (b) (4) SoCo FOIA Response 000920 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ • Budget Quote, QU • Q 5-398 (b) (4) SoCo FOIA Response 000921 Southern Company Services, Inc. DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• Quantity UM Unit Cost LaborS MaterialS Sub contract$ TotalS I (b) (4) Use or disdosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, OU • Qu 5-399 (b) (4) SoCo FOIA Response 000922 Southern Company Services, Inc. January 2007 (b) (4) Account/Description Escalated dollars BudgetPeriod 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS MaterialS SUb contractS Total S (b) (4) I Use or disclosure of dala on this sheet is subject to the restriction on lhe title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote, QU • Qu 5-400 (b) (4) SoCo FOIA Response 000923 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget DelaM Quantity UM Unit Cost laborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restricllon on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budgel Quote. QU- Qu 5-401 (b) (4) SoCo FOIA Response 000924 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote. QU - Qu 5-402 (b) (4) SoCo FOIA Response 000925 Southern Company SeiVices. Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 Cost Basis. Account/Description DE-FC26-06NT42391 Budget Dela~ Quantity UM UnliCosl LaborS Sub contractS MaterialS TotalS I (b) (4) I Use or disclosure of data on this sheet is subject to the reslriclioo on the title page of this proposal I I • Cost Basis: EE- Engineering Estimate, BQ -Budget Quote. QU -Qu 5-403 (b) (4) SoCo FOIA Response 000926 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 Cost Basis• Account f Description DE-FC26-06NT42391 Budget Detail Quantity UM Sub Unit Cost LaborS MaterialS contract$ TotalS I (b) (4) Use or disclosure or data on this sheet is subject to the restriction on lhe title page this proposal or • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Qu 5-404 (b) (4) SoCo FOIA Response 000927 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT4239t Budget Detail Quanlily UM Unit Cost LaborS MaterialS SUb contract$ Total $ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU ·Quo 5-405 (b) (4) SoCo FOIA Response 000928 Southern Company Services, Inc. January 2007 (b) (4) Account I Description DE-FC26-06NT42391 Budget Dela~ Escalated dollars BudgetPeriod 2 Cost Basis• Quantity UM UniiCost laborS MaterialS Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Qu 5-406 (b) (4) SoCo FOIA Response 000929 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26·06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS Total$ (b) (4) t Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, au- Qu 5-407 (b) (4) SoCo FOIA Response 000930 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost laborS Material$ contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the !Hie page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-408 (b) (4) SoCo FOIA Response 000931 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Material$ LaborS , Sub contract$ I TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-409 (b) (4) SoCo FOIA Response 000932 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Oeta~ Quantity UM Unll Cost LaborS MaterialS Sub contrad S Totals (b) (4) Use or disclosure of data on this sheet is subjed to the restriction on the title page of this proposal (b) (4) • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU • Qu 5-410 SoCo FOIA Response 000933 Southern Company Services. Inc. Januad2007 (b) (4) Accounll Description Escalated doMars BudgeiPerlod 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantily UM Unit Cost laborS MaterialS Sub contractS Total S (b) (4) Use or disdosure of data on lhls sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU • Qu 5-411 (b) (4) SoCo FOIA Response 000934 Southem Company Services. Inc. January 2007 (b) (4) Account I Description OE-FC26-06NT42391 Budget OetaV Escalated doHars BudgetPeriod 2 Cost Basis• Quantity UM Unit Cost LaborS Material S Sub contractS TotalS I I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal .....____ - - - - • Cost Basis: EE- Engineering Estimate, BQ ·Budget Quote, QU ·Qu 5-412 - - - - (b) (4) SoCo FOIA Response 000935 Southern Company Services. Inc. (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail QuanUty UM Unit Cost LaborS MaterialS SUb contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this praposal • Cost Basis: EE • Engineering Estimate, BQ ·Budget Quote, QU ·Qu 5-413 (b) (4) SoCo FOIA Response 000936 Southern Company Services, Inc. January 2007 (b) (4) Account/DescnpUon Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost labor$ Sub MaterialS contradS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the mte page of this proposal • Cost Basis: EE • Engineering Estimate, BQ- Budget Quote, QU- Qu s -414 (b) (4) SoCo FOIA Response 000937 Soolhem Company Services. Inc. January 2007 (b) (4) Account/Description Escalated dollars DE-FC26-06NT42391 Budget Oeta~ Budget Period 2 Cost Basis' Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page or this proposal • Cost Basis: EE • Engineering Estimate, BQ- Budget Quote, QU • Qu 5-415 (b) (4) SoCo FOIA Response 000938 Sou1hem Company Services, Inc. (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quanlily UM Unit Cost LaborS Material$ Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BO • Budget Quote, OU - Q 5-416 (b) (4) SoCo FOIA Response 000939 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail auanUty UM Unit Cost LaborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restricUon on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ - Budget Quote, QU - Q 5-417 (b) (4) SoCo FOIA Response 000940 Southern Company Services. Inc. January 2007 (b) (4) Escalated dolars DE-FC26-06NT42391 Budgel Detail Budget Period 2 Cost Account/ Description Basis• Quantity UM Unit Cost LaborS MaterialS Sub contracts TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ • Budget Quote. QU • Qu 5·418 (b) (4) SoCo FOIA Response 000941 Soulhem Company Services, Inc. January 2007 (b) (4) Account I Description Escalaled dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page of this proposal * Cost Basis: EE ·Engineering Estimate, BQ • Budget Quote, QU • Qu 5-419 (b) (4) SoCo FOIA Response 000942 Soulhem Company Services, Inc. January 2007 (b) (4) Account I Descriplion DE-FC26-06NT42391 Budget Oeta~ Escalated dollars Budgel Period 2 Cost Basis• Quantity UM Unit Cost LaborS Materials SUb conlradS TotalS (b) (4) Use or disclosiMl! of data on this sheel is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimale. BQ - Budget Quote. QU • Q 5-420 (b) (4) SoCo FOIA Response 000943 Southern Company Services, Inc. January 2007 (b) (4) Account/Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis* Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU -Q 5-421 (b) (4) SoCo FOIA Response 000944 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description DE·FC26-06NT42391 Budget Deta~ Escalated dollars Budget Period 2 Cost Basis' Quantity UM Unit Cost LaborS Material$ Sub contractS TotalS (b) (4) Use or disclosUI'e of data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ ·Budget Quote, QU- Q 5-422 (b) (4) SoCo FOIA Response 000945 Southern Company Services, Inc. Escalated doMars Budget Period 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS contracts TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate. BQ • Budget Quote. QU • Qu 5-423 (b) (4) SoCo FOIA Response 000946 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contrad $ Total$ (b) (4) Use or disclosure or data on this sheet is subject to the restridion on the lille page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU • Qu 5-424 (b) (4) SoCo FOIA Response 000947 Southern Company Senrices, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this PfOposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU • Qu 5-425 (b) (4) SoCo FOIA Response 000948 Southern Company Services. Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 Cost Basis' Account/ Description DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Sub contractS MaterialS TotalS I I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-426 (b) (4) SoCo FOIA Response 000949 Southern Company Services, Inc. January 2007 (b) (4) Escalated dollars Budget Period 2 DE-FC26-06NT42391 Budget Detail Cost Account I Description Basis' Quantity UM Unil Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE- Engineering Estimate, BQ - Budget Quote, QU- Q 5-427 (b) (4) SoCo FOIA Response 000950 Southern Company SeiVices, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM UnitCosl LaborS MaterialS I Sub contractS I TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Q 5-428 (b) (4) SoCo FOIA Response 000951 Southern Company Services, Inc. (b) (4) Escalated dollars Budget Period 2 DE-FC26-06NT42391 Budget Detail Cost Account/ Description Basis• Quantity UM Unit Cost LaborS Materials Sub contracts TotalS (b) (4) Use or disdosure of data on this sheet Js subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Qu 5-429 (b) (4) SoCo FOIA Response 000952 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM UniiCost LaborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 'Cost Basis: EE- Engineering Estimate. 80- Budget Quote, QU- Qu 5 - 430 (b) (4) SoCo FOIA Response 000953 Soulhem Company Services, Inc. Januaj' 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate. BQ- Budget Quole, QU- Q 5-431 (b) (4) SoCo FOIA Response 000954 Southern Company SeiVices, Inc. Escalated dollars Budget Period 2 (b) (4) DE-FC26-06NT42391 Budget Detail Cost Basis• Accooot I Description Quantity UM Unit Cost LaborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ - Budget Quote, QU- Qu 5-432 (b) (4) SoCo FOIA Response 000955 Soulhem Company Services, Inc. Escalated dollars BudgeiPeriod 2 (b) (4) DE-FC26-06NT42391 Budgel DelaY CosI Basis" Accouni/Description Quantity UM Urjt Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on lhis sheet is subject Ia the restrk:tion on the lille page of this proposal • Cost Basis: EE - Engineering Estimate, BQ- Budget Quote, QU ·Quale 5-433 (b) (4) SoCo FOIA Response 000956 Southern Company Services, Inc. (b) (4) ACCOIMll/ Description Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Dela~ Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on lhe title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Q 5-434 (b) (4) SoCo FOIA Response 000957 Southern Company Selvices, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contracts Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ • Budget Q 5-435 (b) (4) SoCo FOIA Response 000958 Southern Company Se111ices. Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Materials Sub contractS TotalS (b) (4) Use or disclosure of data oo this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ • Budget Qu 5-436 (b) (4) SoCo FOIA Response 000959 Southern Company Services. Inc. (b) (4) Account/ Description Escalated donars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of \hiS proposal • Cost Basis: EE- Engineering Estimate. BQ- Budget Qu 5-437 (b) (4) SoCo FOIA Response 000960 Southern Company Services, Inc. (b) (4) Account I Description Escalated doUars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ Material S SUb contractS Totals (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate. BQ • Budget Q 5-438 (b) (4) SoCo FOIA Response 000961 Southern Company Services, Inc. (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ • Budget Q 5 - 439 (b) (4) SoCo FOIA Response 000962 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Descliption Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM labor$ Unit Cost MaterialS Sub contractS Total S I (b) (4) I I Use or disclosure of data on this sheel is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ - Budget Q I I (b) (4) 5 - 440 SoCo FOIA Response 000963 Southern Company Services, Inc. (b) (4) Account I Desaiplion Escalated dollars Budget Period 2 Cost Basis• DE·FC26·08NT42391 Budget Detail Ouanli1y UM Unit Cost LaborS MaterialS SUb conlrad $ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ- Budget Qu 5-441 (b) (4) SoCo FOIA Response 000964 Southern Company Services, Inc. (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail QuanUty UM Unit Cost LaborS MaterialS SUb contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ- Budget Qu 5 ·442 (b) (4) SoCo FOIA Response 000965 Southern Company Services, Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub cootradS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basts: EE- Engineering Estimate, BQ ·Budget Q (b) (4) 5-443 SoCo FOIA Response 000966 Southem Company SeiVices, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis" DE-FC26·06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Qu 5-444 (b) (4) SoCo FOIA Response 000967 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis" DE-FC26-06NT42391 Budget Del.a~ Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet Is subfect to the restriction on the tille page of I hiS proposal (b) (4) • Cost Basis EE Engineering Estimate, BQ- Budget Q 5-44 SoCo FOIA Response 000968 Southern Company Services, Inc. January 2007 (b) (4) Account/Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• Sub Quantity UM Unit Cost LaborS MaterialS conlract S Total$ (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budgel Q 5-446 (b) (4) SoCo FOIA Response 000969 Soulhem Company Services. Inc. (b) (4) Account I Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• Quantity UM Unit Cost LaborS MaterialS Sub contrad $ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restridion on the title page of this proposal • Cost Basis: EE- Engineering Estimate. BQ- Budget Q 5-447 (b) (4) SoCo FOIA Response 000970 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE·fC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ Tolal $ (b) (4) Use or disclosure of data on this sheet is subject to • Cost Basis: EE- Engineering Estimate, 80 · Budget Q the restriction on the title page of this proposal 5-448 (b) (4) SoCo FOIA Response 000971 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis' DE-FC26-06NT42391 Budget Deta~ Quantity UM UniiCost laborS MaterialS Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject lo the restriction on the title page of this proposal 'Cost Basis: EE- Engineering Estimate, BQ- Budget Q (b) (4) 5-449 SoCo FOIA Response 000972 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS MaterialS Sub contract$ Total$ , (b) (4) I Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Qu 5-450 (b) (4) SoCo FOIA Response 000973 Southern Company Services. Inc. (b) (4) Account/ Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• Quantity UM Unit Cost labor$ MaterialS Sub contract$ Total $ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Q 5 - 451 (b) (4) SoCo FOIA Response 000974 Southern Company Services, Inc. (b) (4) DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis• Account I Description Quantity UM Unit Cost LaborS MaterialS SUb contrad S TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restridion on the title page of this proposal (b) (4) • Cost Basis: EE - Engineering Estimate, BQ - Budget Qu 5 - 452 SoCo FOIA Response 000975 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Accooot I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Q 5-453 (b) (4) SoCo FOIA Response 000976 Southern Company Services. Inc. (b) (4) Account I Descliption DE-FC26-06NT42391 Budget Deta~ Escalated dollars Budget Period 2 Cost Basis• Quantity UM Unit Cost LaborS Materials Sub contrad S TotalS I (b) (4) I Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engmeering Estimate, BQ- Budget Q 5-454 (b) (4) SoCo FOIA Response 000977 Southern Company Selvices, Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labors MaterialS Sub contractS Tolal S (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis. EE - Engineering Estimate, BQ - Budget Q 5-455 (b) (4) SoCo FOIA Response 000978 Southern Company Services. Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unil Cost LaborS MaterialS contracts TotalS (b) (4) Use or disclosure of data on this sheet is subjectlo the restriction on the title page of this proposal • Cosl Basis: EE - Engineering Estimate, BQ • Budget Q 5-456 (b) (4) SoCo FOIA Response 000979 Southern Company SeiVices, Inc. Janua~2007 (b) (4) Account/Descrip~on Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Q 5-457 (b) (4) SoCo FOIA Response 000980 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/Description Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS MaterialS conlrad S TotalS (b) (4) Use or disclosure of dala on this sheel is subject to the restriclion on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quo 5-458 (b) (4) SoCo FOIA Response 000981 Southern Company SefVices, Inc. January 2007 (b) (4) Accouni/DescripUon Escalated dollars Budget Period 2 Cost Basis* DE·FC26·06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS SUb contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject lo the restriction on the title page of this proposal (b) (4) • Cost Basis: EE ·Engineering Estimate, BQ ·Budget Qu 5 ·459 SoCo FOIA Response 000982 Southern Company Services, Inc. January 2007 (b) (4) Account/Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ- Budg 5- (b) (4) SoCo FOIA Response 000983 Southern Company Services, Inc. Janu~2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-D6NT42391 Budget Detail SUb Quantity UM Unit Cost Material$ LaborS contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ- Budget Qu 5-461 (b) (4) SoCo FOIA Response 000984 Southern Company Services, Inc. (b) (4) Escalated doftars Budget Period 2 Cost Basis• Accouot I Description DE-FC26-06NT42391 Budget Detail QuanUty UM Unit Cost LaborS Material$ SUb contract$ Total$ I (b) (4) I I Use or disclosure of data on this sheet is subject to the restriction on the title page of this Pfoposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Qu 5-462 I (b) (4) SoCo FOIA Response 000985 Southern Company Services, Inc. Escalated dolars BudgetPeriod 2 (b) (4) Account I Oescriplion Cost Basis" DE·FC26·06NT42391 Budget Detail Quanlity UM Unit Cost laborS Material$ Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject lo the restriction on the title page of this proposal (b) (4) • Cost Basis: EE- Engineering Estimate, BQ • Budget Qu 5-463 SoCo FOIA Response 000986 Southern Company Services. Inc. Escalated dolars Budget Period 2 (b) (4) Account/ Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS Material$ Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ • Budget Qu 5-464 (b) (4) SoCo FOIA Response 000987 Soulhem Company Services, Inc. (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Materials Sub contracts Tolal S (b) (4) I Use or disclosure of data on this sheet is subject to the restriction on the tille page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Qu 5-465 (b) (4) SoCo FOIA Response 000988 Southern Company Services. Inc. (b) (4) Account I Description Escalaled doHars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Delail Quantity UM Unit Cost LaborS MaterialS Sub contractS Tolal S (b) (4) Use « disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE ·Engineering Estimate, BQ - Budget Qu 5-466 (b) (4) SoCo FOIA Response 000989 Southern Company Services, Inc. (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail OuanUty UM SUb Unit Cost LaborS MaterialS conlract $ TotalS (b) (4) Use Of" disclosure of data on this sheet is subject to the restriclion on the title page of this proposal • Cost Basis: EE - Engineering Estimate. BQ - Budget Qu 5 - 467 (b) (4) SoCo FOIA Response 000990 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26..Q6NT42391 Budget Detail Quantity UM Unit Cost Labor$ MaterialS Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Qu 5-468 (b) (4) SoCo FOIA Response 000991 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Descriplion Cost Basis• DE-FC26-06NT42391 Budget Deta~ Quantity UM Unit Cost Labor$ MaterialS Sub contractS TotalS ! (b) (4) Use or disdostn of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Q 5-469 (b) (4) SoCo FOIA Response 000992 Southern Company Services, Inc. (b) (4) Account I Description Escalated dolars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Q 5-470 (b) (4) SoCo FOIA Response 000993 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Accouni/DescripUon Cost Basis• DE·FC26-06NT42391 Budget Detail Sub Quantity UM Unil Cost LaborS Material$ conlract $ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate. 80 · Budget Q 5-471 (b) (4) SoCo FOIA Response 000994 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) A£count/DescripUon Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ - Budget Qu 5-472 (b) (4) SoCo FOIA Response 000995 Southern Company SeiVices, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost labor$ MaterialS Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the Iitie page of this proposal • Cost Basis: EE ·Engineering Estimate, BQ • Budget Q 5-473 (b) (4) SoCo FOIA Response 000996 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Q 5 - 47 (b) (4) SoCo FOIA Response 000997 Southern Company Services. Inc. January 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contrad S Total$ (b) (4) Use or disclosure of data on thls sheet is subject to the restriction on the title page ol this proposal • Cost Basis: EE- Engineering Estimate, BQ - Budget Qu 5-475 (b) (4) SoCo FOIA Response 000998 Southern Company Services, Inc. (b) (4) Account/OescripUon DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis· Sub Quantity UM Unit Cost LaborS MaterialS conlract $ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Q 5-476 (b) (4) SoCo FOIA Response 000999 Southern Company Services, Inc. DE-FC26-06NT42391 Budget Detail Escalaled dolars Budget Period 2 (b) (4) Account/ Desctiption Cost Basis" SUb Quantity UM Unit Cost LaborS Material$ contractS TotalS (b) (4) I Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Qu 5 - 477 (b) (4) SoCo FOIA Response 001000 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Sub Quantity UM Unit Cost LaborS Material$ contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ- Budget Q 5-478 (b) (4) SoCo FOIA Response 001001 DE·FC26·06NT42391 BUDGET DETAIL SOUTHERN COMPANY SERVICES, INC JANUARY 2007 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 7.5 . 479 (b) (4) SoCo FOIA Response 001002 DE-FC26-06NT42391 BUDGET DETAIL SOUTHERN COMPANY SERVICES, INC JANUARY 2007 (b) (4) Use or d isclosure of data on tills sheel is subjec:l to the resttic:lion on \he tiUe page of this proposal 7.2 . 480 (b) (4) SoCo FOIA Response 001003 SOUTHERN COMPANY SERVICES. INC JANUARY 2007 OE·FC26-06NT42391 BUOOET DETAIL (b) (4) Use Of cbdolure ol data on thk ...... is autJitd kl 1M t.aridlon onlte.U.~otthhpropot.al (b) (4) SoCo FOIA Response 001004 DE·FC26·06NT42391 BUDGET DETAIL SOUTHERN COMPANY SERVICES. INC JANUARY 2007 (b) (4) Use or disdosure of data on th1s sheet is subject to the restriction on the bde page of this proposal 7 2. 482 (b) (4) SoCo FOIA Response 001005 SOUTHERN COMPANY SERVICES INC JANUARY 2007 DE·FC26-06NT42391 BUDGET DETAIL (b) (4) Use or dtsdosure ol data on th1s sheet 1s subject to the restnction on the liUe page ol this proposal 12 . 483 (b) (4) SoCo FOIA Response 001006 SOUTHERN COMPANY SERVICES, INC JANUARY 2007 DE-FC26-06NT42391 BUDGET DETAIL (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 7.2-484 (b) (4) SoCo FOIA Response 001007 SOUTHERN COMPANY SERVICES, INC JANUARY 2007 DE-FC26-06NT42391 BUDGET DETAIL (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 7.2-485 (b) (4) SoCo FOIA Response 001008 SOUTHERN COMPANY SERVICES, INC JANUARY 2007 DE-FC26-06NT42391 BUDGET DETAIL (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 7.2 - 486 (b) (4) SoCo FOIA Response 001009 SOUTHERN COMPANY SERVICES, INC JANUARY 2007 DE-FC26-06NT42391 BUDGET DETAIL (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 7.2-487 (b) (4) SoCo FOIA Response 001010 DE-FC26-06NT42391 BUDGET DETAIL SOUTHERN COMPANY SERVICES, INC JANUARY 2007 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 7.2 - 488 (b) (4) SoCo FOIA Response 001011 DE-FC26-06NT42391 BUDGET DETAIL SOUTHERN COMPANY SERVICES, INC JANUARY 2007 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal 7.5-489 (b) (4) SoCo FOIA Response 001012 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Accooot I Description Cost Basis• DE-FC26-06NT42391 Budget Detail SUb Quantity UM Unit Cost Labor$ MaterialS contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to lhe restriction on the Iitie page of this proposal • Cost Basis: EE- Engineering Estimate, Ba- Budget Quote, au - Quote 7.5-490 (b) (4) SoCo FOIA Response 001013 Southern Company Services, Inc. DE·FC26·06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis• Quantity UM Unit Cost Labor$ Material$ Sub contract$ Total$ (b) (4) Use or disdosure of data on this sheet is subject to the restriction on the Iitie page of this proposal • Cost Basis: EE - Engineering Estimate, BO - Budget Quote, OU - Quote 7.5 - 491 (b) (4) SoCo FOIA Response 001014 Southern Company Services. Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ MaterialS Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.5-492 (b) (4) SoCo FOIA Response 001015 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis' DE-FC26-06NT42391 Budget DetaU Quantity UM Unit Cost labor$ Material$ Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.5-493 (b) (4) SoCo FOIA Response 001016 Southern Company Services, Inc. (b) (4) Account/ Description Escalated dolars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget DelaY Quantity UM Unit Cost Labor$ Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the Iitle page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.5-494 (b) (4) SoCo FOIA Response 001017 Southern Company Services, Inc. (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis* OE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quole, QU- Quole 7.5-495 (b) (4) SoCo FOIA Response 001018 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE·FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS Total$ (b) (4) Use or discloswe of data on this sheet is subject to the restriction on the tille page of this proposal • Cost Basis: EE • Engineering Estimate. BQ • Budget Quote, QU • Quote 7.5 ·496 (b) (4) SoCo FOIA Response 001019 Southern Company SeiVices, Inc. Escalated dollll(s Budget Period 2 (b) (4) Account/ Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ Material$ Sub contract$ Total$ I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ. Budget Quote, QU- Quote 7.5-497 (b) (4) SoCo FOIA Response 001020 Southern Company Services, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ Total$ (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page or this proposal • Cost Basis: EE - Engineering Estimate, BQ- Budget Quote, QU - Quote 7.5-498 (b) (4) SoCo FOIA Response 001021 Southern Company Se!vices, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost labor$ Material$ Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ • Budget Quote. QU- Quote 7.5-499 (b) (4) SoCo FOIA Response 001022 Southern Company Services, Inc. January 2007 (b) (4) Account/Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor $ Material$ Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU - Quote 7.5 - 500 (b) (4) SoCo FOIA Response 001023 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of dala on lhis sheet is subject to the restriction on lhe title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Ouole, OU - Quote 7.5 - 501 (b) (4) SoCo FOIA Response 001024 Southern Company Selvices, Inc. January 2007 (b) (4) Account/ Description DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 Cost Basis" Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basts: EE - Engineering Estimate, BQ - Budget Quote. QU - Quote 7.5-502 (b) (4) SoCo FOIA Response 001025 Southern Company Services. Inc. January 2007 (b) (4) Escalated dolars DE-FC26-06NT42391 Budget Period 2 Account I Description Cost Basis• Budget Detail Quantity UM Unit Cost Labor S MaterialS Sub contractS TotalS (b) (4) Use or disclosure or data on this sheet Is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.5 - 503 (b) (4) SoCo FOIA Response 001026 Soulhem Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unil Cost LaborS Material$ Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on lhe Iitle page of this proposal • Cost Basis: EE -Engineering Eslimate, BQ - Budget Quote, QU- Quole 7.5-504 (b) (4) SoCo FOIA Response 001027 Southem Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost laborS I Material$ Sub contract$ Total$ I (b) (4) Use or disclosure of data on this sheet Is subject to the restriction on the title page or this proposal • Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU -Quote 7.5-505 (b) (4) SoCo FOIA Response 001028 Southern Company Services, Inc. DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis• Quantity UM Unit Cost I LaborS MaterialS Sub contractS TotalS I (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ - Budget Quote. QU • Quote 7.5-506 (b) (4) SoCo FOIA Response 001029 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account/ Description Cost Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material $ Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal * Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.5 -507 (b) (4) SoCo FOIA Response 001030 Southern Company SeNices. Inc. JanuaJY 2007 (b) (4) Account/Description Escalated doftars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub conlract $ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.5-508 (b) (4) SoCo FOIA Response 001031 Southern Company Services, Inc. Janua~2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis* DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contract$ TotalS (b) (4) trav Use or disdosure of data on this sheet is subject to the restriction on the Iitle page of this proposal * Cost Basis: EE • Engineering Estimate. BO • Budget Quote. QU • Quote 7.5. 509 (b) (4) SoCo FOIA Response 001032 Southem Company Senrices, Inc. DE-FC26-06NT42391 Budget Detail Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis" Quantity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page of this proposal • Cost Bas1s: EE • Engineering Estimate. BQ - Budget Quote, QU - Quote 7.5 - 510 (b) (4) SoCo FOIA Response 001033 Southern Company Services. Inc. Escalated dolars Budget Period 2 (b) (4) Account/ Description Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contractS Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate. BQ - Budget Quote. QU • Quote 7.5-511 (b) (4) SoCo FOIA Response 001034 Southern Company Services, Inc. Januaty 2007 (b) (4) Account I Description Escalated dollars Budget Period 2 Cost Basis• DE-FC26-06NT42391 Budget Detail Quanlity UM Unit Cost LaborS MaterialS Sub contractS TotalS (b) (4) Use or disclosure or data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU - Quote 7.5- 512 (b) (4) SoCo FOIA Response 001035 Southern Company Services, Inc. Janu~007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contracts TotalS (b) (4) Use Of disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE - Engineering Estimate. BQ - Budget Quote, QU - Quote 7 .5 - 513 (b) (4) SoCo FOIA Response 001036 Southern Company Services, Inc. Escalated dollars BudgetPeriod 2 (b) (4) Account I Description Cost Basis' DE-FC26-06NT42391 Budget Detail Quanlily UM Unit Cost LaborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ · Budget Quote, QU ·Quote 7.5-514 (b) (4) SoCo FOIA Response 001037 Southern Company SeiVices, Inc. Janua~2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost Labor$ Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE • Engineering EsUmate. BQ - Budget Quote. QU - Quote 7.5-515 (b) (4) SoCo FOIA Response 001038 Southern Company Services, Inc. Janua~2007 (b) (4) Account/ Descfiption Escalated dollars Budget Period 2 Cost Basis" DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS MaterialS Sub contract$ TotalS (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE - Engineering Estimate, BQ - Budget Quote, QU • Quote 7.5-516 (b) (4) SoCo FOIA Response 001039 Southern Company Services, Inc. Escalated dollars Budget Period 2 (b) (4) Account I Description Cost Basis• DE-FC26-06NT42391 Budget Detail Quantity UM Unit Cost LaborS Material$ Sub contract$ Total$ (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BO • Budget Quote, QU • Ooole 7.5. 517 (b) (4) SoCo FOIA Response 001040 Southem Company SeiVices, Inc. January 2007 (b) (4) Account/ Description Escalated dollars Budget Period 2 Cost Basis' DE-FC26-06NT42391 Budget Detail Quantity UM UnitCosl laborS MaterialS Sub contractS Total$ (b) (4) Use or disdosure of data on this sheet is subject to the restriction on the title page of this proposal ' Cost Basis: EE- Engineering Estimate, BQ- Budget Quote, QU- Quote 7.5-518 (b) (4) SoCo FOIA Response 001041 Southern Company Services, Inc. Escalated dolars Budget Period 2 (b) (4) Account/ Description Cost Basis* DE-FC26-06NT42391 Budget Detail Quantily UM Unit Cost LaborS Material S Sub contractS TotalS (b) (4) I I I I I I I I I I I I Use or disclosure of data on this sheet is subject to the restriction on the title page of this proposal • Cost Basis: EE • Engineering Estimate, BQ - Budget Quote. QU - Quote 7.5-519 I (b) (4) SoCo FOIA Response 001042 Southern Companr Set"\ices, Inc. Januarr, 2007 DE-FC26-06NT42391 Section 7- SCS Cost Information (b) (4) Use or disclosure of data on this Sheet is subject to the restriction On the tide page of this proposal 7.5-520 (b) (4) SoCo FOIA Response 001043 Southern Companr Services, Inc. January, 2007 DE-FC26-06NT42391 Section 7- SCS Cost Information (b) (4) Use or disclosure of data on this Sheet is subject to the restriction On the tide page of this proposal 7.5-521 (b) (4) SoCo FOIA Response 001044 From: Sent: To: Cc: Subject: Attachments: "Cantrell, Heather Benson" < HBENSON@southernco.com> Wednesday, July 27, 2011 3:55 PM FITS, FITS@NETLDOE.GOV Robbins, Brittley K.; Shaw, Cindy F.; Henderson, Charles W.; Madden, Diane R.; Johnson, Raymond D. Southern Company Services - Electronic Filing of the Audit of For-Profit Recipients - FY 2010- DOE Award DE-FC26-06NT42391 SCS Audit of For-Profit Recipients FY 2010.pdf Per the instructions of Modification 008 to cooperative agreement number DE-FC26-06NT42391, attached is the Southern Company Services electronic filing of the Audit of For-Profit Recipients under DOE Award DEFC26-06NT42391 for the reporting period 01/01/2010- 12/31/2010. Please let us know if you have any questions or comments concerning this information. Report Information: DOE Award Number: DE-FC26-06NT42391 Type of Report: Audit of For-Profit Recipients Frequency of Report: 0/Y 180 Reporting Period: 1/1/10-12/31/10 Name of Submitting organization: Southern Company Services, Inc. Name of preparer: Heather Cantrell Phone number: 205-257-7162 Fax number: 205-257-6381 Heather Cantrell Southern Company Services, Inc. Government Contracts Coordinator 600 North 18th Street Birmingham, Alabama 35203 (Office) 205-257-7162 (Fax) 205-257-6381 hbenson@southernco.com SoCo FOIA Response 001045 SoCo FOIA Response 001046 SoCo FOIA Response 001047 of Dunn- Taucm Tum1w LJII1 Lau SoCo FOIA Response 001048 49 SoCo FOIA Response 001050 SoCo FOIA Response 001051 SoCo FOIA Response 001052 SoCo FOIA Response 001053 SoCo FOIA Response 001054 SoCo FOIA Response 001055 SoCo FOIA Response 001056 THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES FINANCIAL SECTION II-E SoCo FOIA Response 001057 MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Soulhrrn Company and Subsldlary Companies 2010 Annual Rrporl Southern Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management's supervision, an evaluation of the design and effectiveness of Southern Company's internal control over financial reporting was conducted based on the framework in Internal Control- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company's internal control over financial reporting was effective as of December 31, 20 I0. Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company's financial statements, has issued an attestation report on the effectiveness of Southern Company's internal control over financial reporting as of December 31, 20 I 0. Deloine & Touche LLP's report on Southern Company's internal control over financial reporting is included herein. Thomas A. Fanning Chairman, President, and Chief Executive Officer Art P. Beattie Executive Vice President and Chief Financial Officer February 25,2011 11-9 SoCo FOIA Response 001058 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Southern Company We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company and Subsidiary Companies (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 20 I 0. Our audits also included the financial statement schedule of the Company listed in the Index at Item 15. We also have audited the Company's internal control over financial reporting as of December 31,2010, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and the financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting (page 11-9). Our responsibility is to express an opinion on these financial statements and the financial statement schedule and an opinion on the Company's internal control over financial reporting based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (I) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compi iance with the policies or procedures may deteriorate. In our opinion, the consolidated financial statements (pages 11-44 to 11-10 I) referred to above present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies as of December 31, 20 I 0 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 20 I 0, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Atlanta, Georgia February 25, 20 II 11-10 SoCo FOIA Response 001059 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Soulhorn Comp ..y and Subsidiary Companiu 2010 A••••l Rtporl OVERVIEW Business Activities The primary business of Southern Company (the Company) is electricity sales in the Southeast by the traditional operating companies- Alabama Power, Georgia Power, Gulf Power, and Mississippi Power - and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. Many factors affect the opportunities, challenges, and risks of Southern Company's electricity business. These factors include the traditional operating companies' ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. Each of the traditional operating companies has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives. Southern Company's other business activities include investments in leveraged lease projects, renewable energy projects, and telecommunications. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions and dispositions accordingly. Key Performance lndicnlors In striving to maximize shareholder value while providing cost-effective energy to more than four million customers, Southern Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share (EPS). Southern Company's financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company's results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation Oeet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The fossil/hydro 20 I 0 Peak Season EFOR of 1.67% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The performance for 20 I 0 was better than the target for these reliability measures. Southern Company's 2010 results compared with its targets for some of these key indicators are reflected in the following chart: 2010 Targel Performance Top quartile in customer survevs 5.06% or less $2.30 - S2.36 Kev Performance Indicator Customer Satisfaction Peak Season EFOR- fossil/hydro Basic EPS 2010 Actual Performance Top auartile 1.67% $2.37 See RESULTS OF OPERATIONS herein for additional information on the Company's financial performance. The performance achieved in 20 I 0 renects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management's expectations. 11-11 SoCo FOIA Response 001060 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 ,\nnual Rrport Earnings Southern Company's net income after dividends on preferred and preference stock of subsidiaries was $1.98 billion in 20 I 0, an increase of$332 million from the prior year. This increase was primarily the result of increases in revenues due to colder weather in the first and fourth quarters 20 I0 and warmer weather in the second and third quarters 20 I 0, a litigation settlement agreement with MC Asset Recovery, LLC (MC Asset Recovery) in the first quarter 2009, increased amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia Public Service Commission (PSC), revenues associated with increases in rates under Alabama Power's rate stabilization and equalization plan (Rate RSE) and rate certificated new plant environmental (Rate CNP Environmental) that took effect in January 2010, and increases in sales primarily in the industrial sector. The 20 I 0 increase was partially offset by increases in operations and maintenance expenses, which include an additional accrual to Alabama Power's natural disaster reserve (NOR), a gain in 2009 on the early termination of two leveraged lease investments, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects. Net income after dividends on preferred and preference stock of subsidiaries was $1.64 billion in 2009 and $1 .74 bill ion in 2008. Basic EPS was $2.37 in 2010,$2.07 in 2009, and $2.26 in 2008. Diluted EPS, which factors in additional shares related to stockbased compensation, was $2.36 in 20 I0, $2.06 in 2009, and $2.25 in 2008. EPS for 20 I 0 was negatively impacted by $0.12 per share as a result of an increase in the average shares outstanding. Dividends Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.8025 in 20 I 0, $1.7325 in 2009, and $1 .6625 in 2008. In January 20 II, Southern Company declared a quarterly dividend of 45.50 cents per share. This is the 253rd consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. The Company targets a dividend payout ratio of approximately 70% of net income. For 20 I0, the actual payout ratio was 76%. RESULTS OF OPERATIONS Electricity Business Southern Company's electric utilities generate and sell electricity to retail and wholesale customers in the Southeast. A condensed statement of income for the electricity business follows: Amount 2010 2010 Increase (Decrease) from Prior Year 2009 2008 (in millions) Electric operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total electric operating expenses Operating income Other income (expense), net Interest expense, net of amounts capitalized Income taxes Net income Dividends on preferred and preference stock of subsidiaries Net income after dividends on preferred and preference stock of subsidiaries $ 17,374 6,699 563 3,907 1,494 867 13,530 3,844 159 1,732 747 89 505 19 51 1,411 321 (41) $ (1.358) (865) (341) ( 183) 62 22 (1.305) (53) 53 833 1,116 2,054 (2) 128 154 61 (49) ( 12) $ $ 10 87 ISO 65 $ 1.860 973 300 Ill 199 56 1,639 221 26 17 1,989 $ 154 $ (12) $ 133 11-12 SoCo FOIA Response 001061 MANAGEMENT'S DISCUSSION AND ANALYSIS (conlinu•dJ Soulh•rn Company and Subsidiary Compani•s 2010 Annual R•porl Electric Operati11g Re1•em1es Details of electric operating revenues were as follows: 2010 Amount 2009 2008 (ill mil/iOIIS) Retail- prior year Estimated change in Rates and pricing Sales growth (decline) Weather Fuel and other cost recovery Retail- current year Wholesale revenues Other electric operating revenues Electric operating revenues Percent change s s 13,307 $ 14,055 384 32 439 629 14,791 1,994 589 17.374 1 t.l o;. 144 (208) (21) (663) 13,307 1,802 533 $ 15,642 (8.0%) $ 12,639 668 (106) 854 14,055 2,400 545 $ 17.000 12.3% Retail revenues increased $1.5 billion, decreased $748 million, and increased $1.4 billion in 20 I 0, 2009, and 2008, respectively. The significant factors driving these changes are shown in the preceding table. The increase in rates and pricing in 20 I 0 was primarily due to Rate RSE and Rate CNP Environmental increases at Alabama Power and the recovery of environmental costs at Gulf Power. The 2009 increase in rates and pricing when compared to the prior year was primarily due to an increase in revenues from customer charges at Alabama Power and increased environmental compliance cost recovery (ECCR) revenues at Georgia Power in accordance with its retail rate plan for the years 2008 through 20 I 0 (2007 Retail Rate Plan), partially offset by a decrease in revenues from market-response rates to large commercial and industrial customers at Georgia Power. The 2008 increase in rates and pricing when compared to the prior year was primarily due to Alabama Power' s increase under its Rate RSE, as ordered by the Alabama PSC, and Georgia Power's increase under the 2007 Retail Rate Plan, as ordered by the Georgia PSC. Also contributing to the 2008 increase was an increase in revenues from market-response rates to large commercial and industrial customers. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. The traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental, storm damage, new plants, and PPAs. Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit power sales contracts, and short-term opportunity sales. Wholesale revenues from PPAs and unit power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on the market cost of available energy compared to the cost of the Company's system-owned generation, demand for energy within the Company's service territory, and the availability of the Company's system generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Shortterm opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost to produce the energy. In 2010, wholesale revenues increased $192 million primarily due to higher capacity and energy revenues under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010, as well as increased energy sales that were not covered by PPAs at Southern Power due to more favorable weather. This increase was partially offset by the expiration of long-term unit power sales contracts in May 20 I 0 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 20 I0. See FUTURE EARNINGS POTENTIAL - "PSC Maners - Alabama Power- Rate CNP" herein for additional information regarding the termination of certain unit power sales contracts in 20 I0 . In 2009, wholesale revenues decreased $598 million. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $603 million in 2009. Excluding wholesale fuel revenues, wholesale revenues increased $5 million primarily due to additional revenues associated with a new PPA at Southern Power's Plant Franklin Unit 3 which began in January 2009, partially offset by fewer short-term opportunity sales due to lower gas prices and reduced margins on short-term opportunity sales. 11-13 SoCo FOIA Response 001062 MANAGEMENT'S DISCUSSION AND ANALYSIS (conlinu•lll Soulh Contracts outstanding at the end of the period, assets (liabilities), net $(178) 197 (215) $(196) $(285) 367 (260) $( 178) (a)Currcnt period ch:lngcs also include the changes in fair value of new contracts entered tnto during the period, if any The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 20 I 0 was a decrease of $18 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 20 I 0, Southern Company had a net hedge volume of 149 million mmBtu with a weighted average contract cost approximately $1.35 per mmBtu above market prices, compared to 145 million mmBtu at December 31, 2009 with a weighted average contract cost approximately S 1.23 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies' fuel cost recovery clauses. At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets (liabilities) were as follows: Asset (Liability) Derivatives 2010 2009 (ill milliolls) Regulatory hedges Cash flow hedges Not designated Total fair value $(193) $(175) (1) (2) (2) $(196) $(178) (I) Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies' fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Total net unrealized pre-tax gains (losses) recognized in the statements of income for the years ended December 31, 2010, 2009, and 2008 for energy-related derivative contracts that are not hedges were $(2) million, $(5) million, and $1 million, respectively. 11·39 SoCo FOIA Response 001088 MANAGEMENT'S DISCUSSION AND ANALYSIS (rontinuedl Southern Company and Subsidiary Companies 2010 Annual Report Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note I0 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 20 I 0 were as follows: December 31,2010 Fair Value Measurements Total Fair Value Year I Maturity Years 2&3 Years 4&5 (in millions) Levell Leve12 Level3 Fair value of contracts outstanding at end of period $ $ $- $ - (196) (144) (52) $ (196) $ (144) $(52) $. Southern Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and Standard & Poor's, a division of The McGraw Hill Companies, Inc., or with counterparties who have posted collateral to cover potential credit exposure. Therefore, Southern Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note I to the financial statements under "Financial Instruments" and Note II to the financial statements. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized. Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company's domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company's international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level. Capital Requirements and Contractual Obligations The construction programs of the Company's subsidiaries are currently estimated to include a base level investment of$4.9 billion, $5.1 billion, and $4.5 billion for 20 II, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $341 million, $427 million, and $452 million for 20 II, 2012, and 2013, respectively. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million for 2011,$191 million to $670 million for 2012, and $476 million to $1.9 billion for 2013. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements under "Retail Regulatory Matters- Georgia Power- Nuclear Construction," "Retail Regulatory Matters Georgia Power- Other Construction," and "Retail Regulatory Matters -Mississippi Power Integrated Coal Gasification Combined Cycle" and Note 7 to the financial statements under "Construction Program" for additional information. As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note I to the financial statements under "Nuclear Decommissioning." ll-40 SoCo FOIA Response 001089 MANAGEMENT'S DISCUSSION AND ANALYSIS (contimd) Southern Compuy and Subsidiuy Companin 2010 Annual Report In addition, as discussed in Note 2 to the financial statements, Southern Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the traditional operating companies' respective regulatory commissions. Other funding requirements related to obligations associated with scheduled maturities oflong-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes I, 6, 7, and II to the financial statements for additional information. 11-41 SoCo FOIA Response 001090 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companiu 2010 Annual Report Contractual Obligations 2011 Long-tenn debt1"1 Principal Interest Preferred and preference stock dividendstbJ Energy-related derivative obligations1' 1 Operating leases Capital leases Unrecognized tax benefits and interest1d1 Purchase commitments1' ' Capital11) Limestone'¥' Coal Nuclear fuel Natural gas1hJ Biomass fuel''' Purchased power Long-term service agreements0' TrustsNuclear decommissioning1k 1 Pension and other QOStretirement benefit Qlans111 Total (a) (b) (c) (d) (c) (I) (g) (h) (i) (j) (k) (I) 20122013 20142015 After Uncertain Timins'd' 2015 Total (in miflioru) $1,278 876 65 $2,938 1,610 130 $1,138 1,369 130 $14,029 11,194 94 13 103 35 $ 55 151 154 23 203 170 28 4,554 39 3,810 335 1,357 9,242 82 3,244 427 2,280 260 110 506 270 3 64 $13.282 4 147 $21,165 122 32 72 1,656 349 1,687 36 559 290 89 1,798 807 3,413 110 2,439 1,435 4 35 $7,397 $35,487 $19,383 15,Q49 325 206 521 99 325 13,796 282 10,508 1,918 8,737 178 3,764 2,105 $ 122 46 211 $77,453 All amounts arc rellccted based on final maturity dates. Soutl1ern Company and its subsidiaries plan to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations arc estimated based on rates as of January I, 2011, as reflected in the statements of capitalization. Fhed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shO\\n separately). Preferred and preference stock do not mature; therefore, amounts arc provided for the next five years only. For additional information, sec Notes I and II to the financial statements. T11e timing related to the realization of$122 million in unrecognized ta~ benefits and corresponding interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement ofta~ positions. Sec Notes 3 and 5 to the financial statements for additional information. Southern Company generally docs not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2010, 2009, and 2008 were $4.0 billion, $3.5 billion, and $3.8 billion, respectively. Southern Company provides forecasted capital expenditures for a three-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commiuncnts for nuclear fuel. In addition, such amounts exclude Southern Company's estimates of potential incremental investments to comply with anticipated new environmental regulations which could range from $74 million to $289 million for 2011, $191 million to $670 million for 2012, and $4 76 million to $1.9 billion for 2013 . At December 31, 2010, significant purchase commitments were outstanding in connection with the construction progrnm. As part of Southern Company's program to reduce S02 emissions from its coal plants. the traditional opcrnting companies have entered into various long-term commitments for the procurement ortimestone to be used in llue gas desulfurization equipment. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts rellected ha\·e been estimated based on the New York Mercantile Exchange future prices at December 31,2010. Biomass fuel commiuncnts arc based on minimum committed tonnage of wood waste purchases. Long-term service agreements include price escalation based on inflation indices. Projections of nuclear decommissioning trust fund contributions arc based on the 2010 ARP for Georgia Power. Southern Company forecasts contributions to the qualified pension and other postretirement benefit plans over a three-year period. Southern Company docs not expect to be required to make any contributions to the qualified pension plan during the next three years. Sec Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from Southern Company's corporate assets. 11·42 SoCo FOIA Response 001091 MANAGEMENT'S DISCUSSION AND ANALYSIS ftontinutdl Southtn Comp•ny and S•bsidi..-y Companlts 2010 Annual Rtport Cautionary Statement Regarding Fonvard-Looking Statements Southern Company's 20 I0 Annual Report contains forward-looking stalcments. Forward-looking statemenls include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate actions, environmental regulations and expenditures, future earnings, dividend payout ratios, access 10 sources of capital, projections for the qualified pension plan, postretirement benefit, and nuclear decommissioning trust fund contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impact of the American Recovery and Reinvestment Act of2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 20 I0, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 20 I 0, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," " predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: • • • • • • • • • • • • • • • • • • • • • • • • the impact of recent and future federal and state regulatOI)' changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industl)', implementation of the Energy Policy Act of2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries arc subject, as well as changes in application of existing laws and regulations; current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS audits; the dTects, extent, and timing of the entl)' of additional competition in the markets in which Southern Company's subsidiaries operate; variations in demand for electricity, including those relating to weather, the general economy and recO\'el)' from the recent recession, population and business gro\\1h (and declines), and the effeciS of energy conservation measures; available sources and costs of fuels; effects of inflation; ability to control costs and avoid cost overruns during the development and construction of facilities: investment performance of Southern Company's employee benefit plans and nuclear decommissioning trust funds; advances in technology; state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms; regulatory approvals and actions related to the Plant Vogtle expansion, including Georgia J>SC and NRC approvals and potential DOE loan guarantees; regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals and potential DOE loan guarantees; the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries; the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers: the direct or indirect effect on Southern Company's business resulting from terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company's and its subsidiaries' credit ratings; the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices: catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect e!Tects on Southern Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC. Southern Compaay npressly disclaims any obligation to upd11te any ron1·ud-looking st11tements. 11-43 SoCo FOIA Response 001092 CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2010,2009, and 2008 Southern Compnny and Subsidiary Compnnies 2010 Annunl Report 2010 2009 2008 (in millions) Operating Revenues: Retail revenues Wholesale revenues Other electric revenues Other revenues Total operating revenues Operating Expenses: Fuel Purchased power Other operations and maintenance MC Asset Recovery litigation settlement Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Interest income Leveraged lease income (losses) Gain on disposition of lease termination Loss on extinguishment of debt Interest expense, net of amounts capitalized Other income (expense), net Total other income and (expense) Earnings Before Income Taxes I ncome taxes Consolidated Net Income Dividends on Preferred and Preference Stock of Subsidiaries Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries Common Stock Data: Earnings per share (EPS)Basic EPS Diluted EPS Average number of shares of common stock outstanding- (m mllhonsl Basic Diluted Cash dividends paid per share of common stock $14,791 1,994 589 82 17,456 $13,307 1,802 533 101 15,743 $14,055 2,400 545 127 17,127 6,699 563 4,010 5,952 474 3,526 202 1,503 818 12,475 3,268 6,818 815 3,748 1,513 869 13,654 3,802 194 24 18 (895) (77) (736) 3,066 1,026 2,040 65 200 23 31 26 (17) (905) (22) (664) 2,604 896 1,708 65 1,443 797 13,621 3,506 152 33 (85) (866) (18) (784) 2,722 915 1,807 65 $ 1,975 $ 1,643 $ 1,742 $2.37 2.36 $2.07 2.06 $2.26 2.25 832 837 $1.8025 795 796 $1.7325 771 775 $1.6625 The accompanying notes arc an integral pan of these financial statements. 11-44 SoCo FOIA Response 001093 CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended Dec:ember 31,2010,2009, and 2008 Southern Company and Subsidiary Companies 2010 Annual Report 2010 2009 2008 (In millions) Operating Activities: Consolidated net income Adjustments to reconcile consolidated net income to net cash provided from operating activities -Depreciation and amortization, total Deferred income taxes Deferred revenues Allowance for equity funds used during construction Leveraged lease (income) losses Gain on disposition of lease termination Loss on extinguishment of debt Pension, postretirement, and other employee benefits Stock based compensation expense Hedge settlements Generation construction screening costs Other, net Changes in certain current assets and liabilities--Receivables -Fossil fuel stock -Materials and supplies -Other current assets -Accounts payable -Accrued taxes -Accrued compensation -Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Investment in restricted cash from revenue bonds Distribution of restricted cash from revenue bonds Nuclear decommissioning trust fund purchases Nuclear decommissioning trust fund sales Proceeds from property sales Cost of removal, net of salvage Change in construction payables Other investing activities Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds-Long-term debt issuances Common stock issuances Redemptions -Long-term debt Redeemable preferred stock Payment of common stock dividends Payment of dividends on preferred and preference stock of subsidiaries Other financing activities Net cash provided from financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Eauivalents at End of Year $ 2,040 1,831 1,038 (103) (194) (18) $ 1,708 $ 1,807 1,704 215 120 (152) 85 (614) 33 2 (51) 86 1,788 25 (54) (200) (31) (26) 17 (3) 23 (19) (22) 102 80 135 (30) (17) 4 (308) 180 (103) 3,991 585 (432) (39) (47) (125) (95) (226) 334 3.263 (176) (303) (23) (36) (74) 293 36 20 3.464 (4,086) (SO) 25 (2,009) 2,004 18 (125) (51) 18 (4,256) (4,670) (55) 119 ( 1,234) 1,228 340 (119) 215 (143) (4.319) (3,961) (96) 69 (720) 712 34 (123) 83 (124) (4.126) (306) (314) 659 3,151 772 3,042 1,286 (2,966) (1,234) (1,496) (65) (33) 22 (243) 690 $ 447 (I ,369) (65) (25) 1,329 273 417 $ 690 21 20 15 (108) 3,687 474 (1,469) (125) (1,280) (66) (29) 878 216 201 $ 417 The accompanying notes nre nn integrol pan orthesc fonnncinl statements. 11-45 SoCo FOIA Response 001094 CONSOLIDATED BALANCE SHEETS At December 31,2010 and 2009 Southern Compnny and Subsidiary Companies 2010 Annual Report Assets 2010 2009 (illmilliolls) Current Assets: Cash and cash equivalents Restricted cash and cash equivalents Receivables -Customer accounts receivable Unbilled revenues Under recovered regulatory clause revenues Other accounts and notes receivable Accumulated provision for uncollectible accounts Fossil fuel stock, at average cost Materials and supplies, at average cost Vacation pay Prepaid expenses Other regulatory assets, current Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated depreciation Plant in service, net of depreciation Nuclear fuel, at amortized cost Construction work in progress Total property, plant, and equipment Other Property and Investments: Nuclear decommissioning trusts, at fair value Leveraged leases Miscellaneous property and investments Total other property and investments Deferred Charges and Other Assets: Deferred charges related to income taxes Prepaid pension costs Unamortized debt issuance expense Unamortized loss on reacquired debt Deferred under recovered regulatory clause revenues Other regulatory assets, deferred Other deferred charges and assets Total deferred charges and other assets Total Assets $ 447 68 1,140 420 209 285 (25) 1,308 827 151 784 210 59 5,883 $ 690 43 953 394 333 375 (25) 1,447 794 145 508 167 49 5,873 56,731 20,174 36,557 670 4,775 42,002 53,588 19, 121 34,467 593 4,170 39,230 1,370 624 277 2,271 1,070 610 283 1,963 1,280 88 178 274 218 2,402 436 4,876 $55 032 1,047 208 255 373 2,702 395 4,980 $52.046 The accompanying no1es are an inlegral pan oflhese financ1al slalements 11-46 SoCo FOIA Response 001095 CONSOLIDATED BALANCE SHEETS At December 31,2010 and 2009 Southern Company and Subsidiary Companies 2010 Annual Report Liabilities and Stockholders' Equity 2010 2009 (in milliol:s) Current Liabilities: Securities due within one year Notes payable Accounts payable Customer deposits Accrued taxes -Accrued income taxes Unrecognized tax benefits Other accrued taxes Accrued interest Accrued vacation pay Accrued compensation Liabilities from risk management activities Other regulatory liabilities, current Other current liabilities Total current liabilities Long-Term Debt (Sec accompanying statements) Deferred Credits and Other Liabilities: Accumulated deferred income taxes Deferred credits related to income taxes Accumulated deferred investment tax credits Employee benefit obligations Asset retirement obligations Other cost of removal obligations Other regulatory liabilities, deferred Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Redeemable Preferred Stock of Subsidiaries (See accompanying statements) Total Stockholders' Equity (Sec accompanying statements) Total Liabilities and Stockholders' Equity Commitments and Contingent Matters (Sec notes) $ 1,301 1,297 1,275 332 $ 1,113 639 1,329 331 8 187 440 225 194 438 152 88 535 6,472 18,154 13 166 398 218 184 248 125 528 292 5,584 18,131 7,554 235 509 1,580 1,257 1,158 312 517 13,122 37,748 375 16,909 $55,032 6,455 248 448 2,304 1,201 1,091 278 346 12,371 36,086 375 15,585 $52.046 The accompanying notes arc an mtcgral part of these financial statements 1147 SoCo FOIA Response 001096 CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31, 2010 and 2009 Southern Company and Subsidiary Companies 2010 Annual Report 2010 2009 (in millions) Long-Term Debt: Long-term debt payable to affiliated trusts -Maturity Inter~~~ Rat£~ 2044 5.88% Variable rate (3.39% at 1/1/11) due 2042 Total Ions-term debt Ea~able to affiliated trusts Long-term senior notes and debt -Interest Rates Maturity 4.70% 2010 4.00% to 5.57% 2011 2012 4.85% to 6.25% 1.30% to 6.00% 2013 4.15% to 4.90% 2014 2.38% to 5.75% 2015 2.25% to 8.20% 20 16 through 2048 Adjustable rates (at 111111 ): 0.35% to 0.97% 2010 2011 0.56% to 0.78% 0.62% 2013 0.44% 2040 Total Ions-term senior notes and debt Other long-tenn debt -Pollution control revenue bonds Maturity Interest Bate~ 0.80% to 6.00% 2016 through 2049 Variable rates (at 111/11 ): 20 1 1 throush 2041 0.26% to 0.51% Total other Ions-term debt CaEitalized lease oblisations Unamortized debt (discount), net Total long-term debt (annual interest requirement-$ 876 million) Less amount due within one ~ear Lons-term debt excludins amount due within one ~ear s 206 206 412 304 1,778 1,436 425 1,184 9,438 $ 206 206 412 102 304 1,778 936 425 1,025 8,822 990 790 15,172 1,807 1,973 1,284 3,091 1,612 3,585 98 (23) 99 19,455 1,301 18,154 2009 (percent oftotal) 915 350 50 15,880 (27} 2010 19,244 1,113 18,131 51.2•/o 53.2% 11-48 SoCo FOIA Response 001097 CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2010 and 2009 Southern Company and Subsidiary Companies 2010 Annual Report 2010 2009 (in mil/tons) Redeemable Preferred Stock of Subsidiaries: Cumulative preferred stock $100 par or stated value-- 4.20% to 5.44% Authorized - 20 million shares Outstanding - I million shares $1 par value-- 5.20% to 5.83% Authorized - 28 million shares Outstanding - 12 million shares: $25 stated value Total redeemable preferred stock of subsidiaries (annual dividend requirement-- $ 20 million) Common Stockholders' Equity: Common stock, par value $5 per share -Authorized- I billion shares Issued -- 2010: 844 million shares -- 2009: 820 million shares Treasury -- 20 I 0: 0.5 million shares -- 2009: 0.5 million shares Paid-in capital Treasury, at cost Retained earnings Accumulated other comprehensive income (loss) Total common stockholders' equity Preferred and Preference Stock of Subsidiaries: Non-cumulative preferred stock $25 par value-- 6.00% to 6.13% Authorized - 60 million shares Outstanding- 2 million shares Preference stock Authorized - 65 million shares Outstanding- $1 par value-- 5.63% to 6.50% - 14 million shares (non-cumulative) - $100 par or stated value -- 6.00% to 6.50% - 3 million shares (non-cumulative) Total preferred and preference stock of subsidiaries (annual dividend requirement--$ 45 million) Total stockholders' equity Total Capitalization 2010 2009 (percent oflola/) 81 81 294 294 375 375 4,219 4,101 3,702 (15) 8,366 (70) 16,202 2,995 (15) 7,885 (88) 14,878 45 45 343 343 319 319 707 16,909 $35,438 707 15,585 $34.091 1.1 1.1 45.7 43.6 2.0 2.1 1oo.o•;. 100.0% The accomp:111ying notes are on integral pan of these financial statements. 11-49 SoCo FOIA Response 001098 CONSOLIDATED STATEMENTS OF STOCKIIOLDERS' EQUIT\' For the \'can Endctl December 31, 2010, 2009, and 2008 Southern Company and Subsidiary Companico 2010 Annual Report Number or Common Shares l~sur!! Trco~ua (m Ihmuandr) Balance at December 31, 2007 Net income after dividends on preferred and preference stock of subsidiaries Other comprehensive loss Stock issued Stock-based compensation Cash dividends Other Balance at December 31,2008 Net income after dividends on preferred and preference stock of subsidiaries Other comprehensive: income Stock issued Stock-based compensation Cash dividends Other Balance at December 31,2009 Net income after dividends on preferred and preference stock of subsidiaries Other comprehensive income Stock issued Stock-based compensation Cash dividends Other Ualancc at December 31,2010 763,503 (399) Common Stock Par Paid-In Value Canilnl Trea~uo· Accumulated Other Comprchensin Retained Income jLoss) F.grnin~:~ Preferred and Preference Stock of Subsidiaries Sl,454 S) Plant Vogtle (nuclear) Units I and 2 Plant Hatch (nuclear) Plant Miller (coal) Units I and 2 Plant Scherer (coal) Units I and 2 Plant Wansley (coal) Rocky Mountain (pumped storage) Intercession City (combustion turbine) Plant Stanton (combined cycle) Unit A 45.7% 50.1 $3,292 962 $1,935 534 91.8 1,253 477 8.4 53.5 25.4 33.3 148 700 175 12 74 208 109 3 65.0 156 25 At December 31, 2010, the portion of total construction work in progress related to Plants Miller, Scherer, Wansley, and Vogtle Units 3 and 4 was $125 million, $110 million, $11 million, and $1.3 billion, respectively. Construction at Plants Miller, Wansley, and Scherer relates primarily to environmental projects. See Note 3 under "Retai I Regulatory Matters - Georgia Power - Nuclear Construction" for information on Plant Vogtle Units 3 and 4. Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly owned facilities, except for Rocky Mountain and Intercession City, as agents for their respective co-owners. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing. 5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. II-SO SoCo FOIA Response 001129 NOTES (continnd) Sonthrn Comp..y ..d Subsidiuy Comp..ies 2010 Annuli R•port Current nnd Deferred Income Taxes Details of income tax provisions are as follows: 2010 2009 2008 (irr milliom) FederalCurrent Deferred StateCurrent Deferred Total 42 898 940 $771 40 811 $628 177 805 (54) 140 86 $1,026 100 (15) 85 $896 72 38 110 $915 $ Net cash payments for income taxes in 2010, 2009, and 2008 were $276 million, $975 million, and $537 million, respectively. The tax effects oftemporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2010 2009 (ill milllotu) Deferred tax liabilitiesAccelerated depreciation Property basis differences Leveraged lease basis di ffercnccs Employee benefit obligations Under recovered fuel clause Premium on reacquired debt Regulatory assets associated with employee benefit obligations Regulatory assets associated \\ ith asset retirement obligations Other Total Deferred ta.x assets Federal effect of state deferred ta.xes State effect of federal deferred ta.xes Employee benefit obligations Over recovered fuel clause Other property basis differences Deferred costs Cost of removal Unbilled revenue Other comprehensive losses Asset retirement obligations Other Total Total deferred ta.x liabilities, net Portion included in prepaid expenses (accrued income ta.xes), net Deferred state ta.x assets Valuation allowance Accumulated deferred income ta.xes $6,833 1,150 263 485 179 78 814 509 246 10557 $5,938 986 251 384 271 100 939 486 216 9.571 386 302 108 1,435 119 132 65 109 96 81 486 458 3.391 6.180 229 105 (59) S6.455 so 1,179 40 119 100 52 126 69 509 523 3.153 7,404 117 91 (58) S7.SS4 At December 31, 2010, Southern Company had a State of Georgia net operating loss (NOL) carryforward totaling $0.9 billion, which could result in net state income tax benefits of $53 million, if utilized. However, Southern Company has established a valuation allowance for the potential $53 million tax benefit due to the remote likelihood that the tax benefit will be realized. These NOLs expire between 20 II and 2021. Beginning in 2002, the State of Georgia allowed Southern Company to file a combined return, which has prevented the creation of any additional NOL carryforwards. At December 31, 2010, the tax-related regulatory assets and liabilities were $1.3 billion and $237 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than 11-81 SoCo FOIA Response 001130 NOTES (conlinurtl) Soulhrrn Company and Subsidiary Companirs 2010 Annual Rrporl the current enacled tax law, and to taxes applicable to capitalized interest. In 2010, $82 million was deferred as a regulatory asset related to the impacl of the Patienl Proleclion and Affordable Care Act and the Health Care and Education Reconciliation Act of2010 (together, the Acts). The Acts eliminated the deductibility ofhealthcare costs that are covered by federal Medicare subsidy payments. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits. In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $23 million in 20 l 0, $24 million in 2009, and $23 million in 2008. At December 31, 20 I 0, all investment tax credits available to reduce federal income taxes payable had been utilized. On September 27, 20 I0, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA inc~des an extension of the 50% bonus depreciation for certain property acquired and placed in service in 20 I 0 (and for certain long-term construction projects to be placed in service in 20 II). Additionally, on December 17, 20 I 0, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Acl (Tax Relief Act) was signed into law. Major lax incentives in lhe Tax Relief Act include I 00% bonus depreciation for property placed in service after September 8, 20 I 0 and through 20 II (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-1erm conslruction projects to be placed in service in 2013). The applicalion of the bonus depreciation provisions in these acts in 2010 significanlly increased deferred lax liabilities related to accelerated depreciation. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Federal slatutory rate State income tax, net of federal deduction Employee stock plans dividend deduction Non-deductible book depreciation Difference in prior years' deferred and current tax rate AFUDC-Equity Production activities deduction lTC basis difference Leveraged lease termination MC Asset Recovery Donations Other Effective income tax rate 2010 2009 2008 35.0°/. 1.8 (1.2) 0.8 (0.1) (2.2) 35.0% 2.1 ( 1.4) 0.9 (0.1) (2.7) (0.7) 35.0% 2.6 (1.3) 0.8 (0.2) ( 1.9) (0.4) (0.9) 2.7 (0.4) (0.1) 34.4% {1.0) 33.6% (0.4) (0.2} 33.5% Southern Company's effective tax rate is lower than the statutory rate primarily due to the employee stock plans' dividend deduction and AFUDC equity, which is not taxable. Soulhern Company's 2010 effective tax rate decreased from 2009 primarily due to the $202 million charge recorded for the MC Asset Recovery litigation settlement in 2009, which completed and resolved all claims by MC Asset Recovery against Southern Company. Southern Company is currently evaluating potential recovery of the settlement payment through various means including insurance, claims in U.S. Bankruptcy Court, and other avenues. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. The ultimate outcome of any such recovery and/or income tax treatment cannot be determined at this time. The decrease in Southern Company's effective tax rate was partially offset by the elimination of the production activities deduction in 2010. The American Jobs Creation Act of2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 ofthe Internal Revenue Code (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 20 I 0. For 2008 and 2009, a 6% reduction was available to Southern Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions, there was no domestic production deduction available to Southern Company for 20 I 0. 11-82 SoCo FOIA Response 001131 NOTES (tonti•u•dl Soutbrrn Company and Subsidiary Companlrs 2010 Annual Rrporl Unrecognized Tax Benefits For 2010, the total amount of unrecognized tax benefits increased by $97 million, resulting in a balance of$296 million as of December 31, 20 I0. Changes during the year in unrecognized tax benefits were as follows: 2010 2009 2008 (in millions) Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions increase from prior periods Tax positions decrease from prior periods Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year $199 62 62 (27) $146 53 12 ( 10) $264 49 130 (297) (2) $296 $199 $146 The tax positions from current periods relate primarily to the Georgia state tax credits litigation, tax accounting method change for repairs, and other miscellaneous uncertain tax positions. The tax positions increase from prior periods relates primarily to the tax accounting method change for repairs and other miscellaneous positions. The tax positions decrease from prior periods relates primarily to the Georgia state tax credit litigation and miscellaneous tax positions. See Note 3 under "Income Tax Matters - Georgia State Income Tax Credits" and "Tax Method of Accounting for Repairs" for additional information. The impact on Southern Company's effective tax rate, if recognized, is as follows: 2010 2009 2008 (in milli01u) Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits $217 79 $296 $199 $199 $143 3 $146 The tax positions impacting the effective tax rate primarily relate to Georgia state tax credit litigation at Georgia Power and the production activities deduction tax position. However, as discussed in Note 3 under " Income Tax Matters," if Georgia Power is successful in its claim against the Georgia DOR, a significant portion of the tax benefit is expected to be deferred and returned to retail customers and therefore no material impact to net income is expected. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note 3 under "Income Tax Matters - Georgia State Income Tax Credits" and "Tax Method of Accounting for Repairs" for additional information. Accrued interest for unrecognized tax benefits was as follows: 2010 2009 2008 (in millions) Interest accrued at beginning of year Interest reclassi lied due to settlements Interest accrued during the year Balance at end of year $21 $15 8 6 $21 $29 $31 (49) 33 $15 Southern Company classifies interest on tax uncertainties as interest expense. The net amount of interest accrued during 20 I 0 was primarily associated with the Georgia state tax credit litigation. Southern Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of Southern Company's unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the Georgia state tax credit litigation would substantially reduce the balances. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate oflhe range of reasonably possible outcomes cannot be determined. 11-83 SoCo FOIA Response 001132 NOTES (contin•ed) Southern Comp..y and Subsidiary Companies 2010 Annual Report The IRS has audited and closed all tax returns prior to 2007. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006. 6. FINANCING Long-Term Debt Payable to Affiliated Trusts Certain of the traditional operating companies have fanned certain wholly-owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the applicable traditional operating company through the issuance ofjunior subordinated notes totaling $412 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as long-term debt. Each traditional operating company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trust's payment obligations with respect to these securities. At December 31, 20 I 0, preferred securilies of$400 million were outstanding. See Note I under "Variable Interest Entities" for additional information on the accounting treatment for these trusts and the related securities. Securities Due Within One Year A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows: 2010 s 8 23 600 670 $1.301 Pollution control revenue bonds Capitalized leases Senior notes Other long-term debt Total 2009 (irr milliorrs) $ 21 1,090 2 $ 1,113 Maturities through 2015 applicable to total long-term debt are as follows: $1.3 billion in 20 II; $1.8 billion in 20 12; $1.7 billion in 2013; $441 million in 2014; and $1.2 billion in 2015. Bank Term Loans Certain of the traditional operating companies have entered into bank term loan agreements. In 2010, Mississippi Power entered into a one-year $125 million aggregate principal amount long-term floating rate bank loan that bears interest based on one-month London Interbank Offered Rate (LIBOR). The proceeds from this loan were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes, including Mississippi Power's continuous construction program. At December 31, 20 I 0 and 2009, certain of the traditional operating companies had outstanding bank term loans totaling $615 million and $490 million, respectively. Senior Notes Southern Company and its subsidiaries issued a total of$2.9 billion of senior notes in 2010. Southern Company issued $400 million, and the traditional operating companies' combined issuances totaled $2.5 billion. The proceeds of these issuances were used to repay long-term and short-term indebtedness and for other general corporate purposes including the applicable subsidiary's continuous construction program. At December 31,2010 and 2009, Southern Company and its subsidiaries had a total of$15.2 billion and $14.7 billion, respectively, of senior notes outstanding. At December 31,2010 and 2009, Southern Company had a total of$1.6 billion and $1.8 billion, respectively, of senior notes outstanding. Subsequent to December 31, 20 I0, Georgia Power issued $300 million aggregate principal amount of Series 20 II A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay a portion of Georgia Power's outstanding short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program. 11-84 SoCo FOIA Response 001133 NOTES (conll•ueill Southern Compan)' and Subsidiary Comp..ies 2010 Annual Report Pollution Control and Other Revenue Bonds Pollution control obligations represent loans to the traditional operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The traditional operating companies have $3.1 billion of outstanding pollution control revenue bonds and are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. In December 20 I 0, Mississippi Power incurred obligations relating to the issuance of$ I00 million of revenue bonds in two series, each of which is due December I, 2040. The first series of$50 million was issued with an initial fixed rate of2.25% through January 14, 2013 and the second series of$50 million was issued with a Ooating rate. Proceeds from the second series bonds were classified as restricted cash at December 31, 20 I 0 and these bonds were redeemed on February 8, 20 I I. The proceeds from the first series bonds were used to finance the acquisition and construction of buildings and immovable equipment in connection with Mississippi Power's construction of the Kemper JGCC. Assets Subject to Lien Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. Alabama Power and Gulf Power have granted one or more liens on certain of their respective property in connection with the issuance of certain pollution control revenue bonds with an outstanding principal amount of $194 million. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. Bnnk Credit Arrnngements The following table outlines the credit arrangements by company: Executable Term-Loans Coml!anv Total Unused One Year Two Years (ill milfiOIIS) Southern Company Alabama Power Georgia Power Gulf Power Mississippi Power Southern Power Other Total (a) $ 950 1,271 1,715 240 161 400 60 $4,797 $ 950 1,271 1,703 240 161 400 60 $4,785 $ $ 372 220 210 65 Ex!!ires - 2011 2013 (ill mil/iOIIS) $ - 41 506 595 240 161 $81 60 $1,562 40 2012 Expires Within One Year1"1 Term No Term Loan Loan O!!tion O!!tion $950 $ 765 1,120 (i11 millioiiS) 372 260 210 106 $ 134 335 30 55 60 $1,008 $554 $ 400 60 $927 $ 3.235 $ Rcnects facilities expiring on or before December 31, 20 II . All of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average approximately Y: of I% or less for Southern Company, the traditional operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal. Most of the credit arrangements with banks have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities. At December 31, 20 I 0, Southern Company, Southern Power, and the traditional operating companies were each in compliance with their respective debt limit covenants. 11-SS SoCo FOIA Response 001134 NOTES (tontlnufd) Soulhfrn Comrany and Subsidiary Comraniu 2010 Annual Rfporl In addition, the credit arrangements typically contain cross default provisions that would be triggered if the borrower defaulted on other indebtedness above a specified threshold. The cross default provisions are restricted only to the indebtedness, including any guarantee obligations, of the company that has such credit arrangements. Southern Company and its subsidiaries are currently in compliance with all such covenants. A portion of the $4.8 billion unused credit with banks is allocated to provide liquidity support to the traditional operating companies' variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2010 was approximately $1.3 billion. Subsequent to December 31, 2010, Georgia Power's remarketing of$137 million ofputtable variable rate pollution control bonds increased the total requiring liquidity support to $522 million. Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of committed bank credit arrangements. Southern Company and the traditional operating companies may also borrow through various other arrangements with banks. The amount of short-term bank loans included in notes payable in the balance sheets at December 31, 20 I0 was $1 million. There were no short term-bank loans included in notes payable in the balance sheets at December 31, 2009. At December 3 I, 20 I0, the Southern Company system had approximately $1.3 billion of commercial paper borrowings outstanding with a weighted average interest rate of0.3% per annum. During 20 I 0, Southern Company had an average of $690 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $1 .3 billion. At December 31, 2009, the Southern Company system had approximately $638 million of commercial paper borrowings outstanding with a weighted average interest rate of0.3% per annum. During 2009, Southern Company had an average of$956 million of commercial paper outstanding at a weighted average interest rate of0.4% per annum and the maximum amount outstanding was $1.4 billion. Chnnges in Redeemnblc Preferred Stock of Subsidiaries Each of the traditional operating companies has issued preferred and/or preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary's board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as "Redeemable Preferred Stock of Subsidiaries" in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision that would allow the holders to elect a majority of such subsidiary's board. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are required to be shown as "noncontrolling interest," separately presented as a component of"Stockholders' Equity" on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity. The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable Preferred Stock of Subsidiaries (in millions) $498 Balance at December 31, 2007 Issued Redeemed Other Bahmce at December 31, 2008 Issued Redeemed Balance at December 31, 2009 Issued Redeemed Balance at December 31,2010 ( 125) 2 $375 $375 $375 11-86 SoCo FOIA Response 001135 NOTES (continurdl Southrrn Comp1ny ud Subsidiary Companirs 2010 Annual Rrport 7. COMMITMENTS Construction Program The construction programs of the Company's subsidiaries are currently estimated to include a base level investment of$4.9 billion in 2011,$5.1 billion in 2012, and $4.5 billion in 2013. These amounts include $335 million, $207 million, and $220 million in 2011, 2012, and 2013, respectively, for construction expenditures related to contractual purchase commitments for nuclear fuel included herein under "Fuel and Purchased Power Commitments." Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of$341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. The capital budget amounts for 20 11·2013 include amounts for the construction of Plant Vogtle Units 3 and 4. Of the estimated total $4.4 billion in capital costs for Plant Vogtle Units 3 and 4, approximately $943 million is expected to be incurred from 2014 through 2017. The construction programs are subject to periodic review and revision, and actual conslruction cosls may vary from these estimates because of numerous factors. These factors include: changes in business condiJions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirement and replacement decisions, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 3 I, 20 I0, significant purchase commitmenJs were outstanding in connection with the ongoing construction program, which includes new facilities and capital improvements to transmission, distribution, and generation facilities, including those to meet environmental standards. See Note 3 under "Retail Regulatory Matters - Georgia Power - Nuclear Construction," "Retail Regulatory Matters - Georgia Power Other Construction," and "Retail Regulatory Matters - Mississippi Power Integrated Coal Gasification Combined Cycle" for additional information. long-Term Service Agreements The traditional operating companies and Southern Power have entered into long-term service agreements (LTSAs) with General Electric (GE), Alstom Power, Inc., Mitsubishi Power Systems Americas, Inc., and Siemens AG for the purpose of securing maintenance support for the combined cycle and combustion turbine generating facilities owned or under construction by the subsidiaries. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The L TSAs are also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments under the LTSAs, which are subject to price escalation, are made at various intervals based on actual operating hours or number of gas turbine starts of the respective units. Total remaining payments under these agreements for facilities owned are currently estimated at $2.1 billion over the remaining life of the agreements, which are currently estimated to range up to 23 years. However, the LTSAs contain various cancellation provisions at the option of the purchasers. Georgia Power has also entered into a L TSA with GE through 2014 for neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently estimated at $6 million. The contract contains cancellation provisions at the option of Georgia Power. Payments made under the LTSAs prior to the performance of any work are recorded as a prepayment in the balance sheets. All work performed is capitalized or charged to expense (net of any joint owner billings), as appropriate based on the nature of the work. limestone Commitments As part of Southern Company's program to reduce sulfur dioxide emissions from its coal plants, the traditional operating companies have entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal bum and sulfur content. Southern Company has a minimum contractual obligation of 6.9 million tons, equating to approximately $282 million, through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $39 million in 2011, $40 million in 2012,$42 million in 2013,$43 million in 2014, and $29 million in 2015. 11-87 SoCo FOIA Response 001136 NOTES Ctontinued) Southern Comp1ny and Subsidiary Companies 2010 Annual Reporl Fuel and Purchased Power Commitments To supply a portion of the fuel requirements of the generating plants, Southern Company has entered into various long-term commitments for the procurement of fossil, biomass fuel, and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emissions allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2010. Also, Southern Company has entered into various long-term commitments for the purchase of capacity and electricity. Total estimated minimum long-term obligations at December 31 , 20 I 0 were as follows: Natural Gas Commitments Nuclear Fuel Biomass Fuel Coal Purchased Power* (irr millioru) 2011 2012 2013 2014 2015 20 16 and thereafter Total $1,357 1,226 1,054 908 779 3.413 $8,737 $ 3,810 1,882 1,362 873 783 1.798 $10,508 $ 335 207 220 208 141 807 $1,918 $ 14 18 18 18 110 $178 $ 260 269 237 268 291 2.439 $3,764 •ccnnin !'PAs rcflcclcd in 1hc lnblc ore nccoumed for as opcrulingleascs. Additional commitments for fuel will be required to supply Southern Company' s future needs. Total charges for nuclear fuel included in fuel expense amounted to $184 million in 2010,$160 million in 2009, and S 147 million in 2008. Coal commitments for Mississippi Power include a minimum annual management fee of$38 million beginning in 2014 from the executed 40-year management contract with Liberty Fuels, LLC related to the Kemper IGCC. Operating Lenses In 200 I , Mississippi Power began the initial I0-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership whose investors are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of Juniper's assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease agreement is treated as an operating lease for accounting purposes as well as for both retail and wholesale rate recovery purposes. The initial lease term ends in 20 II, and the lease includes a purchase and renewal option based on the cost of the facility at the inception of the lease. Mississippi Power is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. In April2010, Mississippi Power was required to notify the lessor, Juniper, if it intended to terminate the lease at the end of the initial term expiring in October 20 II. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the Plant Daniel combined cycle generating units for approximately $354 million or renew the lease for approximately $31 million annually for 10 years. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011 . If the lease is renewed, the agreement calls for Mississippi Power to amortize an additional 17% of the initial completion cost over the renewal period. Upon termination of the lease, at Mississippi Power's option, it may either exercise its purchase option or the facility can be sold to a third party. If Mississippi Power does not exercise either its purchase option or its renewal option, Mississippi Power could lose its rights to some or all of the 1,064 MWs of capacity at that time. The ultimate outcome of this matter cannot be determined at this time. The lease provides for a residual value guarantee, approximately 73% of the acquisition cost, by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is Jess than the unamortized cost of the asset. A liability of approximately $2 million, $3 million, and $5 million for the fair market value ofthis residual value guarantee is included in the balance sheets as of December 31,2010,2009, and 2008, respectively. Southern Company also has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $188 million, $186 million, and $184 million for 20 I 0, 2009, and 2008, respectively. Southern Company includes any step 11-88 SoCo FOIA Response 001137 NOTES (co•linutd) Soulhtrn Compan)' and S•bsidiary Companies 2010 Annual Rtporl rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. At December 31, 20 I 0, estimated minimum lease payments for noncancelable operating leases were as follows: Plant Daniel Minimum Lease Payments Barges & Rail Cars Other (ill mifliOIIS) 2011 2012 2013 2014 2015 2016 and thereafter Total $28 s 74 s 52 $28 58 48 39 14 16 $249 35 29 24 17 87 $244 Total $154 93 77 63 31 103 $521 For the traditional operating companies, a majority of the barge and rail car lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to the residual value ofthe leased property. These leases expire in 2011,2012,2013,2014,2015, and 2016 and the maximum obligations under these leases are $40 million, S I million, $39 million, $8 million, $5 million, and $4 million, respectively. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations. Guarantees As discussed earlier in this Note under "Operating Leases," Alabama Power, Georgia Power, and Mississippi Power have entered into certain residual value guarantees. 8. COMMON STOCK Stock Issued During 20 I 0, Southern Company issued 19.6 million shares of common stock for $629 million through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued 4.1 million shares of common stock through at-themarket issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of $143 million, net of $1 million in fees and commissions. In 2009, Southern Company raised $673 million from the issuance of22.6 million new common shares through the Southern Investment Plan and employee and director stock plans. In 2009, Southern Company issued 19.9 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of$613 million, net of$6 million in fees and commissions. Shares Reserved At December 31, 20 I 0, a total of 66 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (which includes stock options and performance shares units as discussed below). Of the total66 million shares reserved, there were 10 million shares of common stock remaining available for awards under the stock option and performance share plans as of December 31, 20 I0. Stock Option Plan Southern Company provides non-qualified stock options to a large segment of Southern Company system employees ranging from line management to executives. As of December 31, 20 I 0, there were 7,330 current and former employees participating in the stock option plan. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than I 0 years after the date of 11-89 SoCo FOIA Response 001138 NOTES (conlinutd) Soulhtrn Company ud Subsidiary Companits 2010 ,bnaal Rtporl grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting. The estimated fair values of stock options granted in 20 I0, 2009, and 2008 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company's stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Dividend yield Weighted average grant-date fair value 2010 I 7.4•/o 5.0 2.4% 5.6o/. $2.23 2009 15.6% 5.0 1.9% 5.4% $1.80 2008 13.1% 5.0 2.8% 4.5% $2.37 Southern Company's activity in the stock option plan for 2010 is summarized below: Outstanding at December 31, 2009 Granted Exercised Cancelled Outstanding at December 31, 20 I 0 Exercisable at December 31, 2010 Shares Subject To Option 48,247,319 9,582,288 (7,024, 176) (93,845) 50,711,586 34,564,434 Weighted Average Exercise Price $32.10 31.22 28.15 31.02 $32.48 $32.81 The number of stock options vested, and expected to vest in the future, as of December 31, 20 I 0 was not significantly different from the number of stock options outstanding at December 31, 2010 as stated above. As of December 31, 2010, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $292 million and $188 million, respectively. As of December 31, 20 I 0, there was $5 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately I 0 months. For the years ended December 31, 20 I 0, 2009, and 2008, total compensation cost for stock option awards recognized in income was $22 million, $23 million, and $20 million, respectively, with the related tax benefit also recognized in income of$9 million, $9 million, and $8 million, respectively. The total intrinsic value of options exercised during the years ended December 31, 2010,2009, and 2008 was $57 million, $9 million, and $45 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $22 million, $4 million, and $17 million for the years ended December 3 I, 2010, 2009, and 2008, respectively. Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 20 I 0, 2009, and 2008 was S 198 million, $19 million, and $113 million, respectively. Performance Share Plan In 20 I0, Southern Company implemented the performance share program under its omnibus incentive compensation plan, which provides performance share award units to a large segment of Southern Company system employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on 11·90 SoCo FOIA Response 001139 NOTES (ro•linurtl) Soulhrrn Comp1ny .nd Subsitlill')' Cum,.niH 2010 Annuli Rrporl Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount. The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. Expected volatility used in the model of20. 7% was based on historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate of 1.4% was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units. The annualized dividend rate at the time of the grant was $1.75. During 2010, 1,050,052 performance share units were granted with a weighted-average grant date fair value of$30.13. During 2010, 141 ,711 performance share units were forfeited resulting in 908,341 unvested units outstanding at December 31, 20 I 0. For the year ended December 31 , 20 I 0, total compensation cost for performance share units recognized in income was $9 million, with the related tax benefit also recognized in income of$4 million. As of December 31, 2010, there was $18 million of total unrecognized compensation cost related to performance share award units that will be recognized over the next two years. Diluted Earnings Per Share For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows: Average Common Stock Shares 2010 2009 2008 (in lhousonds) As reported shares Effect of options Diluted shares 832,189 4,792 836,981 794,795 1.620 796,415 771,039 3.809 774,848 Stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive were 13.1 million and 37.7 million at December 31, 2010 and 2009, respectively. Assuming an average stock price of$38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options would have increased by 0.8 million and 3.4 million shares for the years ended December 31,2010 and 2009, respectively. Common Stock Dividend Restrictions The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 20 I 0, consolidated retained earnings included $5.9 billion of undistributed retained earnings of the subsidiaries. Southern Power's credit facility contains potential limitations on the payment of common stock dividends; as of December 31, 20 I 0, Southern Power was in compliance with all such requirements. 9. NUCLEARINSURANCE Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of$375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of S17.5 mill ion per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests, is $235 million and $237 million, respectively, per incident, but not more than an aggregate of$35 million per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013. 11-91 SoCo FOIA Response 001140 NOTES (conlinard) Soulllrrn Companr ud Subsldinr Companirs 2010 Annual Rrporl Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' operating nuclear generating facilities. Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Alabama Power and Georgia Power each purchase the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period. A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion in limits for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $42 million and $70 million, respectively. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. 10. FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. • • • Level I consists of observable market data in an active market for identical assets or liabilities. Level 2 consists of observable market data, other than that included in Level I, that is either directly or indirectly observable. Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. 11-92 SoCo FOIA Response 001141 NOTES (ronain••lll Soulhtrn Comi'Ail)' llllli S•bsidiary Comp~nits 2010 Annual Rrporl As of December 31, 20 I 0, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: As of December 31,2010: Fnir Value Measurements Using Quoted Prices in Active Signilicnnt Other Signilicnnt Markets for Identical Observable Unobservable Assets Inputs Inputs (Levell) (Levell) (Levell) Total (in millions) Assets: Energy-related derivatives Interest rate derivatives Foreign currency derivatives Nuclear decommissioning trusts:1"1 Domestic equity U.S. Treasury and government agency securities Municipal bonds Corporate bonds Mortgage and asset backed securities Other Cash equivalents and restricted cash Other Total Liabi lilies: Energy-related derivatives Interest rate derivatives Total $ $ 604 20 351 9 $984 $$- 10 10 3 $ - $ 10 10 3 664 240 53 60 220 53 220 119 74 220 51 $820 19 $ 19 $206 I $207 $$- 119 74 351 79 $1,823 $206 I $207 (a) Includes the mveslment sccurittcs pledged to cred1tors and collateral n:ce1vcd. and excludes receivables related to investment income, pendens Investment sales, and payablcs related to pcndmg mvcstmcnt purchases and the lendmg pool Sec Note I under "Nuclear Decommissioning" for ooditional information Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note I I for additional information on how these derivatives are used. "Other investments" include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions. For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics. A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit 11-93 SoCo FOIA Response 001142 NOTES (rontlnutdl Soulhtrn Company and Sub•idiary Companlts 2010 Annual Rtport information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts' judgment are also obtained when available. As of December 31, 20 I0, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: As of December 31,2010: Fair Value Unfunded Commitments Redemption Frequency $65 67 86 None None None Daily Daily Daily Ito 3 days Not applicable 15 days 351 None Daily Not applicable 2 None Daily Not applicable Redemption Notice Period (inmi/liom) Nuclear decommissioning trusts: Corporate bonds -commingled funds Other- commingled funds Trust-owned life insurance Cash equivalents and restricted cash: Money market funds Other: Money market funds The commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset rate date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The corporate bonds- commingled funds represent the investment of cash collaleral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. See Note I under "Nuclear Decommissioning" for additional information. Alabama Power's nuclear decommissioning trust includes investments in Trust-Owned Life Insurance (TOLl). The 1axable nuclear decommissioning trust invests in the TOLl in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLl through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLl agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLl policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the Securities and Exchange Commission and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds. 11-94 SoCo FOIA Response 001143 NOTES (tonlinurd) Soulhnn Company and Subsidiary Companirs 2010 Annual Rrpor1 Changes in the fair value measurement of the Level3 items using significant unobservable inputs for the year ended December 31, 20 I 0 were as follows: Levell Other (ill millio11s) $35 Beginning balance at December 31, 2009 Total gains (losses)- realized/unrealized: Included in earnings Included in OCI Transfers out of Level 3 Ending balance at December 31,2010 (I) 5 (20) $19 Transfers in and out of the levels of fair value hierarchy are recognized as of the end of the reporting period. The value of one of the investments was reclassified from Level3 to Level I because the securities began trading on the public market. The reclassification is reflected in the table above as a transfer out of Level3 at its fair value. As of December 3 I, 20 I 0 and 2009, other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (illmillioru) Long-term debt: 2010 2009 $19,356 $19,145 $20,073 $19,567 The fair values were based on either closing market prices (Level I) or closing prices of comparable instruments (Level2). 11. DERIVATIVES Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities. Energy-Related Derivatives The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts. Certain of the traditional operating companies have recently started using significantly more financial options per the guidelines of their respective PSCs, which is expected to continue to mitigate price volatility. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the electric utilities may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the electric utilities may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. 11-95 SoCo FOIA Response 001144 NOTES (conlinutd) Soulbtrn Company and Sub,idiary Companies 2010 Annual R•porl Energy-related derivative contracts are accounted for in one of three methods: • • • Regulatory Hedges- Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies' fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. Cash Flow Hedges- Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. Not Designated- Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31 , 20 I 0, the net volume of energy-related derivative contracts for power and natural gas positions for the Southern Company system, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Power Longest Hedge Net Sold Date Megawatt-hours Longest Non-Hedge Date Gas Longest Hedge Date Longest Non-Hedge Date 2015 2015 (in milliotu) (ill millions) I Net Purchased mmDtu* 2011 2011 149 ' million British thermal units In addition to the volumes discussed in the tables above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 4 million mmBtu. For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending December 31, 20 II are immaterial for Southern Company. Interest Rate Derivatives Southern Company and certain subsidiaries also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset with any difference representing ineffectiveness. 11-96 SoCo FOIA Response 001145 NOTES (conlinurd) Soul bern Company and Subsidiuy Companies 2010 An..al Rrport At December 31, 20 I 0, the following interest rate derivatives were outstanding: Notional Amount Interest Rate Received Interest Rate Paid Fair Value Gain (Loss) December 31, 2010 Hedge Maturity Date (in millions) (in millions) CasII jlo111 fledges of e:l:isti11g debt $300 3-month LIBOR + 0.40% spread 1.24%* October 20 II 4.15% 3-month LIBOR + 1.96%* spread May 2014 $(1) Fair l•alue ltedges of e~:isti11g debt 350 Total 10 $ 9 $650 • Weighted Average For the year ended December 31, 20 I 0, the Company had realized net gains of $2 million upon termination of certain interest rate derivatives at the same time the related debt was issued. The effective portion of these gains has been deferred in OCI and is being amortized to interest expense over the life of the original interest rate derivative, reflecting the period in which the forecasted hedged transaction affects earnings. Subsequent to December 31, 20 I 0, Alabama Power entered into forward-starting interest rale swaps to mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million. The estimated pre-ta.x losses that wi II be reclassified from OCI to interest expense for the next 12-month period ending December 31, 20 II is $17 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2037. Foreign Currency Derivatives Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 20 I 0, the following foreign currency derivatives were outstanding: Notional Amount Hedge Maturity Date Fonvard Rate (inmi/Jion.s) Fair Value Gain (Loss) December 31, 2010 (in mi/Jion.s) Casltjlow ltedges offorecasted tra11sactio11s YEN82 85.326 Yen per Dollar• Various through May 2011 $- Various through July 2012 3 Fair value ltedges ofjirm commitmeltls EUR41.1 1.256 Dollars per Euro• $3 Total • Weighted Average 11-97 SoCo FOIA Response 001146 NOTES jronllnutdl Soullltrn Company and Subsidiary Companies 2010 Annual Rtporl Derivative Financial Statement Presentation and Amounts At December 31, 20 I 0 and 2009, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows: Derivative Catego!:I Asset Derivatives Balance Sheet Location 2010 Liabilit! Derivatives Balance Sheet Location 2010 2009 (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets Other deferred charges and assets Total derivatives designated as hedging instruments for re~;ulato!ll!ureoses Derivatives designated as hedging instruments In cash now and fair value hedges Energy-related derivatives: Interest rate derivatives: Foreign currency derivatives: Other current assets Other current assets Other deferred charges and assets Other current assets Other deferred charges and assets Total derivatives designated as hedging instruments in cash now and fair value hedges Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets Other deferred chaq~es and assets Total derivatives not designated as hed~;in~; instruments Total $4 2009 (ill mil/iOIIS) $1 3 $7 $2 S- $3 6 3 4 2 $13 $6 $2 $ 2 $3 $23 $2 SID Liabilities from risk management activities Other deferred credits and liabilities Liabilities from risk management activities Liabilities from risk management activities Other deferred credits and liabilities Liabilities from risk management activities Other deferred credits and liabilities $145 $111 55 66 $200 $177 $1 $5 6 $2 Liabilities from risk management activities Other deferred credits and liabilities $5 $5 $207 Sll $ 3 $3 $191 All derivative instruments are measured at fair value. See Note 10 for additional information. 11-98 SoCo FOIA Response 001147 NOTES (conlinutdl Soulhtm Company and Sub•idlary Companlt• 20t0 Annual Rtporl At December 31, 20 I 0 and 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: Unrealized Losses Balance Sheet Location 2010 Derivative Category 2009 Unrealized Gains Balance Sheet Location 2010 (i11 nrillioru) Energy-related derivatives: Other regulatory assets, current Other regulatory assets, deferred Total energy-related derivative gains (losses) 2009 (m nrillio11s) $(145) $(Ill) (55) $(200) $(177) (66) Other regulatory liabilities, current Other regulatory liabilities, deferred $4 $1 3 $7 $2 For the twelve months ended December 31, 20 I 0, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company's statement of income were $10 million. This amount was offset with changes in the fair value of the hedged debt. For the twelve months ended December 31, 20 I0, the pre-tax gains from foreign currency derivatives designated as fair value hedging instruments on Southern Company's statement of income were $3 million. These amounts were offset with changes in the fair value of the purchase commitment related to equipment purchases. For the years ended December 31, 20 I0, 2009, and 2008, the pre-tax effect of derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Hedging Relationshi(!S Derivative Categoa: Gain (Loss) Reclassified from Accumulated OCI into Income {Effective Portion} Amount Statements of Income Location 2009 2010 2008 Gain (Loss) Recognized in OCI on Derivative {Effective Portion} 2010 2009 2008 (irrmilliotrs) Energy-related derivatives Interest rate derivatives Foreign currencx derivatives Total $1 $(2) (3) (5) $(I) (47) 1 $~1! $(7) Fuel Interest expense, net of amounts capitalized Other o~rations and maintenance $(48) s - (25) I s !24! (i11 nrilliotrs) - $ $ - (46) ( 19) $(46) $(19) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 20 I0, 2009, and 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was as follows: Derivatives not Designated as Hedging Instruments Derivative Category Unrealized Gain (Loss} Recognized in Income Amount Statements of Income Location 2010 2009 2008 (ill nrilliotrs) Energy-related derivatives: Total Wholesale revenues Fuel Purchased power S(2) I $5 (6) m (4) $(2) $(5) $ (2) 5 (2) $I SoCo FOIA Response 001148 NOTES (continued) Soulbtrn Company and Subsidiary Companies 2010 Annual Report Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are cenain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of cenain Southern Company subsidiaries. At December 31, 20 I0, the fair value of derivative liabilities with contingent features was $40 million. At December 31, 20 I 0, the Company had no collateral posted with its derivative counterpanies. The maximum potential collateral requirement arising from the credit-risk-related contingent features, at a rating below BBB· and/or Baa3, is $40 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Included in these amounts are cenain agreements that could require collateral in the event that one or more Southern Company system power pool panicipants has a credit rating change to below investment grade. 11-100 SoCo FOIA Response 001149 NOTES (conlinutd) Soulhtrn Company and Subsidiary Companlts 2010 Annual Rtporl 12. SEGMENT AND RELATED INFORMATION Southern Company's reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Southern Power's revenues from sales to the traditional operating companies were $371 million, $544 million, and $638 million in 2010,2009, and 2008, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications, renewable energy projects, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows: Electric Utilities Trnditionnl Operating Coml!anies Southern Power Eliminations Total All Other Eliminations Consolidated (i11 millioru) 2010 Operating revenues Depreciation and amortization Interest income Interest expense Income taxes Segment net income (loss)* Total assets Gross (!ro(!erll: additions 2009 Operating revenues Depreciation and amortization Interest income Interest expense Inco me ta"~;cS Segment net income (loss)• Total assets Gross property additions $16,713 1,375 22 757 1,039 1,859 51,145 41029 $15,304 1,378 21 749 902 1,679 48,403 4.568 $1,129 119 $(468) 76 77 130 3,276 300 (128) $(609) $ 947 98 85 86 156 3,043 331 (143) 2008 s 1,314 $(835) Operating revenues $16,521 89 Depreciation and amortization 1,325 Interest income 32 I Interest expense 689 83 Income ta"~;es 944 93 Segment net income (loss)• 1.703 144 Total assets 44,794 (139) 2,813 50 4.058 Gross ~ro~ertl: additions • After dividends on preferred and preference stock of subsidiaries $17,374 1,494 22 833 1,116 1,989 54,293 4!329 $162 19 3 62 (90) (10) 1,279 114 $(80) $15,642 1,476 21 834 988 1,835 51,303 4.899 $ 165 27 3 71 (92) ( 193) 1,223 14 $(64) $17,000 1,414 33 772 1,037 1,847 47,468 4.108 s 182 29 94 (122) (104) 1,407 14 (I) (4) (540) (I) I (480) s (55) (I) (528) $17,456 1,513 24 895 1,026 1,975 55,032 4,443 $15,743 1,503 23 905 896 1,643 52,046 4.913 $17,127 1,443 33 866 915 1,742 48,347 4.122 Produc:ts and Services Year Retail Electric Utilities' Revenues Wholesale Other Total (ill millions) 2010 2009 2008 $14,791 13,307 14,055 $1,994 1,802 2,400 $589 533 545 $17,374 15,642 17.000 11-101 SoCo FOIA Response 001150 NOTES (ro••i•urd) Soulhrm Company and Subsidiary Comp..ir• 2010 Annual Rrporl 13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial data for 20 I0 and 2009 are as follows: Quarter Ended Operating Revenues March 2010 June 2010 September 2010 December 2010 $4,157 4,208 5,320 3,771 March 2009 June 2009 September 2009 December 2009 $3,666 3,885 4,682 3,510 Operating Income (ill Consolidated Per Common Share Net Income After Dividends on Trading Preferred and Price Range Preference Stock Basic of Subsidiaries Earnings Dividends High Low mi/lioru) s 922 951 1,459 470 $495 510 817 153 $0.60 0.62 0.98 0.18 $0.4375 0.4550 0.4550 0.4550 $33.73 35.45 37.73 38.62 $30.85 32.04 33.00 37.10 $ 490 886 1,415 477 $126" 478 790 249 $0.16" 0.61 0.99 0.31 $0.4200 0.4375 0.4375 0.4375 $37.62 32.05 32.67 34.47 $26.48 27.19 30.27 30.89 Southern Company's bus1ness IS mnucnccd by seasonal weather cond111ons • Southern Company's MC Asset Recm·cry ht1gat10n setllement reduced eammgs by S202 mllhon, or 25 ccniS per share, during the first quarter 2009 11- 102 SoCo FOIA Response 001151 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA For the l'eriods Ended December 2006 through 2010 Southern Company and Subsidiary Companies 2010 Annual Report 2010 Operating Revenues (in millions) $17,456 Total Assets (in millions) $55,032 $4,443 Gross Property Additions (in millions) Return on Average Common Equity {pmtnl) 12.71 $1.8025 Cash Dividends Paid Per Share of Common Stock Consolidated Net Income Arter Dividends on Prderred and Preference $1,975 Stock of Subsidiaries (in millioM) Earnings Per Share$2.37 Basic Diluted 2.36 Capitalization (in millions): Common stock equity 16,202 Preferred and preference stock of subsidiaries 707 Redeemable preferred stock of subsidiaries 375 Lon~;~·term debt 18,154 Total !cxcludin~ amounts due within one vcarl $35!438 Capitalization Ratios (percent): Common stock equity 45.7 Preferred and preference stock of subsidiaries 2.0 Redeemable preferred stock of subsidiaries 1.1 Lons·term debt 51.2 Total lc•tluding amounts due " i thin one ,·carl 100.0 Other Common Stock Data: Book value per share $19.21 Market price per share: High $38.62 Low 30.85 Close (year-cnd) 38.23 Market-to-book ratio (year·cnd) (pttccnt) 199.0 Price-earnings ratio (year-cnd) (times) 16.1 Dividends paid (in millions) $1,496 Dividend yield (ycor.cnd) (ptrcent) 4.7 Dividend payout ratio (pttccnt) 75.7 Shares outstanding (in thous:~nds): Average 832,189 Year-end 843,340 160,426* Stockholders of record l port oflhcsc fi~W~CiiiiSIon·rrCompany 2010 Annual Rrporl As of December 31,2009: Fair Value Measurements Using Quoted Prices in Active Significant Significant Markets for Other Identical Observable Unobservable Assets Inputs Inputs {Level 1) {Level3) {Level2) Total (mnullum.t) Assets: Domestic equity• International equity• Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private eguit~ Total Liabilities: Derivatives Total $339 439 $141 44 $ $ 480 483 127 34 85 3 104 127 34 85 3 lOS 53 $832 $538 166 169 $335 219 169 $1,705 $538 $335 $1,704 (I) (I) $831 •Level t securities consist of actively traded stocks wh1le Levet2 securities consiSt of pooled funds. Management believes thatlhe portfolio 1s well diversified with no significant concentrations ofnsk Changes in the fair value measurement of the Level3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 20 I 0 and 2009 were as follows: 2010 Real EstAte Investments Private Eguit~ 2009 ReAl Estate Investments Private Egui!): (ill millio11s) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the ~ear Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $166 Sl69 14 9 3 3 17 12 (I) 8 $191 $180 $254 (72) (20) (92) 4 $166 $148 13 3 16 5 $169 The fair values of other postretirement benefit plan assets as of December 31, 20 I 0 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. 11-156 SoCo FOIA Response 001205 NOTES (conlinuedl Alabama Power Company 2010 Annual Report As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Other Significant Markets for Identical Observable Unobservable Inputs Inputs Assets (Leve13) (Levell) (Lcve12) Total (in millimu) Assets: Domestic equity• International equity• Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Special situations Real estate investments Private equity Total $62 19 $ 7 6 $ - $ 69 25 5 4 9 3 24 159 5 4 9 3 24 159 3 $84 $217 10 9 $19 13 9 $320 •Level I securities consist ofacuvcly traded sloc~s wh1le Lcvcl2 secur11ies consist of pooled funds. Management believes that the ponfolio is well diversified with no sigmficant conccnlrnllons ofris~ As of December 31. 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant ldenticnl Observable Unobservable Inputs Assets Inputs (Levell) (Level2) (Level3) Total (in millwru) Assets: Domestic equity• International equity* Fixed income: U.S. Treasury, government, and agency bonds Mongage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Special situations Real estate investments Private equity Total $54 24 $ 8 2 - s 62 26 7 2 5 7 2 5 23 144 23 144 3 $81 $ $191 9 10 $19 12 10 $291 "Level I securities consist of actively traded stocks while Level 2 securities consist of pooled funds Management believes that the por1foho is well diversified with no significant concentrations of risk. 11-1.57 SoCo FOIA Response 001206 NOTES (co•li•urd) Alab•m• PowrrComp••r 2010 An•••l Rrporl Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 3 I, 20 I0 and 2009 were as follows: 2010 Real Estate Investments Private Equity $ 9 $10 2009 Real Estate Investments Private Equity (itr nril/iorrs) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $15 (5) $8 2 (I) (6) 2 (I) SIO s9 $9 SIO Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2010,2009, and 2008 were $18 million, S 19 million, and S18 million, respectively. 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company's financial statements. Environmental Matters New Source Review Actiotrs In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to each of the traditional operating companies. After the Company was dismissed from the original action, the EPA filed a separate action in January 200 I against the Company in the U.S. District Court for the Northern District of Alabama. In the lawsuit against the Company, the EPA alleges that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil action requests penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of2001, and the case has not been reopened. The separate action against the Company is ongoing. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving a portion of the Company's lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of the Company with respect to its 11·1 58 SoCo FOIA Response 001207 NOTES (contin••dl ,\lab1ma rower Compla)· 2010 Annu1l Rnr Comp..y 2010 ,\ . .ual Rrporl Otfler Operatio11s ami llfailltellullce E:-:pe11se.f In 20 I0, other operations and maintenance expenses increased $240 million, or 16.1 %, compared to 2009. The increase was due to increases of$ I42 million in power generation, $74 million in transmission and distribution, and $25 million in customer accounting, service, and soles due to cost containment efforts in 2009 as a result of economic conditions. The increase in power generation operations and maintenance expenses was also due to higher generation levels to meet increased customer demand in 20 I 0. In 2009, other operations and maintenance expenses decreased $88 million, or 5.5%, compared to 2008. The decrease was due to a $46 million decrease in power generation, a $28 million decrease in transmission and distribution, and a $32 million decrease in customer accounting, service, and sales, most of which were related to cost containment activities in an effort to offset the effects of the recessionary economy. In 2008, olher operations and maintenance expenses increased $21 million, or 1.2%, compared to 2007. The increase was primarily the result of a $15 million increase in the accrual for property damage approved under the 2007 Retail Rate Plan, a $15 million increase in scheduled outages and maintenance for fossil generating plants, and a $22 million increase related to meter reading, records and collections, and uncollectible account expenses. These increases were partially offset by decreases of$25 million related to the timing of transmission and distribution operations and maintenance and $7 million related to medical, pension, and other employee benefits. Depreclatio11 a11d Amllrtizatioll Depreciation and amortization decreased $97 million, or 14.8%, in 2010 compared to the prior year. This decrease was primarily due to a $133 mill ion increase in amortization of the regulatory liability related to other cost of removal obligations, as authorized by the Georgia PSC, partially oiTset by increased depreciation related to additional plant in service related to transmission, distribution, and environmental projects. See FUTURE EARNINGS POTENTIAL- "PSC Matters- Rate Plans" herein, Note I to the financial statements under "Depreciation and Amortization," and Note 3 to the financial statements under "Retail Regulatory Matters - Rate Plans" for additional informalion. Depreciation and amortiwtion increased $18 million, or 2.9%, in 2009 compared to the prior year primarily due to additional plant in service related to transmission, distribution, and environmental projects, partially oiTset by the amortization of $41 million of the regulatory liability related to other cost of removal obligations. Depreciation and amortiwtion increased $126 million, or 24.6%, in 2008 compared to the prior year primarily due to an increase in plant in service related to completed transmission, distribution, and environmenlal projects, changes in depreciation rates eiTective January I, 2008 approved under the 2007 Retail Rate Plan, and the expiration of amortiwtion related to a regulatory liability for purchased power costs under the terms ofthe relail rate plan for I he three years ended December 3 I, 2007. TILI:t!.f Otfler Tfla11 IIICfJIIIt! TILI:t!.f In 2010, taxes other than income taxes increased $27 million, or 8.5%, from the prior year primarily due to higher municipal franchise fees resulting from retail revenue increases during 20 I0. In 2009, the increase in taxes other than income taxes was immaterial. In 2008, taxes other than income taxes increased $24 million, or 8.6%, from the prior year primarily due to higher municipal franchise fees resulting from retail revenue increases during 2008. Allmvullcefllr Ftmds Used Duri11g Cmt.flrltclimt Eq11ity Allowance for funds used during construction (AFUDC) equity increased $50 million, or 51 .5%, in 2010 primarily due to the increase in construction related to three new combined cycle units at Plant McDonough, two new nuclear generating units at Plant Vogtle (Plant Vogtle Units 3 and 4), and ongoing environmental and transmission projects. In 2009,the increase in AFUDC equity as compared to 2008 was immaterial. AFUDC equity increased $27 million, or 39.8%, in 2008 primarily due to the increase in construction related to ongoing environmental and transmission projects, as well as the new units at Plant McDonough. See FUTURE EARNINGS POTENTIAL- "Construction" herein and Note 3 to the financial statements under "Construction" for additional information. 11·1&'9 SoCo FOIA Response 001238 MANAGEMENT'S DISCUSSION AND ANALYSIS (conlin•rlll GrorJll• Po10·rr Company 2010 Annual Rtporl l11tere.ft Expe11se, Net ofAmou11ts Cupitalizetl In 2010, interest expense, net of amounts capitalized decreased $11 million, or 2.8%, primarily due to a $14 million increase in interest capitalized in 20 I 0 compared to the prior year. In 2009, interest expense, net of amounts capitalized increased $41 million, or 11 .7%, primarily due to an increase in long-term debt levels resulting from the issuance of additional senior notes and pollution control bonds to fund the Company's ongoing construction program. The increase in interest expense in 2008 as compared to 2007 was immaterial. Otl1er l11come (Expe11se), Net Other income (expense), net decreased $20 million in 20 I0 primarily as a result of lower revenues of $9 million from non-operating activities and increased donations of$5 million. Other income (expense), net increased $7 million, or 80.8%, in 2009 primarily related to $2 million and $1 million increases in customer contracting and income resulting from purchases by large commercial and industrial customers of hedges against market-response roles, respectively, and a decrease of$2 million in donations. Other income (expense), net decreased $23 million, or 163.0%, in 2008 primarily due to a $13 million change in classification of revenues related to a residential pricing program to base retail revenues in 2008 as ordered by the Georgia PSC under the 2007 Retail Rate Plan, as well as decreased revenues of$7 million and $3 million related to non-operating rental income and customer contracting, respectively. lllctlme Taxes Income taxes increased $43 million, or 10.5%, in 2010 primarily due to higher pre-tax earnings, partially offset by increases in nontaxable AFUDC equity and state tax credits. Income taxes decreased $78 million, or 15.9%, in 2009 primarily due to changes in pretax income. Income taxes increased $70 million, or 16.8%, in 2008 primarily due to increased pre-tax net income and the effect of deductions for the Company's donation of2,200 acres in the Tallulah Gorge area to the State of Georgia in 2007. This increase was partially offset by an increase in AFUDC equity, as well as additional state tn." credits and an increase in the federal production activities deduction. Effects of In nation The Company is subject to rote regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years. FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers arc set by the Georgia PSC under cost-based regulatory principles. Prices for electricity relating to wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and revenues are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES - " Application of Critical Accounting Policies and Estimates - Electric Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters. The results of operations for the past three years arc not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the Company' s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service area. Changes in economic conditions impact sales for the Company, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. 11· 190 SoCo FOIA Response 001239 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gtol'l:il Po,·tr Comp1ny 2010 Annuli Rtporl Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. The Company's environmental compliance cost recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. New Source Re1•if!lll Aclitms In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-lired generating facilities. The action was filed concurrently with the issuance of a notice of violation of the NSR provisions to the Company. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against the Company, has been administratively closed since the spring of 200 I, and the case has not been reopened. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008,the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 20 I0, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 20 I0. The court has set a trial date for October 20 II for any remaining claims. The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of$25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot now be determined. Curbtm Ditu:ide Litigatim1 New York Ca.w: In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company's service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies' emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (I) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company's and the other defendants' motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court's ruling, vacating the dismissal of the plaintiffs' claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants' petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. 11- 191 SoCo FOIA Response 001240 MANAGEMENT'S DISCUSSION AND ANALYSIS fronlinurdl Groi'J:ial'owrr Company 2010 Annuall{rporl Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina liled a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies. and a coal company. The plaintiffs are the governing bodies of an lnupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs' damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants' motions to dismiss the case based on lack ofjurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs' failure to establish the standard for determining that the defendants' conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court's order dismissing the case. On January 24, 20 II, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil. coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs' appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January I0, 20 II, the U.S. Supreme Court denied the plaintiffs' petition to reinstate the appeal. This case is now concluded. Em•irmtme11tu/ Statute.~ uml Regu/uti1111.~ General The Company's operations arc subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 20 I 0, the Company had invested approximately $3.7 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of $217 million, $440 million, and $689 million for 20 I 0, 2009, and 2008, respectively. The Company expects that capital expenditures to comply with existing statutes and regulations will be $73 million. $79 million. and $58 million in 2011,2012, and 2013, respectively. These environmental costs that are known and estimable at this time are included under the heading "Capital" in the table under FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements and Contractual Obligations" herein. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $69 million to $289 million in 2011, $191 million to $65 I million in 2012, and $476 million to $1.4 billion in 2013. The Company's compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of any new or revised environmental statutes and regulations that are enacted, including the proposed environmental legislation and regulations described below; the cost, availability, and existing inventory of emissions allowances; and the Company's fuel mix. Compliance with any new federal or state legislation or regulations relating to global climate change, air quality, coal combustion byproducts, including coal ash, water quality, or other environmental and health concerns could also significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company' s operations, the full 11-192 SoCo FOIA Response 001241 MANAGEMENT'S DISCUSSION AND ANALYSIS (continucdl Gco11:ia l'ower Company 2010 Annual Report impact of any such changes cannot be detennined at this time. Additionally, many of the Company's commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2010,the Company had spent approximately $3.4 billion in reducing sulfur dioxide (S01 ) and nitrogen oxide (NO,) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional conlrols are currently planned and others are under consideration to further reduce air emissions, maintain complinnce with existing regulntions, nnd meet new requirements. The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone air quality standard. A 20county area within metropolitan Atlanta is the only location within the Company's service area that is currently designated as nonattainment for the current standard. On November 30, 20 I0, the EPA extended the attainment date for this area by one year as a result of improving air quality. In March 2008, the EPA issued a linal rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the level of the standard. Under the EPA's current schedule, a linal revision to the eight-hour ozone standard is expected in July 20 II, with state implementation plans for any resulting nonattainment areas due in mid-20 14. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within the Company's service territory and could result in additional required reductions in NO, emissions. During 2005, the EPA's annual line particulate matter nonattainment designntions became effective for several areas within the Company's service area. State implementation plans demonstrating attainment with annual standards have been submitted to the EPA. The EPA is expected to propose new annualnnd 24-hour line particulate matter standards during the summer of2011. Final revisions to the National Ambient Air Quality Standard for S02 , including the establishment of a new one-hour slandard, became effective on August 23, 20 I0. Since the EPA intends to rely on computer modeling for implementation of the S0 2 standard, the identilication of potential nonattainment areas remains uncertain and could ultimately include areas within the Compnny's service territory. Implementation of the revised S0 1 standard could result in additional required reductions in S02 emissions and increased compliance and operation costs. Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (N02), which established a new one-hour standard, became effective on April 12, 20 I0. Although none of the areas within the Company's service territory are expected to be designated as nonattainment for the N02 standard, based on current ambient air quality monitoring data, the new N02 standard could result in significant additional compliance and operational costs for units that require new source permitting. Twenty-eight eastern states, including the States ofGeorgin and Alabama, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO, and/or S0 2 to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects ofCAIR, but left CAlR compliance requirements in place while the EPA develops a revised rule. The States of Georgia and Alabama have completed their plans to implement CAIR, and emissions reductions are being accomplished by the installation nnd operation of emissions controls at the Company's coal-lired facilities and/or by the purchase of emissions allowances. On August2, 2010, the EPA published a proposed rule, referred to as the Transport Rule, to replace CAIR. This proposed rule would require 31 eastem states and the District of Columbia (D.C.) to reduce power plant emissions of S01 and NO, that contribute to downwind states' nonattainment of federal ozone and/or line particulate matter ambient air quality standards. To address line particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Georgia and Alabama, to reduce annual emissions of SO~ and NO, from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Georgia and Alabama, to achieve additional reductions in NO, emissions from power plants during the ozone season. The proposed Transport Rule contains a "preferred option" that would allow limited interstate trading of emissions allowances; however, the EPA also requested comment on two allernative approaches that would not allow interstate trading of emissions allowances. The EPA stated that it also intends to develop a second phase of the Transport Rule in 20 II to address the more stringent ozone air quality standards after they are finalized. The EPA expects to finalize the Transport Rule in June 20 II and require compliance beginning in 2012. The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrolit Technology 11-193 SoCo FOIA Response 001242 MANAGEMENT'S DISCUSSION AND ANALYSIS ( The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expecled return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. Key elements in determining the Company's pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company's investment strategy, hislorical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. The Company discounts the future cash nows related to its postretiremenl benefit plans using a single-point discount rate developed from lhc weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. A 25 basis point change in any significant assumption would result in a $9 million or less change in total benefit expense and a $112 million or less change in projected obligations. FINANCIAL CONDITION AND LIQUIDITY Overview The Company's financial condition remained stable at December 31,2010. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Sec "Sources of Capital" and "Financing Activities" herein for additional information. The Company's investments in the qualified pension plan and the nuclear decommissioning trust funds remained stable in value as of December 31, 20 I0. In December 20 I0, the Company contributed $168 million to the qualified pension plan. The Company will fund approximately $3 million, $2 million, and $2 million to its nuclear decommissioning trust funds in 2011.2012, and 2013, respectively. Net cash provided from operating activities totaled S1.8 billion in 20 I0, an increase of $429 million from 2009, primarily due to a S 136 million increase in net income, fuel inventory reductions in 20 I0 compared to additions in 2009, and a net increase of $94 million in deferred and prepaid income taxes primarily due to the extension of bonus depreciation and the change in the tax accounting method for repair costs (See FUTURE EARNINGS POTENTIAL - "Income Tax Matters - Tax Method of Accounting For Repairs" and "Bonus Depreciation" herein), partially offset by the contributions to the qualified pension plnn. Net cash provided from operating activities totaled $1.4 billion in 2009, a decrease of $310 million from 2008, primarily due to an $89 million decrease in net income, a reduction in deferred revenues of approximately $172 million, a reduction in accrued compensation of approximately $123 million, and an increase in fuel inventory additions of approximately $150 million, partially offset by a reduction in accounts receivable of approximately $210 million. Net cash provided from operating activities totaled $1.7 billion in 2008, an increase of 11-203 SoCo FOIA Response 001252 MANAGEMENT'S DISCUSSION AND ANALYSIS (co•tlnurdl Gro'lli• Power Comp•ny 2010 An•u•l Report $279 million from 2007, primarily due to higher retail operaling revenues partially offset by higher inventory additions. Net cash used for investing activities totaled $2.2 billion, $2.4 billion, and $1.9 billion in 20 I0, 2009, and 2008, respectively, due to gross property additions primarily related to installation of equipment to comply with environmental standards; construction of generation, transmission, and distribution facilities; and purchase of nuclear fuel. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, capital contributions from Southern Company, and the issuance of debt. Net cash provided from financing activities totaled $391 million, $881 million, and $310 million for 20 I0, 2009, and 2008, respectively. These totals arc primarily related to additional issuances of senior notes and capital contributions from Southern Company in all years. The statements of cash flows provide additional details. See "Financing Activities" herein. Significant balance sheet changes in 2010 include a $1.6 billion increase in total property, plant, and equipment related to the construction activities discussed above. Other significant balance sheet changes in 20 I0 include an increase in paid-in capital of$698 million reflecting equity contributions from Southern Company. Significant balance sheet changes in 2009 include a $1.9 billion increase in total property, plant, and equipment and a $776 million increase in long-term debt to provide funds for the Company's continuous construction program. The Company's ratio of common equity to total capitalization, including short-term debt, was 48.8% in 20 I0 and 47.8% in 2009. Sec Note 6 to the financial statements for additional information. Sources of Capital Except as described below with respect to potential DOE loan guarantees, the Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend on prevailing market conditions, regulatory approvals, and other factors. On June 18, 20 I0, the Company reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future borrowings by the Company related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to the Company and secured by a first priority lien on the Company's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of70% of eligible project costs or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the COL for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for the Company. See FUTURE EARNINGS POTENTIAL- "Construction- Nuclear" herein and Note 3 to the financial statements under "Construction - Nuclear" for more information on Plant Vogtle Units 3 and 4. The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of short· term debt securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company Iiles registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended. The amounts of securities authorized by the Georgia PSC and the FERC arc continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. The Company's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source for under recovered fuel costs and to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, at December 31, 20 I0 the Company had credit arrangements with banks totaling $1.7 billion. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. In addition, the Company has substantial cash flow from operating activities and access to capital markets, induding a commercial paper program, to meet liquidity needs. 11-204 SoCo FOIA Response 001253 MANAGEMENT'S DISCUSSION AND ANALYSIS l~ontinutdl Gto'l:i• Powtr Company 2010 Annual Rtport At December 31,2010, bank credit arrangements were as follows: Total Unused Expires 2011 2012 (ill millions) $1,715 $1,703 $595 $1,120 Of the credit arrangements that expire in 2011,$40 million allow for the execution of term loans for an additional two-year period, and $220 million allow for execution of term loans for a one-year period. These credit arrangements provide liquidity support to the Company's variable rate pollution control revenue bonds and commercial paper borrowings. As of December 31, 20 I 0, the Company had $385 million outstanding pollution control revenue bonds requiring liquidity support. Subsequent to December 31,2010, the Company's remarkeling of$137 million of variable rate pollution control revenue bonds increased the tolal requiring liquidity support to $522 million. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from issuances for the benefit of any other operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support. As of December 31, 20 I 0, the Company had $5 75 million of outstanding commercial paper. During 20 I0, the maximum amount of commercial paper outstanding was $575 mi Ilion and the average amount outstanding was $167 million. During 2009, the maximum amount of commercial paper outstanding was $7S7 million and the average amount outstanding was $348 million. The weiglued average annual interest rate on commercial paper in 20 I 0 and 2009 was 0 .3% and 0.4%, respectively. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash. Financing Activities In March 20 I 0, the Company issued $350 mill ion aggregate principal amount of Series 20 IOA Floating Rate Senior Notes due March 15, 2013. The net proceeds were used to repay at maturity $250 million aggregate principal amount of Series 2008A Floating Rate Senior Notes due March 17, 20 I 0, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including the Company's continuous construction program. In June 2010, the Company issued $600 million aggregate principal amount of Series 20 lOB S.40% Senior Notes due June I, 2040. The net proceeds from the sale of the Series 20 I OB Senior Notes were used for the redemption of all of the $200 million aggregate principal amount of the Company's Series R 6.00% Senior Notes due October IS, 2033 and all of the $150 million aggregate principal amount of the Company's Series 0 5.90% Senior Notes due April 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including the Company's continuous conslruction program. In September 2010, the Company issued $SOO million aggregate principal amount Series 20 I OC 4.75% Senior Notes due September I, 2040. The'llet proceeds were used to redeem all of the $250 million aggregate principal amount of the Company's Series X S.70% Senior Notes due January I5, 204S, $125 million aggregate principal amount of the Company's Series W 6.00% Senior Notes due August IS, 2044, $100 million aggregate principal amount of the Company' s Series T S.7S% Senior Public Income Notes due January I5, 2044, and $3S million aggregate principal amount of the Company's Series G 5.7S% Senior Notes due December I, 2044. Also in Seplember 2010, the Company issued $SOO million aggregate principal amount Series 2010D 1.30% Senior Notes due September 15,2013. l11e net proceeds were used for the repurchase of all of the $114 million aggregate principal amount of outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2009, due January I, 2049; $40 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2009, due January I, 2049; $173 million aggregate principal amount ofthe outstanding Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009, due December I, 2032; $89 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2009, due October I, 2048; and $46 million aggregate principal amount of the outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1996, due October I, 2032, and for other general corporate purposes, including the Company's continuous 11-205 SoCo FOIA Response 001254 MANAGEMENT'S DISCUSSION AND ANALYSIS (contlnutdl Gto'lll• l'o'l\u Company 2010 A•nu•l Rtpurl conslruclion program. The pollution control revenue bonds repurchased by the Company are being held by the Company and may be remarketed to investors in the future. In December 2010, the Development Authority of Floyd County issued $53 million aggregate principal amounl Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2010 (the 2010 Bonds) for the benefit of the Company, and the 20 I0 Bonds were purchased by the Company. The proceeds from the issuance of the 20 I0 Bonds were used in December 2010 to purchase and cancel the $53 million aggrcgale principal amount Development Authority of Floyd County Pollution Control Revenue Bonds (Georgia Power Company PlanI Hammond Project), First Series 2008. In January 20 II, the Company rcmarkcted lhe 2010 Bonds to investors. Also subsequent to December 31,2010, the Company issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay a portion of the Company's outstanding short-term indebledness and for general corporale purposes, including lhe Company's continuous conslruclion program. In add ilion lo any finnncings thai may be necessary lo rneel capital requiremenls and conlractual obligalions, lhe Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Credit Rating Risk The Company docs nol have any credit arrangements that would require malerial changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts I hat could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. At December 31,2010, the maximum potential collateral requirements under these contracts 111 a BBB- and/or Ban3 rating were approximalely $27 million. At December 31,2010, the maximum potential collateral requirements under these contracts at 11 rating below BBB- and/or Baa3 were approximately $1.4 bill ion. Included in these amounts nrc certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or c11sh. Additionally, any credit rating downgrade could impact the Company's ability to access capital markets, particularly the short-term debt market. On August 12,2010, Moody's Investors Service (Moody's) downgraded the issuer and long-term debt ratings of the Company (senior unsecured to A3 from A2). Moody's also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of several Southern Company subsidiaries (including the Company) to P-2 from P-1. In addition, Moody's announced chat it had downgraded lhe variable rate demand obligation ratings of the Company to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of the Company to Baa2 from Ban I. Moody's also downgraded the trust preferred securities rating of the Company to Baal from A3. Moody's also announced that the ratings outlook for the Company is stable. On December 22, 20 I0, Fitch Ratings, Inc. announced that the ratings outlook of the Company had been revised from ncgati ve to stable. Market Price Risk Due to cost-based rate regulation and other various cosl recovery mechanisms, the Company continues to have limited exposure to market rate volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attribulablc to these exposures the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions nrc monitored using techniques including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis. To mitigate future exposure to changes in interest rates, the Company enters into derivatives that have been designated as hedges. The weighted average interest rate on $1.0 billion of outstanding variable rate long-term debt at January I, 2011 was 0.57%. If the Company sustained a I00 basis point change in interest rates for all unhedgcd variable rate long-term debt, the change would affect annualized interest expense by approximately $10 million at January I, 2011. For further information, see Note I to the financial 11-206 SoCo FOIA Response 001255 MANAGEMENT'S DISCUSSION AND ANALYSIS (ttontinurtll Gttoi"J:ia l'owtr Company 2010 Annual Rtporl statements under "Financial Instruments" and Note II to the financial statements. To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The Company continues to manage a fuel hedging program implemented per the guidelines of the Georgia PSC. The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the years ended December 31 were as follows: 2010 2009 Changes Changes Fair Value (i11 millirms) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes(•l Contracts outstanding at the end of the period, assets (liabilities), net $ $ (75) 85 $ (110) (100) $ ( 113) 150 ( 112) (75) Ia) Current period changes also include the changes in fair value of new contracts entered into during the pcritltl, if any The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 20 I0 was a decrease of$25 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 20 I0, the Company had a net hedge volume of 58.7 million mmBtu with a weighted average contract cost approximately $1.74 per mmBtu above market prices, and 64.6 million mmBtu at December 31, 2009 with a weighted average contract cost approximately $1.16 per mmBtu above market prices. All natural gas hedges gains and losses are recovered through the Company's fuel cost recovery mechanism. At December 31,2010 and 2009, substantially all of the Company's energy-related derivntive contracts were designated as regulatory hedges and are related to the Compnny's fuel hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery mechanism. Gains and losses on energy-related derivative contracts that are not designated or fnilto qualify as hedges arc recognized in the statements of income as incurred and were not material for any year presented. The Company uses over-the-counter contracts that arc not exchange traded but arc fair valued using prices which are actively quoted, and thus fall into Lcvcl2. Sec Note 10 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall11t December 31, 20 I0 were ns follows: Total Fair Value December 31, 2010 Fair Value Measurements Mnturity Years 4&5 Year I Years 2&3 (ill millimts) Level I Level 2 Level 3 Fair value of contracts outstanding at end of period $ $ $ ( 100) (77) $ (100) $ (77) $ (23) $ (23) $ The Comp11ny is exposed to market price risk in the event of nonperformance by counterparties to the energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that h11ve investment grade credit ratings by Moody's and Standard & Poor's, a division of The McGraw Hill Companies, Inc., or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note I to the financi11l statements under "Financial Instruments" nnd Note II to the financial st11tements. SoCo FOIA Response 001256 MANAGEMENT'S DISCUSSION AND ANALYSIS (tontinutdl Gtol'lli• Po"u Comp ..y 2010 Annul Rtporl The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulnlions lo implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of overthe-counter derivalives. The impact, if any, cannot be determined until regulations are finalized. CApital Requirements And ContractuAl Obligations The construction program of the Company is currently eslimaled lo include a base level inveslment of$2.1 billion, $2.2 billion, and $2.0 billion for 2011,2012, and 2013, respectively. Included in lhcse estimated amounts are environmental expenditures to comply with cxisling statutes and rcgulalions of $73 million, $79 million, and $58 million for 20 II, 2012, and 2013, respectively. In addition, the Company currently estimates that potential incremental inveslments to comply wilh anticipaled new environmenlal regulations could range from $69 million lo $289 million in 20 II, $191 million to $651 million in 2012, and $476 million to $1.4 billion in 2013. The construction program is subject to periodic review and revision, and aciUal construction costs may vary from these estimales because of numerous factors. These faclors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; slonn impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See No1e 3 and Note 7 to the financial stalemenls under "Construction- Nuclear" and "Construction Program," respectively, for additional information. As a result of requirements by the NRC, the Company has established external trust funds for nuclear decommissioning costs. For additional information, sec Note I to the financial statements under "Nuclear Decommissioning." In addition, as discussed in Note 2 lo the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC and the FERC. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments arc detailed in the contractual obligations table that follows. See Notes I, 6, 7, and II to the financial statements for additional infom1ation. 11-208 SoCo FOIA Response 001257 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gto11:ia l'owtr Company 2010 Annual Rtporl Contractual Obligations 20122013 2011 20142015 Afier 2015 Uncertain Timing ldl Total (in million•) Long-term debt1"1 Principal $ Interest Preferred and preference stock dividends1b1 Energy-related derivative obligations<<• Operating leases Capital leases Unrecognized tax benefits and interest
rtfolio is welldiversified with no significant concentrations of risk. 11-234 SoCo FOIA Response 001283 NOTES fconti•.nd) GtofJ:il t•owrr Comp..y 20t0 ,hnu.l Rtporl Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 20 I0 and 2009 are as follows: 2009 2010 Real Estate Investments Private Equity Real Estate Investments Private Equity (illmillimu) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on inwstmcnts Purchases, sales. and settlements Transfers into/out of Level 3 Ending balance s 8 s 8 $ 12 $ 7 (3) (I) (4) $ 8 s 8 $ 8 $ 8 Employee Savings Plan The Company also sponsors a 40 I (k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee' s base salary. Total matching contributions made to the plan for 2010, 2009, and 2008 were $23 million, $25 million, and $25 million, respectively. 3. CONTINGENCIES AND REGULATORY MATIEitS General Litigntion Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, hove become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management docs not anticipate that the liabilities, if any, arising from such current proceedings would haven material adverse effect on the Company's financial statements. Environmental Matters New Smtrce Re1•iew Aclitms In November 1999,the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related slate laws at certain coal-fired generating facilities. The action was filed concurrently with the issuance of a notice of violation of the NSR provisions to the Company. Afier Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against the Company, has been administratively closed since the spring of 200 I, and the case has not been reopened. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore nrc excluded from NSR permitting. On September 2, 20 I 0, the EPA dismissed five of its eight remaining claims against 11-235 SoCo FOIA Response 001284 NOTES (continued) GeorJ:ia l'ower Company 2010 Annual Report Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 20 I0. The court has set a trial date for October 20 II for any remaining claims. The Company believes that it complied wilh applicable Jaws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of$25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash nows, and financial condition if such costs arc not recovered through regulated rates. The ultimate oulcome of this matter cannot now be determined. Carho11 Dio:t:ide Litigatitm New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company's service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies' emissions of carbon dioxide, a greenhouse gas, contribute lo global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (I) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage ench year for at lenst n decode. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes lhat the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern Dislrict of New York granted Southern Company's and the other defendants' motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court's ruling, vacating the dismissal of the plaintiffs' claim, and remanding the case to the district court. On December 6, 20 I 0, the U.S. Supreme Court granted the defendants' petition for writ of certiorari. The ultimate outcome ofthese matters cannot be detennined at this time. Kivalina Case In February 2008,the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an lnupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs' damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants' motions to dismiss the case based on lack ofjurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs' failure to establish lhe standard for determining that the defendants' conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court's order dismissing the case. On January 24,2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be detennined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern Dislrict of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifih Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs' appeal of the 11-236 SoCo FOIA Response 001285 NOTES (collli ..cd) Gcol')lil l'o'lnr Company 2010 ,\naual Rcporl case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January I 0, 20 II, the U.S. Supreme Court denied the plaintiffs' petition to reinstate the appeal. This case is now concluded. Em•irommmtal Remediatitm The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. The Company accrued $1 million annually for environmental remediation expenses during 2008through 2010 that was recoverable through its ECCR tariff. Beginning in 2011,the Company is accruing approximately $3 million annually under the 2010 ARP. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As of December 31, 2010,the balance of the environmental remediation liability was $13 million, with approximately $3 million included in other regulatory assets, current and approximately $3 million included as other regulatory assets, deferred. The Company has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL arc anticipated. The final outcome of these matters cannot be determined at this time. However, bnsed on the currently known conditions at these sites and the nature nod extent of activities relating to these sites, management does not believe that additionallinbilities, if any, nt these sites would be material to the financial statements. In September 2008, the EPA advised the Company that it has been designated as n PRP nt the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices regarding this site from the EPA. The Company, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, in April 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including the Company, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, as a result of the regulatory treatment previously described, it is not expected to have a material impact on the Company's financial statements. Income Tax Mailers Georgia State l11come Ta.r: Credit.r The Company's 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. The Compnny filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) has not responded to these claims. In July 2007, the Company filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 20 I 0, the Superior Court of Fulton County ruled in favor of the Company's motion for summary judgment. TI1e Georgia DOR has appealed to the Georgia Court of Appeals and a decision is expected Inter this year. Any decision may be subject to further appeal to the Georgia Supreme Court. An unrecognized tax benefit has been recorded related to these credits. If the Company prevails, no material impact on the Company's net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers in accordance with the 2010 ARP. If the Company is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on the Company's cash now. See Note 5 under " Unrecognized Tax Benefits" for additional information. The ultimate outcome of this maller cannot be determined at this time. II-2J 7 SoCo FOIA Response 001286 NOTES (co•tinuttl) Gtoll!i• rowtr Company 2010 Annual Rtpurl Tax !1/etllod ofAccmmti11g/or Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company's generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 20 I0. The new tax method resulted in net positive cash flow in 20 I0 of approximately $133 million for the Company. A Ithough IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. The ultimate outcome of this matter cannot be determined at this time. Sec Note 5 under "Unrecognized Tax Benefits" for additional information. Nuclear Fuel Disposal Costs The Company has contracts with the U.S., acting through the U.S. Department of Energy (DOE), that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and the Company is pursuing legal remedies ngainst the government for breach of contract. In July 2007, the U.S. Court of Federal Claims awarded the Company approximately $30 million, based on its ownership interests, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Hatch nod Vogtlc from 1998 through 2004. In November 2007, the government's motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April2008. On May 5, 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay. In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government's alleged continuing breach of contract. The complaint docs not contain any speci tic dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of December 31, 20 I 0 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on the Company's net income is expected as any damage amounts collected from the government arc expected to be returned to customers. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plant Hatch, an on-site dry spent fuel storage facility is operational and cnn be expanded to accommodate spent fuel through the expected life of the plant. Rctuil Rcgulutory Matters Rute Pltms The economic recession significantly reduced the Company's revenues upon which retail rates were set by the Georgia PSC for 2008 through 2010 under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce expenses, the Company's projected retail return on common equity (ROE) for both 2009 and 20 I 0 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, in June 2009, the Company liled a request with the Georgia PSC for an accounting order that would allow the Company to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. In August 2009, the Georgia PSC approved the accounting order. Under the tenns of the accounting order, the Company could amortize up to S I 08 million of the regulatory liability in 2009 and up to $216 million in 20 I0, limited to the amount needed to earn no more than a 9.75% and 10.15% retail ROE in 2009 and 2010, respectively. For the years ended December 31, 2009 and 2010, the Company amortized $41 million and $174 million ofthe regulatory liability, respectively. On December 21,2010, the Georgia PSC approved the 2010 ARP, which became effective January I, 2011. The terms of the 2010 ARP reflect a settlement agreement among the Company, the Georgia PSC's Public Interest Advocacy Staff(PSC Staff), and eight other intervenors. Under the terms of the 2010 ARP, the Company will amortize approximately $92 million of its remaining regulatory liability related to other cost of removnl obligations over the three years ending December 31, 2013. 11-238 SoCo FOIA Response 001287 NOTES (rontin~d) Gtoi'Jli• l'o"u Company 2010 ,\anuallttport Also under the tenns of the 2010 ARP, effective January I, 2011, the Company increased its (I) traditional base tariff rates by approximately $347 million; (2) Demand-Side Management (DSM) tari!Trates by approximately $31 million; (3) ECCR tari!Trate by approximately S 168 million; and (4) Municipal Franchise Fee (MFF) toriIT rate by approximately S 16 million, for a total increase in base revenues of approximately $562 million. Under the 2010 ARP, the following additional base rote adjustments will be made to the Company's tori ITs in 2012 and 20 I3: • Effective January I, 2012, the DSM tariffs will increase by $17 million; • Effective April I, 20 I 2, the traditional base tori ffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Units 4 and 5 for the period from commercial operation through December 3 I, 20 13; • Effective January I, 2013, the DSM tariffs will increase by $18 million; • Effective January I, 2013,the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Unit 6 for the period from commercial operation through December 31, 20 13; and • The MFF tari!Twill increase consistent with these adjustments. The Company currently estimates these adjustments will result in nnnualized base revenue increases of approximately $190 mi Ilion in 2012 and $93 million in 2013. Under the 20 I0 ARP, the Company's retail ROE is set at 11 . 15%, and earnings will be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any comings above 12.25% will be directly refunded to customers, with the remaining one-third retained by the Company. Ifni any time during the tenn of the 2010 ARP, the Company projects that retail earnings will be below 10.25% for any calendar year, it may petition the Georgia PSC for the implementation of on Interim Cost Recovery (ICR) tariff to adjust the Company's earnings back to 11 10.25% retnil ROE. The Georgia PSC will hove 90 days to rule on nny such request. If approved, any ICR tari!Twould expire at the earlier of January I, 2014 or the end of the calendar year in which the ICR tari!Tbecomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR,the Company may file n full rate case. Except as provided above, the Company will not file for a general bnse rate increase while the 20 I0 ARP is in effect. The Company is required to file n general rate case by July I, 2013, in response to which the Georgin PSC would be expected to determine whether the 2010 ARP should be continued, modified, or discontinued. The Company currently expects to file an update to its integrated resource plan in June 2011. Under the tenns of the 2010 ARP, any costs associated with changes to the Company's approved environmental operating or capitol budgets (resulting from new or revised environmental regulations) through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Such costs that may be deferred as n regulatory asset include nny impairment losses that may result from a decision to retire certain units that 11re no longer cost effective in light of new or modi lied environmental regulations. In addition, in connection with the 20 I0 ARP, the Georgia PSC also approved revised depreciation rates thnt will recover the remaining book value of certain of the Company's existing coal-fired units by December 31, 20 14. The ultimate outcome of these mntters cannot be determined 111 this time. F11el Cll.f l Recm'l!I'J' The Company has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved increases in the Company's total annual billings of approximately S222 million effective June I, 2008 and $373 million effective April I, 20 I0. In addition, the Georgia PSC has authorized an interim fuel rider, which would allow the Company to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered fuel balance exceeds budget by more thnn $75 million. The Company is currently required to file its next fuel case by March I, 20 I I. The Company's under recovered fuel balance totaled approximately $398 million, of which approximately $214 million is included in deferred charges nnd other assets in the balance sheets at December 31, 20 I 0. Fuel cost recovery revenues as recorded in the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in the billing factor has no significant effect on the Company's revenues or net income, but does impact annual cash now. 11-239 SoCo FOIA Response 001288 NOTES lconli•uelll Gtol'l!i• Po1nr Comp•ny 2010 Ann .. l Reporl Construction Nuclear In August 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of the Company, Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant Voglle Units 3 and 4 ). See Note 4 for additional information on these co-owners. In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units. If licensed by the NRC, Plant Vogtlc Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively. In April 2008, the Company, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering. procuremenl, and construction agreement to design, engineer, procure, construct, and test two APJOOO nuclear unils with electric generating capacity of approximately I,100 megawatts each and related facilities, struclures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement). The Vogtle 3 and 4 Agreemenl is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under I he lerms of the Voglle 3 and 4 Agreement, the Owners agreed to pay a purchase price that will be subject to certain price escalations and adjustmenls, including fixed escalation amounts and certain indexbased adjuslments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership inlerest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. The Company's proportionate share is 45.7%. The Owners and the Consortium have agreed to certain liquidaled damages upon the Consortium's failure to comply with the schedule and performance guarantees. The Consortium' s liability lo the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. Certain payment obligalions of Weslinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement arc guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rnting downgrndes of any Owner, such Owner will be required to provide a Jetter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently slop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events. In March 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve the inclusion of the related construction work in progress accounts in rate base. In April2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows the Company to recover financing costs for nuclear construction projects by including the related construclion work in progress accounts in rnte base during lhe construclion period. With respcclto Plant Vogtle Unils 3 and 4, lhis legislalion allows the Company lo recover projected financing costs of approximately $1.7 billion during the construclion period beginning in 20 II, which reduces I he projected in-service costlo approximalely $4.4 billion. The Georgia PSC has ordered lhe Company lo report againsllhis lolnl certified cosl of approximately $6. 1 billion. In addilion, on December 21 , 20 I0, the Georgia PSC approved the Company's Nuclear Construction Cosl Recovery (NCCR) tariff. The NCCR tariff became effcclive January I, 20 II and is expecled lo collecl approximately $223 million in revenues during 20 II . On February 21,2011, the Georgia PSC voted lo approve lhe Company's lhird semi-annual conslruclion monitoring report including lola I costs of$1.048 billion for Planl Voglle Units 3 and 4 incurred through June 30, 20 I0. In conneclion with ils certificalion of Voglle Unils 3 and 4, lhe Georgia PSC ordered I he Company and the PSC Slaff lo work logelher to develop a risk sharing or incenlive mechanism lhat would provide some level of proleclion 10 rntcpayers in the event of significant cosl overruns, but also not penalize lhe Company's earnings if and when overruns are due lo mandales from governing agencies. Such discussions have conlinued through the third semi-annual construction monitoring proceedings; however, lhe Georgia PSC has deferred a decision with respeclto any relaled incentive or risk-sharing mechanism until a later dale. The Company will continue to file conslruction monitoring reports by February 28 and August 3 I of each year during lhe construclion period. 11-240 SoCo FOIA Response 001289 NOTES ltonlinued• Geoi'J!ia Po"·er Comrany 2010 Annuall{erorl In 2009, the Southern Alliance for Clean Energy (SACE) and the Fulton County Taxpayers Foundation, Inc. (FCTF) filed separate petitions in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC's certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. On May 5, 20 I0, the court dismissed as premature the plaintiffs' claim challenging the Georgia Nuclear Energy Financing Act. FCTF appealed the decision, and the Georgia Supreme Court ruled against FCTF, finding the suit premature. In addition, on May 5, 20 I0, the Superior Court of Fulton County issued an order remanding the Georgia PSC's certification order for inclusion of further findings of fact and conclusions of law by the Georgia PSC. In compliance with the court's order, the Georgia PSC issued its order on remand to include further findings of fact and conclusions of law on June 23, 2010. On July 5, 2010, SACE and FCTF liled separate motions with the Georgia PSC for reconsideration of the order on remand. On August 17, 20 I0, the Georgia PSC voted to reaffinn its order. The matter is no longer subject to judicial review and is now concluded. On December 2, 2010, Westinghouse submitted an APIOOO Design Certification Amendment (DCA) to the NRC. On February 10, 20 II, the NRC announced that it was seeking public comment on a proposed rule to approve the DCA and amend the ccrti lied API 000 reactor design for usc in the U.S. The Advisory Commillcc on Reactor Safeguards also issued a letter on January 24, 20 II endorsing the issuance of the COL for Plant Vogtle Units 3 and 4. The Company currently expects to receive the COL for Plant Vogtle Units 3 and 4 from lhe NRC in lale 20 II based on lhe NRC's February 16, 20 II release of ils COL schedule framework. There arc olher pending technical and procedural challenges lo lhe construction and licensing of Plant Voglle Units 3 and 4. Similar addilional challenges at the stale and federal level are expected as construction proceeds. The ultimate outcome of these matters cannot be detennined at this time. Other Cmr:rtru,·timr On May 6, 2010, the Georgia PSC approved the Company's request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-tenn reduclion in forecasted demand, as well as the requested increase in the certified amount. As a resull, the units nrc expecled to be placed into service in January 2012, May 2012, and January 2013, respectively. To date, the Georgia PSC has approved the Company's quarterly construction moniloring reports including aclual project expenditures incurred through June 30, 20 I0. The Company will continue to file quarterly construclion moniloring reports throughoullhc construction period. 4. JOINT OWNERSIIIP AGREEMENTS The Company and Alabama Power own equally all oflhe outslnnding cnpilal stock ofSEGCO, which owns electric generating units with a total rated capacity of 1,020 megawntls, as well as associaled transmission facilities. The capacity of these units is sold equally to the Company and Alabama Power under a contract which, in subslance, requires payments sufficient lo provide for the operating expenses, taxes, debt service, and return on investmenl, whether or not SEGCO has any capacity and energy available. The lenn of lhe contract extends automatically for two-year periods, subject to either party's right to cancel upon two years' notice. The Company accounts for SEGCO using the equity method. The Company's share of expenses included in purchased power from affiliates in the statements of income is as follows: 2010 2009 2008 (in millioru) Energy Ca~acit:>;: $ 53 $ 44 $ 86 47 43 $ 87 $ 127 $ 100 Total 41 The Company owns undivided interests in Plants Vogllc, Hatch, Wansley, and Scherer in varying amounts jointly with OPC, MEAG Power, Dalton, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company and Florida Power Corporation (Progress Energy Florida) jointly own a combustion turbine unit (Intercession City) operated by Progress Energy Florida. 11-241 SoCo FOIA Response 001290 NOTES (conlinutdl Gtofl:iR l'owrr Company 1010 Annual Rtport At December 31, 20 I 0, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly owned fncil ities in commercial operation with the above entities were as follows: Company Fncilil:t: {Tr~e} Ownershi~ Accumulated Investment De~recinlion (inmillion.f) Plant Vogtle (nuclear) Units I and 2 Plant Hatch (nuclear) Plant Wansley (coal) Plant Scherer (coal) Units I and 2 Unit 3 Rocky Mountain (pumped storage) Intercession Cit~ (combustion-turbine) 45.7% 50.1 53.5 8.4 75.0 25.4 33.3 $ 3,292 $ 1,935 962 700 534 208 148 857 175 12 74 362 109 3 At December 31, 2010, the portion ortotal construction work in progress related to Plants Wansley, Scherer, and Vogtle Units 3 and 4 was $11 million, $1 10 million, and $1.3 billion, respectively. Construction at Plants Wansley and Scherer relnles primarily to environmental projects. Sec Note 3 under "Construclion- Nuclear" for informal ion on Plant Vogtle Units 3 and 4. The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the slalements of income and lhe Company is responsible for providing its own financing. 5. INCOME TAXES Southern Company files a consolidated federal income tax relurn and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocalion agreemenl, each subsidiary's current and deferred tax expense is com puled on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separalc income tax relurn. In accordance with IRS regulations, each company is jointly and severally liable for the lax liability. Current and Deferred Income Taxes Details of income tax provisions arc as follows: 2010 2009 2008 (itr millions) Federal$211 175 386 $284 155 439 (36) 30 7 17 33 16 {6} $453 24 $410 49 $488 $ 147 312 459 Current Deferred StateCurrent Deferred Tolal 11-242 SoCo FOIA Response 001291 NOTES (continurd) Groi"Jlia rower Company 2010 Annual Rrporl The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise lo deferred ta.x assets and liabilities, are as follows: 2010 2009 (itt millions) Deferred tax liabilities Accelerated depreciation Property basis differences Employee benefit obligations Fuel clause under recovery Premium on reacquired debt Emissions allowances Regulatory assets associated wilh employee benefit obligations Asset retirement obligations Other Total $ 3,184 746 251 162 71 18 336 275 52 5,095 $ 2,923 585 184 270 64 22 362 263 70 4.743 Deferred tax assels 159 433 111 Federal effect of state deferred taxes Employee benefit obligations Other property basis differences Other deferred cosls Cost of removal obligations 72 52 192 State tax credit carry forward Other comprehensive income 6 57 275 Unbilled fuel revenue Asset retirement obligations Environmental capital cost recovery 1 37 Other Total Total deferred tax liabilities, net Portion included in current asscts/(liabilities), net Accumulated deferred income taxes 177 482 117 65 109 99 12 42 263 37 38 1,395 1,441 3,700 18 3,302 88 $ 3,718 $ 3,390 At December 31, 2010, tax-related regulatory assets were $727 million and tax-related regulatory liabilities were $129 million. These assets arc attributable to tax benefits nowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest. In 20 I 0, the Company deferred $51 million as a regulatory asset related to the impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of2010 (together, the Acts). The Acts eliminated the deductibility of health care costs that are covered by federal Medicare subsidy payments. Beginning in 20 II, the Company is amortizing the regulatory asset to income tax expense over 12 years, under the 20 I 0 ARP. These liabilities are attributable to deferred taxes previously recognized at rates higher limn current enacted tax law and to unamortized investment tax credits. In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $13 million in 2010, $14 million in 2009, and $13 million in 2008. At December 31 , 2010, all investment tax credits available to reduce federal income taxes payable had been utilized. On September 27, 2010, the Small Business Jobs and Credit Act of20 10 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 20 I0 (and for certain long-term construction projects to be placed in service in 2011 ). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance 11-243 SoCo FOIA Response 001292 NOTES (conli.. ull Gtoi'J:ial'owtr Company 2010 ,\nnual Rtporl Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include I00% bonus depreciation for property placed in service afler September 8, 20 I0 and through 20 II (and for certain long-tenn construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-tenn construction projects to be placed in service in 2013). The application of the bonus depreciation provisions in these acts in 2010 significantly increased deferred tax liabilities related to accelerated depreciation. Effective Tax Rate A reconciliation of the federal statutory income tax rntc to the effective income tax rnte is as follows: Federal statutory rate State income tax, net of federal deduction Non-deductible book depreciation AFUDC equity Donations Other Effective income tax rnte 2010 35.0"/o (0.3) 1.0 (3.6) 2009 35.0% 1.2 1.1 (2.7) (0.8) {0.2} 31.9% {0.8! 33.0% 2008 35.0% 2.2 0.9 (2.4) p.q 34.6% The decreases in the Company's 20 I 0 and 2009 effective tax rates arc primarily the result of increases in non-taxable AFUDC equity and state tax credits. See "Unrecognized Tax Benefits" herein and Note 3 under " Income Tax Matters" for additional information on unrecognized tax benefits and related litigation related to state tax credits. The American Jobs Creation Act of 2004 created n tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code. The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 20 I 0. Unrecognized Tax Benefits For 2010, the total amount of unrecognized tax benefits increased by $56 million, resulting in a balance of$237 million as of December 31, 20 I0. Changes during the year in unrecognized tax benefits were as follows: 2010 2009 2008 (in millitJII.f) Unrecognized tax benefits at beginning ofyenr Tax positions from current periods Tax positions increase from prior periods Tax positions decrease from prior periods Reductions due to settlements Reductions due to expired stntute of limitations Balance at end of year $ 181 $ 137 52 44 27 (23) 6 (5) $ 89 47 5 (4) s IIS) Liabilities from risk manngement activities Other deferred credits and liabilities Liabilities from risk mana~;~ement activities $77 $47 24 28 $101 $75 $$101 $2 $77 All derivative instruments are measured at fair value. See Note I 0 for additional information. 11-255 SoCo FOIA Response 001304 NOTES (tontinurd} Gtui"J:ia l'uwrr Company 2010 Annual Rrporl At December 31, 20 I 0 and 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: Unrealized Losses Balance Sheet Location 2010 Derivative Category 2009 Unrealized Gains Balance Sheet Location 2010 (;,1 millimts) Energy-related derivatives: Other regulatory assets, current Other regulatory assets. deferred Total energy-related derivative gains (losses) $(77) $(47) (24) (28) $(101) $(75) 2009 (ill millimu) Other regulatory liabilities, current Other deferred credits and liabilities $1 $- Sl $- For the years ended December 31, 20 I0, 2009, and 2008, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Uedging Relationships Derivative Category Gain (Loss) Recognized in OCI on Derivative {Effective Portion) 2010 2009 2008 Gain (Loss) Reclassined from Accumulated OCI into lnt:ome (Effective Portion) Amount 2008 Statements of Income Location 2010 2009 (ill mil/irms) (ill mil/iOIIS) Interest rate derivatives s- $(3) $(34) Interest expense, net of amounts capitalized $(16) $(22) $(3) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 3 I, 20 I 0, 2009, and 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. The Company has certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain arliliated companies. At December 31 , 2010, the fair value of derivative liabilities with contingent features was $26 million. At December 31,2010, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-riskrelated contingent features, at a rating below BBB- and/or Baa3, is $40 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in certain agreements that could require collateral in the event thnt one or more Southern Company system power pool participants has n credit rating change to below investment grnde. SoCo FOIA Response 001305 NOTES lo"·tr Company 20 HI Annual Rtporl 12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 20 I 0 and 2009 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock (ill millions) March 2010 June2010 September 2010 December 2010 $ 1,984 2,000 2,628 1,737 $ 399 $ 238 411 714 141 238 420 54 March 2009 June 2009 September 2009 December 2009 $ 1,766 1,874 2,327 1.725 $ 272 369 683 206 $ 122 190 388 114 The Company's business is influenced by seasonal wealher conditions. 11-2~7 SoCo FOIA Response 001306 SELECTED FINANCIAL AND OPERATING OATA 2006-2010 Georgia Power Company 2010 Annual Report Operating Revenues Net Income after Dividends on Preferred and Preference Stock (in million•> Cash Dividends on Common Stock (in million•) Return on Average Common Equity «1•rrcrnt) Total Assets lin ~nlllluns) Gross Pro~ert,r Additions lin million•) Capitalization (in million•): Common stock equity Preferred and preference stock Lons-terrn debt Total tc•cludin5amoun1s due wilhin one vcorl Capitalization Ratios (percenl): Common stock equity Preferred and preference stock Lons-terrn debt Total (c.xcludin~ nmounls due wilhin one vcnrl Customers (ytar-cnd): Residential Commercial Industrial Other Total Em~lo_rees lltar·cndl N!A 2010 $8,349 2009 $7,692 2008 $8,412 2007 $7,572 2006 $7,246 $950 $814 $903 $836 $787 $820 11.42 $25,914 $2,401 $739 11.01 $24,295 $2,646 $721 13.56 $22,316 $1,953 $690 13.50 $20,823 $1,862 $630 13.80 $19,309 $1,277 $8,741 266 7,931 $161938 $7,903 266 7,782 $15.951 $6,879 266 7,006 $14.151 $6,435 266 5,938 $12.639 $5,956 45 5,212 $11.213 51.6 1.6 46.8 100.0 49.5 1.7 48.8 100.0 48.6 1.9 49.5 100.0 50.9 2.1 47.0 100.0 53.1 0.4 46.5 100.0 2,049,770 296,140 8,136 7,309 2,043,661 295,375 8,202 6,580 2.353.818 8,599 2,039,503 295,925 8,248 5,566 2.349.242 9,337 2,024,520 295,478 8,240 4,807 2.333.045 9,270 1,998,643 294,654 8,008 4,371 2.305.676 9,278 2~61~55 8,330 Nol Applicable 11-258 SoCo FOIA Response 001307 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 (continued) Georgia Power Company 2010 Annual Report Operating Revenues Cln millions): Residential Commercial Industrial Other Total retail Wholesale- non-affiliates Wholesale- affiliates Total revenues from sales of electricity Other revenues Total Kilowatt-Hour Sales (in millions): Residential Commercial Industrial Other Total retail Wholesale- non-affiliates Wholesale- affiliates Total Average Revenue Per Kilowatt-Hour (cents): Residential Commercial Industrial Total retail Wholesale Total sales Residential Average Annual Kilowatt-Hour Usc Per Customer Residential Average Annual Revenue Per Customer Plant Nomcplatc Copacity Ratings (year-end) (mcpwalls) Maximum Peak-Hour Demand (mL-ga ..·uus): Winter Summer Annual Load Factor (Jlcrccnt) Plant Availability (percent): Fossil-steam Nuclear Source of Energy Supply Cl'erccn!l: Coal Nuclear Hydro Oil and gas Purchased power From non-affiliates From affiliates Total 2010 2009 2008 2007 2006 $ 3,072 3,011 1,441 84 7,608 380 53 8,041 308 $8 349 $2,686 2,826 1,318 82 6,912 395 112 7,419 273 $7,692 $2,648 2,917 1,640 81 7,286 569 286 8,141 271 $8,412 $2,443 2,576 1,404 75 6,498 538 278 7,314 258 $7.572 $2,326 2,424 1,382 74 6,206 552 253 7,011 235 $7.246 29,433 33,855 23,209 663 87,160 4,662 1,000 92 822 26,272 32,593 21,810 671 81,346 5,208 2,504 89.058 26,412 33,058 24,164 671 84,305 9,755 3,695 97.755 26,840 33,057 25,490 697 86,084 10,578 5,192 101.854 26,206 32,112 25,577 660 84,555 10,687 5,463 I 00.705 10.44 8.89 6.21 8.73 7.65 8.66 10.22 8.67 6.04 8.50 6.57 8.33 10.03 8.82 6.79 8.64 6.36 8.33 9.10 7.79 5.51 7.55 5.17 7. 18 8.88 7.55 5.40 7.34 4.98 6.96 14,367 12,848 12,969 13,315 13,216 $1,499 $1,314 $1,300 $1,212 $1,173 15,992 15,995 15,995 15,995 15,995 15,614 17,152 60.9 15,173 16,080 60.7 14,221 17,270 58.4 13,817 17,974 57.5 13,528 17,159 61.8 88.6 94.0 92.5 88.4 91.0 89.8 90.8 92.4 91.4 90.7 51.8 16.4 1.4 8.0 52.3 16.2 1.8 7.7 58.7 14.8 0.6 5.1 61.5 14.6 0.5 5.5 59.0 14.4 0.9 5.0 5.2 17.2 100.0 4.4 17.6 100.0 5.1 15.7 100.0 3.8 14.1 100.0 3.8 16.9 100.0 11-259 SoCo FOIA Response 001308 GULF PU WEIR COMPANY FINANCIAL. SECTION I I- SoCo FOIA Response 001309 MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Gulrl'owrrCompany 2010 Annual Reporl The management of Gulf Power Company (the "Company") is responsible for eslablishing and mainlaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a15(1). A control system can provide only reasonable, not absolule, assurance that the objectives of the conlrol system are met. Under management's supervision, an evaluation of the design and effecliveness of the Company's inlemal control over financial reporting was conducted based on the framework in Internal Co/llro/- llllegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal conlrol over financial reporting was effective as of December 31, 20 I 0. Mark A. Crosswhite President and Chief Executive Omcer Richard S. Teel Vice President and Chief Financial Omcer February 25, 2011 11-261 SoCo FOIA Response 001310 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Gulf Power Company We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (the "Company") (a wholly owned subsidiary of Southern Company) as of December 31,2010 and 2009, and the related statements of income, comprehensive income, common stockholder's equity, and cash nows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed of the Company in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements (pages 11-287 to 11-327) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 20 I0 and 2009, and the results of its operations and its cash nows for each of the three years in the period ended December 31, 20 I0, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the in formation set forth therein. Atlanta, Georgia February 25, 2011 11-262 SoCo FOIA Response 001311 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Gulrl'm•-er Company 2010 ,\nnual Report OVERVIEW Business Activities Gulf Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. Key PerformAnce Indicators In striving to maximize shareholder value while providing cost-effective energy to over 430,000 customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. The Company's financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company's results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of plant availability and eflicient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The 2010 Peak Season EFOR of3.86% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for rei iabil ity arc set internally based on historical performance, expected weather conditions, and expected capital expenditures. The performance for 20 I0 was better than the target for these rei iability measures. Net income after dividends on preference stock is the primary measure of the Company' s financial perfonnance. The performance for net income after dividends on preference stock in 2010 was above target. The Company's 20 I0 results compared with its targets for some of these key indicators arc reflected in the following chart: Key Performance Indicator Customer SAtisfaction Peak SeAson EFOR Net income arter dividends on Jlreference stock 2010 Target Performance 2010 ActuAl Performance Top quartile in customer surveys 5.06% or Jess Top quartile 3.86% $116.8 million $121.5 million Sec RESULTS OF OPERATIONS herein for additional information on the Company's financial performance. The performance achieved in 20 I 0 reflects the continued emphasis the Company places on these indicators as well as the commitment of employees to meet and exceed targets. Enrnings The Company's 20 I 0 net income after dividends on preference stock was $121.5 million, an increase of$ I 0.3 million from the previous year. In 2009, net income after dividends on preference stock was S I I I .2 million, an increase of$12.9 million from the previous year. In 2008, net income after dividends on preference stock was $98.3 million, an increase of$14.2 million from the previous year. The increase in net income after dividends on preference stock in 20 I0 was primarily due to increased retail revenues due lo significantly colder weather in the first quarter 2010 and warmer weather in the third quarter 2010. The increases in revenues were partially offset by an increase in operations and maintenance expenses. The increase in net income afier dividends on preference stock in 2009 was due primarily to increased allowance for funds used during construction (AFUDC) equity, which is non-taxable, and decreased interest expense, net of amounts capitalized, partially offset by unfavorable weather and a decline in sales. The increase 11-263 SoCo FOIA Response 001312 MANAGEMENT'S DISCUSSION AND ANALYSIS (conlinurd. Gulf l'01nr Company 2010 Annuallltport in net income after dividends on preference stock in 2008 was due primarily to higher wholesale revenues from non-affiliates, increased AFUDC equity, and a gain on the sale of assets. RESULTS OF OPERATIONS A condensed statement of income follows: Increase (Decrensc) from Prior Ycnr 2010 2009 2008 Amount 2010 (in millions) Operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Total other income and (expense) Income taxes Net income Dividends on preference stock Net income after dividends on preference stock $ 1,590.2 742.3 97.2 280.6 121.5 101.8 1.343.4 246.8 (47.6) 71.5 127.7 6.2 $ 121.5 $ (84.9) (62.2) ( 17.4) (17.2) 8.6 7.3 (80.9) (4.0) 15.8 ( 1.1) 12.9 $ 127.4 168.9 5.2 20.3 28.1 7.3 229.8 58.2 (29.4) 18.5 10.3 10.3 $ 12.9 $ 14.2 $ 288.0 $ 62.2 37.9 7.1 (0.8) 4.2 110,6 16.8 6 .7 7.0 16.5 2.3 Operuti11g Ret'f!llllt!s Operating revenues for 20 I0 were $1,590.2 million, reflecting an increase of $288.0 million from 2009. The following table summarizes the significant changes in operating revenues for the past three years: 2010 Amount 2009 2008 (in millions) Retail- prior year Estimated change inRates and pricing Sales growth (decline) Weather Fuel and other cost recove!i: Retail- current l::ear Wholesale revenues Non-affiliates Affiliates Total wholesale revenues Other operating revenues Total operatin~;~ revenues Percent chan~;~e $ 1,106.6 72.7 (2.3) 18.7 113.0 1,308.7 $ 1, 120.8 33.0 (5.7) (4.5) (37.0) 1,106.6 94.1 109.2 110.0 32.1 219.2 126.2 62.3 69.4 $ 1,302.2 $ 1,590.2 (6.1)% 22.1% $ 1,006.3 6.3 (4.6) 3.9 108.9 1,120.8 97.1 107.0 204.1 62.3 $ 1,387.2 10.1% Retail revenues increased $202.1 million, or 18.3%, in 2010, decreased $14.2 million, or 1.3%, in 2009, and increased $114.4 million, or 11.4%, in 2008. 11-264 SoCo FOIA Response 001313 MANAGEMENT'S DISCUSSION AND ANALYSIS (to•tinutlll Gul£ Powtr Company 2010 Annul Rtporl Revenues associated with changes in rates and pricing include cost recovery provisions for energy conservation costs and environmental compliance costs. Annually, the Company petitions the Florida Public Service Commission (PSC) for recovery of projected costs, including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions include related expenses and a return on average net investment. See Note 3 to the financial statements under "Retail Regulatory Matters- Environmental Cost Recovery" for additional information. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes relating to sales growth (or decline) and weather. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, and purchased power capacity costs. Annually, the Company petitions the Florida PSC for recovery of projected fuel and purchased power costs, including any true-up amount from prior periods, and approved rates are implemented each January. Cost recovery provisions also include revenues related to the recovery of storm damage restoration costs. The recovery provisions generally equal the related expenses and have no material effect on net income. Sec Note I to the financial statements under "Revenues" and "Property Damage Reserve" and Note 3 to the financial statements under "Retail Regulatory Matters- fuel Cost Recovery" for additional information. Total wholesale revenues were $219.2 million in 20 I 0, an increase of $93.0 million, or 73.7%, compared to 2009 primarily to serve weather-related increases in affiliate demand as a result of colder weather in the first and fourth quarters 2010 and wanner weather in the second and third quarters 2010. Total wholesale revenues were $126.2 million in 2009, a decrease of $77.8 million, or 38.2%, compared to 2008 primarily due to decreased energy sales to affiliates at a lower cost per kilowatt-hour (K\VU). Total wholesale revenues were $204.1 million in 2008, an increase of$7.4 million, or 3.7%, compared to 2007 primarily due to higher capacity revenues associated with new and existing territorial wholesale contracts with non-affiliated companies. Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Revenues from unit power sales increased $7.3 million, or 12.6% in 2010 primarily due to increased capacity revenues as a result of new contracts. Revenues from other power sales increased $7.8 million, or 21.3% in 20 I 0 primarily due to increased KWU sales to serve weather-related increases in non-territorial demand. Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to other ulilitics in Florida and Georgia. Wholesale revenues from contracts have both capacity and energy components. Capacity revenues renect the recovery of fixed costs and a return on investment. Energy is generally sold at variable cost. The capacity and energy components under these unit power sales contracts were as follows: 2010 2009 2008 (in rlwu.wmls) Unit power salesCapacity Energy Total Other power salesCapacity and other Energy Total Total non-affiliated s 33,482 31,379 64,861 I 1,158 33,153 44,31 I s 109,172 s s 24,466 33.122 57.588 $ 22,028 33,767 55.795 11,060 25,457 36,517 94,105 10,890 30,380 41.270 $ 97,065 Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). These transactions do not have a significant impact on earnings since the fuel revenue related to energy sales and the cost of energy purchases are both included in the detennination of recoverable fuel costs and are generally offset by revenues collected in the Company's fuel cost recovery clause. Other operating revenues decreased $7.2 million, or 10.4%, in 20 I 0 primarily due a $10.3 million decrease in revenues rrom other energy services, partially offset by higher franchise fees of$3.1 million. Other operating revenues increased $7 .I million, or 11.3%, in 2009 primarily due to other energy services and franchise fees, offset by transmission and distribution network services and timber 11-265 SoCo FOIA Response 001314 MANAGEMENT'S DISCUSSION AND ANALYSIS lconlinutd) G•lrl'o"'" Comp1ny 2010 .\anu1l Rtporl sales. Other operating revenues increased $5.6 million, or 9.9%, in 2008 primarily due to transmission and distribution network services and other energy services. Revenues from other energy services did not hnve a material effect on net income since they were generally offset by associated expenses. Franchise fees have no impact on net income. E11ergy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to yenr. KWI-I sales for 20 I0 nnd the percent change by year were as follows: Total KWIIs 2010 (ill Residential Commercial Industrial Other Total retail Wholesale Non-affiliates Affiliates Total wholesale Total eners~ sales Total KWII Percent Change 2010 2009 2008 Weather-Adjusted Percent Change 2010 2009 2008 0. 1% (4.1)% (0.4) 7.9 (5.1) millirms) 5,651 3,996 1,686 26 11,359 1.6•!. 2.6 (2.4) 1.9 4.2 1,675 2!437 4,112 15,471 (7.6) 180.0 53.2 13.9"/,, ( 1.8)% ( 1.6) (2 1.9) 8. 1 j5.5~ (2.3)% (0.3) 7.9 (5. 1) 0.2 (0.2)n/• 0.3 (2.4) 1.9 (0.3)% ( 1.1) (21 .9) 8. 1 (4.6)% (0.7~% (0.2) (53.5} ( 18.4) (35.1) {27.8) (27.2~ (10.8)% (8.4!% Changes in retail energy sales arc comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Residential KWH sales increased 7.6% in 20 I0 compared to 2009 primarily due to significantly colder weather in the first quarter 20 I 0 and warmer weather in the third quarter 20 I0. Weather-adjusted KWH sales to residential customers remained relatively flat as compared to 2009. Residential KWH sales decreased 1.8% in 2009 compared to 2008 primarily due to the recessionary economy. Weather-adjusted KWH sales to residential customers remained relatively flat as compared to 2008. Residential KWH sales decreased 2.3% in 2008 compared to 2007 primarily due to decreased customer usage as a result of a slowing economy, partially offset by more favorable weather. Commercial KWH sales increased 2.6% in 2010 compared to 2009 primarily due to significantly colder weather in the first quarter 20 l 0 and warmer weather in the third quarter 20 I0. Weather-adjusted KWH sales to commercial customers remained relatively flat as compared to 2009. Commercial KWH sales decreased 1.6% in 2009 compared to 2008 primarily due to the recessionary economy and a decrease in the number of customers. Weather-adjusted KWH sales to commercial customers decreased primarily due to rcccssionary-driven decreases in per customer usage and in the number or customers as compared to 2008. The change in commercial KWH sales in 2008 compared to 2007 was immaterial. Industrial KWI-I sales decreased 2.4% in 20 I0 compared to 2009 primarily resulting from increased customer co-generation due to the lower cost or natural gas in 20 I0. Industrial KWH sales decreased 21.9% in 2009 compared to 2008 primarily due to increased customer co-generation due to the lower cost of natural gas in 2009, decreased demand, and n business closure due to the recessionary economy. Industrial KWH sales increased 7.9% in 2008 compared to 2007 primarily due to decreased customer co-generation due to the higher cost of natural gas. Wholesale KWI-I sales to non-affiliates decreased 7.6% in 2010, decreased 0.2% in 2009. and decreased 18.4% in 2008 each compared to the prior year. The decrease in 2010 was primarily a result of lower KWHs scheduled by unit power customers. The decrease in 2009 was primarily a result of the rccessionary economy. The decrease in 2008 was primarily the result of fluctuations in the fuel cost to produce energy sold to non-affiliated utilities under both long-term and short-term contracts. The degree to which prices for oil and natural gas, which are the primary fuel sources for these customers, differ from the Company's fuel costs will influence these changes in sales. TI1e fluctuations in sales have a minimal effect on earnings since the fuel revenue related to energy sales and the cost or energy purchases arc both included in the determination of recoverable fuel costs and are generally oiTset by revenues collected in the Company's fuel cost recovery clause. 11-266 SoCo FOIA Response 001315 SoCo FOIA Response 001316 MANAGEMENT'S DISCUSSION AND ANALYSIS (rontlnurtll Gulr l'm4'fr Company 2010 ,\nnualltrport Wholesale KWH sales to affiliates increased 180% in 20 I0, decreased 53.5% in 2009, and decreased 35.1% in 2008, compared to prior years. The increase in 2010 was primarily to serve weather-relaled increases in affiliate demand due to colder weather in the first and fourth quarters 20 I0 and warmer weather in the second and third quarters 2010. The decrease in 2009 was primarily a result of the recessionary economy. The decrease in 2008 was primarily due to the availability oflower cost generation resources at affiliated companies. Fuel uttd Purcltased Power Expe11ses Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company's electricity generated and purchased were as follows: Total generation (millimrsrifKII'IIs) Total Eurchased ~wer (millitms of. Kll'l/s) Sources of generation (f~err:rm) Coal Gas Cost of fuel, generated (cc111s per 11e1 J..'WII) Coal Gas Average cost of fuel, generated (cems prr 11e1 Kll'll)• Average cost of EUrchased ~wer (ce11rs £1Cr 11c1 KWI/J 2010 13,440 2,858 78"/o 22 2009 12,895 1.481 69% 31 2008 14,762 1,187 84% 16 5.10 4.68 4.27 4.66 3.58 8.02 5.01 5.82 4.39 6.71 4.31 9.21 •Fuel includes fuel purchased by the Company for lolling ngrL'l!meniS where power is gL-ncrnlctl by the provider anti is indutlctl in purchoSL'tl power when tlctennining the n\'crngc cost of purchased powLT. Total fuel and purchased power expenses were $839.5 million in 20 I 0, an increase of $174.1 million, or 26.2%, above the prior year costs. The net increase in fuel and purchased power expenses was primarily due to a $116.3 million increase related to total KWHs generated and purchased and a $57.8 million increase in the cost of energy resulting primarily from an increase in the average cost of coal-fired generation and affiliated company power purchases. Total fuel and purchased power expenses were $665.4 million in 2009, a decrease of $79.6 million, or I0.7%, below the prior year costs. The net decrease in fuel and purchased power expenses was primarily due to a $53.3 million decrease related to total KWl·ls generated and purchased and a $26.3 million decrease in the cost of energy primarily resulting from a decrease in the average cost of natural gas. Total fuel and purchased power expenses were $745.0 million in 2008, an increase of$100.1 million, or 15.5%, above the prior year costs. The net increase in fuel and purchased power expenses was due to a $130.5 million increase in the average cost of fuel and purchased power as well as a $34.9 million increase related to KWHs purchased, offset by a $65.3 million decrease related to KWI-Is generated. Fuel expense was $742.3 million in 2010, an increase of$168.9 million, or 29.5%, above the prior year costs. This increase was primarily the result of a 19.4% increase in the average cost of coal and a 4.2% increase in KWHs generated as a result of higher demand. Fuel expense was $573.4 million in 2009, a decrease of $62.2 million, or 9.8%, below the prior year costs. This decrease was primarily the result of a 41.9% decrease in the average cost of natural gas and a 12.6% decrease in KWHs generated as a result of lower demand, partially offset by an increase of 19.3% in the average cost of coal perK WH generated. Fuel expense was $635.6 million in 2008, an increase of $62.2 million, or 10.9%, above the prior year costs. This increase was the result of a 25.3% increase in the average cost of fuel, offset by an 11.4% decrease in K WHs generated. Purchased power expense was $97.2 million in 2010, an increase of$5.2 million, or 5.7%, above the prior year costs. This increase was the result of a 92.9% increase in the volume of KWl·ls purchased, offset by a 13.3% decrease in the average cost perK WH purchased. Purchased power expense was $92.0 million in 2009, a decrease of $17.4 million, or 15.9%, below the prior year costs. This decrease was primarily the result of a 27 .I% decrease in the average cost per KWH purchased, offset by a 24.8% increase in the volume of K WHs purchased. Purchased power expense was $109.4 million in 2008, an increase of$37.9 million, or 53.0%, above the prior year costs. This increase was the result of a 48.8% increase in total KWHs purchased and a 2.8% increase in the average cost per net KWH. 11·267 SoCo FOIA Response 001317 MANAGEMENT'S DISCUSSION AND ANALYSIS lconlinurdl Gulrl'owrrCompan)' 2010 Annual Rtporl From an overall global market perspective, coal prices increased substantially in 20 I 0 from the levels experienced in 2009, but remained lower than the unprecedented high levels of2008. The slowly recovering U.S. economy and global demand from coal importing countries drove the higher prices in 20 I0, with concerns over regulatory actions, such as permilting issues, and their negative impact on production also contributing upward pressure. Domestic natural gas prices continued to be depressed by robust supplies, including production from shale gas, as well as lower demand. These lower natural gas prices contributed to increased use of natural gas-fueled generating units in 2009 and 2010. Fuel expenses generally do not affect net income, since they arc offset by fuel revenues under the Company's fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL- "PSC Matters- Fuel Cost Recovery" herein for additional information. Otlter Operutitms u11d Muilltellallce Expe11ses In 20 I 0, other operations and maintenance expenses increased $20.3 million, or 7.8%, compared to the prior year primarily due to a $20.2 million increase in scheduled and unscheduled maintenance at generation facilities. In 2009, other operations and maintenance expenses decreased $17.2 million, or 6.2%, compared to the prior year primarily due to a $14.4 million decrease in administrative and general expense, most of which was related to decreased slorm recovery costs, and a $6.7 million decrease in power generation, most of which was related to scheduled and unscheduled maintenance and cost containment activities in an effort to offset the effects of the recessionary economy. This decrease was partially offset by a $4.8 million increase in other energy services. In 2008, other operations and maintenance expenses increased $7.1 million, or 2.6%, compared to the prior year primarily due to an $8.2 million increase in scheduled and unscheduled maintenance at generation facilities. Depreciutio11 utrd Amortizutio11 Depreciation and amortization increased $28.1 million, or 30.1%, in 2010 compared to the prior year primarily due to the addition of an environmental control project at Plant Crist being placed into service in December 2009 and other net additions to generation and distribution facilities. Approximately $19.0 million ofthe increase was related to the environmental control project at Plant Crist and was recovered through the environmental clause; therefore, it had no material impact on net income. Depreciation and amortization increased $8.6 million, or I0.1 %, in 2009 compared to the prior year primarily due to additions of environmentnl control projects at Plant Crist and Plant Scherer and other net additions to generntion nnd distribution facilities. Depreciation and amortization decreased $0.8 million, or 0.9%, in 2008 compared to the prior year primarily ns a result of a $3.8 million gnin on lhe sale of a building. The decrease was partially offset by an incrense of$3.0 million in depreciation due to net additions to generation and dislribution facilities. Taxes Otller Tllu11 l11come Taxes Taxes other than income !axes increased $7.3 million, or 7.7%, in 2010 compared to the prior year primarily due to a $5.5 million increase in gross receipt and franchise fees and a $1.0 million increase in payroll taxes. Taxes olher than income !axes increased $7.3 million, or 8.3%, in 2009 compared to the prior year primarily due to a $5.6 million increase in gross receipls and franchise taxes and a $1.6 million increase in property taxes. Taxes other than income taxes increased $4.2 million, or 5.1%, in 2008 compared to the prior year primarily due to a $1.9 million decrease in 2007 related to the resolution of a dispute regarding property taxes in Monroe County, Georgia and a $1.9 million increase in franchise and gross receipt taxes. Gross receipts and franchise taxes have no impact on net income. Allmvu11cefor F1111ds U.fed Duri11g Ctmstmctimr Equity AFUDC equity decreased $16.6 million, or 69.7%, in 2010 compared to the prior year primarily due to an environmental control project at Plant Crist being placed into service in December 2009. AFUDC equity increased $13.8 million, or 138.8%, in 2009 compared to the prior year primarily due lo construction of environmental control projects al Plant Crist and Plant Scherer. A FUDC equity increased $7.6 million, or 319.9%, in 2008 compared to lhe prior year primarily due to construction of environmental control projects at Plant Crist and Plant Scherer. See Note I to the linancial statements under "Allowance for Funds Used During Construction (AFUDC)" for additional information. 11-268 SoCo FOIA Response 001318 MANAGEMENT'S DISCUSSION AND ANALYSIS (conlinutlll Gulf ro~nr Compnny 2010 Annual Rtporl l11terest Expe11se, Net ll/Ammmts Capitalized Interest expense, net of amounts capitalized increased $13.5 million, or 35.3%, in 20 I0 compared to the prior year as the result of a reduction in capitalized interest for an environmental control project at Plant Crist being placed into service in December 2009. The increased interest was also primarily due to an increase in long-term debt levels resulting from the issuance of additional senior notes in 2010 to fund general corporate purposes, including the Company's continuous construction program. Interest expense, net of amounts capitalized decreased $4.7 million, or 11.0%, in 2009 compared to the prior year as the result of an increase in capitalization of AFUDC debt related to the construction of environmental control projects at Plant Crist and Plant Scherer. Interest expense, net of amounts capitalized decreased $1.6 million, or 3 .5%, in 2008 compared to the prior year as the result of an increase in capitalization of AFUDC debt related to the construction of environmental control projects and the redemption of$41.2 million of long-term debt payable to an affiliated trust in 2007. These decreases were offset by the issuance of a $110 million term loan agreement in 2008. lllcflme Taxes Income taxes increased $18.5 million, or 34.9%, in 2010, compared to the prior year primarily as a result of higher earnings before income taxes and a reduction in the tax benefits associated with a decrease in AFUDC equity, which is non-taxable. Income taxes decreased $1.1 million, or 2.0%, in 2009 compared to the prior year primarily due to the tax benefit associated with an increase in AFUDC equity, which is non-taxable, partially offset by higher earnings before taxes. Income taxes increased $7.0 million, or 14.9%, in 2008, compared to the prior year primarily due to higher earnings before income taxes and a decrease in the federal production activities deduction, partially offset by the tax benefit associated with an increase in AFUDC equity, which is non-taxable. See Note 5 to the financial statements under "Effective Tax Rate" for additional information. Effects of In nation The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years. FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Florida PSC under cost-based regulatory principles. Prices for electricity relnting to wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power arc regulated by the FERC. Retail rates and earnings arc reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES - "Application of Critical Accounting Policies and Estimates - Electric Utility Regulation" herein and Note 3 to the financial statements for additional information about regulatory matters. The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the Company's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term wi II depend, in part, upon maintaining energy sales which is subject to a number of factors. 1l1ese factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company' s service area. Changes in economic conditions impact sales for the Company, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under " Environmental Matters" for additional information. 11-269 SoCo FOIA Response 001319 MANAGEMENT'S DISCUSSION AND ANALYSIS (conlinuctl) Gulr l'o'>·owrr Company 2010 Annual Reporl approximately 13 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The Company continues to evaluate its future energy and emissions profiles and is participating in volunlary programs lo reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions. PSC Matters Ge11eral The Company's rates and charges for service lo relail customers are subject to the regulatory oversight of the Florida PSC. The Company's rates are a combination of base rntes and severn! separate cost recovery clauses for specific calegories of cosls. These separnte cost recovery clauses address such ilems as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmenlallaws and regulalions. Cosls not addressed through one of the specific cost recovery clauses are recovered through the Company's base rnles. In November 20 I0, the Florida PSC approved the Company's annual cost recovery clause requests for its fuel, purchased power capacily, energy conservalion, and environmental compliance cost recovery factors for 20 II . The net effect of the approved changes to the Company's cosl recovery factors for 20 II is a 2.8% rnte decrease for residenlial cuslomers using 1,000 K WHs per monlh. The bi !ling factors for 20 II are intended to allow the Company lo recover projected 20 II costs as well as refund or collecllhe 20 I 0 over or under recovered amounls in 2011. Revenues for all cosl recovery clauses, as recorded on lhe financial slalements, are adjusled for differences in aclual recoverable costs and amouniS billed in current regulaled rales. Accordingly, changing lhe billing faclor has no significanl effect on lhe Company's revenues or net income, but does impact annual cash flow. See Noles I and 3 to lhe financial stalemenls under "Revenues" and "Retail Regulatory Mauers- Fuel Cost Recovery," respectively, for additional information. F11el Ct1sl Recm•ery The Company petitions for fuel cosl recovery rales to be approved by the Florida PSC on an annual basis. The fuel cosl recovery rales include the costs of fuel and purchased energy. The Company continuously monilors I he over or under recovered fuel cost balance in light of the inherent variabilily in fuel cosls. If, al any time during lhe year, lhe projecled fuel cosl over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the period, lhe Company is required to nolify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested. The change in lhe fuel cost under-recovered balance during 20 I0 was primarily due to higher than expected fuel costs and purchased power energy expenses. At De~:ember 31, 20 I0 and 2009, the under recovered fuel balance was approximately $17.4 million and $2.4 million, respectively, which is included in under recovered regulatory clause revenues, current in the balance sheets. P11rcltased PlJwer Capacity RectJI'l!IJ' The Florida PSC allows the Company to recover its costs for capacily pur~:hased from other power producers under power pur~:hase agreements (PPAs) through a separnte cost recovery component or factor in the Company' s retail energy rates. Like the other specific cost recovery factors included in the Company's retail energy rates, the rntes for purchased capacity are set annually. When the Company enters into a new PPA, it is reviewed and approved by the Florida PSC for cost recovery purposes. As of December 31 , 20 I0 and 2009, the Company had an over recovered purchased power capacity balance of approximately $4.4 million and $1.5 million, respectively, which is included in other regulatory liabilities, current in the balance sheets. Em•irmmtelltal CtJst RectJI'ery• In August 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company's plan for complying with certain federal and slate regulations addressing air quality. The Company's environmental compliance plan as filed in Mar~:h 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The stipulation covers all elements of the current plan that arc scheduled to be implemented in the 2007 through 2011 timeframe. On April I, 2010,the Company liled an update to the plan, which was approved by the Florida PSC on November 15, 20 I 0. The Florida PSC acknowledged that the costs associated with the Company' s CAIR and Clean Air Visibility Rule compliance plans arc eligible for recovery through the environmental cost recovery clause. Annually, the 11-276 SoCo FOIA Response 001326 MANAGEMENT'S DISCUSSION AND ANALYSIS lcontlnutlll GuiCJ>owtr Company 2010 Annual Rtporl Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 20 I0 and 2009, the over recovered environmental balance was approximately $10.4 million and $11.7 mi Ilion, respectively, which is included in other regulatory liabilities, current in the balance sheets. See FINANCIAL CONDITION AND LIQUIDITY- "Capital Requirements and Contractual Obi igations" herein, Note 3 to the financial statements under "Retail Regulatory Matters- Environmental Cost Recovery," and Note 7 to the financial statements under "Construction Program" for additional information. On July 22, 20 I 0, Mississippi Power Company (Mississippi Power) filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurizntion system on Plant Daniel Units I and 2. These units are jointly owned by Mississippi Power and the Company, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million. The project is scheduled for completion in the fourth quarter 2014. The Company's portion of the cost, if approved by the Florida PSC, is expected to be recovered through the environmental compliance recovery clause. Hearings on the certificate request were held with the Mississippi PSC on January 25, 20 II with a final order expected by February 28, 20 II. The ultimate outcome of this matter cannot now be determined. Legislation Stimulus Ftmding On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S. Department of Energy, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. The Company will receive, and will match, $15.5 million under the agreement. The ultimate outcome of this matter cannot be determined at this time. Heu/tlu:ure ReflJrm On March 23, 2010,the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 20IO, the Health Care and Education Reconciliation Act of2010 (together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of2003 (MPDIMA). Since the 2006 tax year, the Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be nctunrially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer's income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer's income tax deduction for the costs of providing Medicare Part D-equivalcnt prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the Company's financial statements. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and re lated employee benefit plan costs. Any future impact on the Company's financial statements cannot be determined at this time. See Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information. Income Tax Matters Tux MelltoJ of AccmmtitrgflJr Repair.~ The Company submitted a change in the tax accounting method for repair costs associated with the Company's generation, transmission, and distribution systems with the Iii ing of the 2009 federal income tax return in September 20 I0. The new tax method resulted in net positive cash flow in 2010 of approximately $8 million for the Company. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 to the financial statements under " Unrecognized Tax Benefits" for additional information. The ultimate outcome ofthis matter cannot be detennined at this time. 11-277 SoCo FOIA Response 001327 MANAGEMENT'S DISCUSSION AND ANALYSIS lronlinueiiJ Gulr Power Company 2010 Annuall{eporl Bo1111s Depreciatia11 On September 27, 2010, the Small Business Jobs and Credit Act of20 10 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 20 II). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus deprecialion for property placed in service after Seplember 8, 2010 and through 20 II (and for certain long-tenn construction projects to be placed in service in 20 12) and 50% bonus depreciation for property placed in service in 20 12 (and for certain long-tenn construction projects to be placed in service in 2013), which could have a significant impact on Jhe future cash flows of the Company. The application of the bonus depreciation provisions in these acts in 2010 provided approximately $36 million in increased cash flow. The Company estimates the potential increased cash flow for 20 ll to be between approximately $40 million and $50 mill ion. Illlema/ Ret'f!llllf! Code Sectimr 199 Domestic Prmluctimr Detluctimr The American Jobs Creation Act of2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of quali lied production activities net income. The percentage was phased in over the years 2005 through 20 I 0. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased lax deductions from bonus depreciation and pension conlributions there was no domestic production deduction available to the Company for 20 I 0 and none is projected to be available for 20 II. See Note 5 to the financial statements under "Effective Tax Rate" for additional infonnation. Other Matters The Company is involved in various other matters being litigated and regulatory mailers that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public henllh and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requiremenls such as opacily and air and waler quality standards, has increased generally lhroughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other em issions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for currenl proceedings nol specifically reported herein, management does not anticipale thallhe liabilities, if any, arising from such currenl proceedings would have a malerial adverse effect on the Company's financial slatemenls. See Nole 3 to the financial statemenls for infonnation regarding material issues. ACCOUNTING I'OLICIES Application or Critical Accounting l'olicies nnd Estimates The Company prepares its financial statemenls in accordance with GAAP. Significanl accounling policies are described in Note I to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce eslimatesthat nre significantly different from those recorded in the financial statements. Senior management has reviewed nnd discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors. Electric Utility Regulatio11 The Company is subject to retail regulation by the Florida PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is pennitted lo charge customers based on allowable costs. As a resull, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemnking process, the regulators may require lhe inclusion of costs or revenues in periods different than when they would be recognized by a non-regulnted company. This treatment may result in the deferral of expenses and the recording ofrelated regulatory assets based on anticipated future recovery through rates or the deferral of gnins or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a resull of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, ll-278 SoCo FOIA Response 001328 MANAGEMENT'S DISCUSSION AND ANALYSIS (tonli•uul) Gulf l'ou·rr Company 2010 A. .ual Ittport the accounting estimates inherent in specific costs such as depreciation and pension and postretirement benefits have less of a direct impact on the Company's results of operations than they would on a non-regulated company. As renected in Note I to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements. Ctmti11gelll Ob/igutio11s The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's financial statements. These events or conditions include the following: • Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, coal combustion by products, including coal ash, control oftoxic substances, hazardous and solid wastes, and other environmental matters. • Changes in existing income tax regulations or changes in IRS or state revenue department interpretations of existing regulations. • Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party. • Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as 11 defend11nt. • Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA. U11hilled Re1•em1e.s Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered nnd billed, arc estimated. Components of the unbilled revenue estimates include total KWI-I territorial supply, total KWI-I billed, estimated total electricity lost in delivery, and customer usage. These components cnn nuctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictnble and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Compnny's results of operations. Pcnsitm und Otlter Pt~slreliremenl Benefits The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. 11-279 SoCo FOIA Response 001329 MANAGEMENT'S DISCUSSION AND ANALYSIS (rontinurdJ Gutr Power Company 2010 Annual Rrport Key elements in determining the Company's pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected Jong-tenn return on postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-tenn rate of expected returns on various asset classes to the Company's target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. A 25 basis point change in any significant assumption would result in a $1.1 million or Jess change in total benefit expense and a $13 million or less change in projected obligations. FINANCIAL CONDITION AND LIQUIDITY Overview The Company's financial condition remained stable at December 31,2010. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Sec "Sources of Capital" and "Financing Activities" herein for additional information. The Company's investments in the qualified pension plan remained stable in value as of December 31, 2010. In December 2010, the Company contributed $28 million to the qualified pension plan. Net cash provided from operating activities totaled $267.8 million,$ 194.2 million, and $147.9 million for 2010, 2009, and 2008, respectively. The $73.5 million increase in net cash provided from operating activities in 2010 was primarily due to a $99.2 million increase from deferred income taxes related to bonus depreciation and a $90.9 million decrease in fuel inventory, partially offset by a $109.4 million increase in accounts receivable related to fuel cost and a $25.7 million decrease related to the qualified pension plan. The $46.3 million increase in net cash provided from operating activities in 2009 was primarily due to a $134.5 million reduction in accounts receivable related to fuel cost, partially offset by a $40.5 million decrease in deferred income taxes and a $38.4 million increase in fuel inventory. The $69.1 million decrease in net cash provided from operating activities in 2008 was due primarily to a $61.0 million increase in cash used for the under recovered regulatory clause related to fuel. Net cash used for investing activities totaled $308.4 million, $468.4 million, and $348.7 million for 2010,2009, and 2008, respectively. The changes in cash used for investing activities were primarily due to gross property additions to utility plant of$285.4 million, $450.4 million, and $390.7 million for 20 I0, 2009, and 2008, respectively. Funds for the Company's property additions were provided by operating activities, capital contributions, and other financing activities. Net cash provided from financing activities totaled $48.4 million, $279.4 million, and $198.8 million for 20 I0, 2009, and 2008, respectively. The $231.0 million decrease in net cash provided from financing activities in 20 I 0 was due primarily to $194.4 million higher issuances of pollution control revenue bonds and common stock in 2009 and a net $54.3 million decrease in senior notes outstanding. The $80.6 million increase in net cash provided from financing activities in 2009 was due primarily to $258.4 million in higher debt issuances and cash raised from a common stock sale, partially offset by a $157.0 million decrease in notes payable. The $178.6 million increase in net cash provided from financing activities in 2008 was due primarily to the issuance of$11 0 million in long-term debt and $50 million in short-term debt, and a $49.1 million change in commercial paper cash flows in 2008. The increase was partially offset by the issuance of$85 million in senior notes in 2007. Significant balance sheet changes in 2010 include increases in customer accounts receivable of $10.1 million; under recovered regulatory clause revenues of$15.4 million; other regulatory assets, deferred of $28.9 million, primarily due to an increase in PPA deferred capacity expense, and accumulated deferred income taxes of$85.5 million. Total property, plant, and equipment increased by $194.9 million primarily due to environmental control projects. Securities due within one year decreased by $30.0 million primarily due to senior notes maturing in the first quarter 20 I 0. Employee benefit obligations decreased by $32.6 million primarily due to funding of the Company's qualified pension plan. The Company's ratio of common equity to total capitalization, including short-term debt, was 43.1% in 2010, 43.4% in 2009, and 42.9% in 2008. See Note 6 to the financial statements for additional information. 11-280 SoCo FOIA Response 001330 MANAGEMENT'S DISCUSSION AND ANALYSIS Crontinutlll Gulr l'owrr Company 2010 Annual Rtpurl Sources of Capital The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, and short-term indebtedness. However, the amount, type, and timing of any future financings, if needed, will depend on prevailing market conditions, regulatory approval, and other factors. Security issuances are subject to regulatory approval by the Florida PSC pursuant to its rules and regulations. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended ( 1933 Act). The amounts of securities authorized by the Florida PSC, as well as the amounts, if any, registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. The Company's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term-debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At December 31, 2010, the Company had approximately $16.4 million of cash and cash equivalents, along with $240 million of unused committed lines of credit with banks to meet its short-term cash needs. These bank credit arrangements will expire in 2011 and $210 million contain provisions allowing one-year term loans executable at expiration. In February 20 II, the Company renewed a $30 mi Ilion credit facility. The Company plans to renew the other lines of credit during 20 II prior to their expiration. These credit arrangements provide liquidity support to the Company's variable rate pollution control revenue bonds and commercial paper borrowings. As of December 31, 20 I 0, the Company had $69 mill ion outstanding of pollution control revenue bonds requiring liquidity support. In addition, the Company has substantial cash flow from operating activities and access to the capital markets to meet liquidity needs. Sec Note 6 to the financial statements under "Bank Credit Arrangements" for additional infonnation. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other traditional operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support. At December 31, 20 I0, the Company had $1.2 million in notes payable outstanding related to other energy services contracts. At December 31, 2010, the Company had approximately $92.0 million of commercial paper borrowings outstanding with a weighted average interest rate of OJ% per annum. During 2010, the Company had an average of$44 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $1 08 million. At December 31, 2009, the Company had $88.9 million of commercial paper borrowings outstanding with a weighted average interest rate of 1.0% per annum. During 2009, the Company had an average of $51.7 mi Ilion of commercial paper outstanding at a weighted average interest rate of 1.0% per annum and the maximum amount outstanding was $152.1 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash. Finnncing Activities In January 20 I0, the Company issued to Southern Company 500,000 shares of common stock, without par value, and realized proceeds of$50 million. The proceeds were used to repay a portion of the Company's short-term debt and for other general corporate purposes. In April 2010, the Company issued $175 million aggregate principal amount of Series 20 lOA 4.75% Senior Notes due April 15, 2020. The net proceeds were used to repay at maturity $140 million aggregate principal amount of Series 2009A Floating Rate Senior Notes due June 28, 20 I0, to repay a portion of its outstanding short-term debt, and for general corporate purposes, including the Company' s continuous construction program. The Company settled $100 million of interest rate hedges related to the Series 20 IOA Senior Note issuance at a gain of approximately $1.5 million. The gain will be amortized to interest expense over I0 years. 11-281 SoCo FOIA Response 001331 MANAGEMENT'S DISCUSSION AND ANALYSIS l·,r Company 2010 Annual Rtporl natural gas purchases. The Company continues to manage a financial hedging program for fuel purchased to operate its electric generating fleet implemented per the guidelines of the Florida PSC. The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the years ended December 31 were as follows: 2010 2009 Changes Changes Fair Value (illtlwwwmls) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes<•l Contracts outstanding at the end of the period, assets (liabilities). net $ (13,687) 17,613 (15,154) $ (11,228) $ (31,161) 41,683 (24,209) $ (13,687) (aI Current period changes also include the changes in fair value of new conlracts cnlercd into during Ihe period, if any The change in the fair value positions of the energy-related derivative contracts for the year ended December 3 l, 20 l 0 was nn increase of$2.5 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thcrmnl units (mmBtu) and the price of natural gas. AI December 31, 20 I 0, the Company had a net hedge volume of 19.6 million mmBtu with a weighted average contract cost approximately $0.67 per mmBtu above market prices and 10.7 million mmBtu at December 31, 2009 with a weighted average contract cost approximately $1.29 per mmBtu above market prices. Natural gas settlements are recovered through the Company's fuel cost recovery clause. At December 31, 2010 and 2009, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and arc related to the Company's fuel hedging program. Therefore, gains and losses are initially recorded as regulatory linbilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clnuse. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented. The Company uses over-the-counter contracts that arc not exchange traded but are fair valued using prices which arc actively quoted, and thus fall into Level 2. See Note 9 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 3 I, 20 I 0 were as follows: December 31,2010 Fair Value Measurements Maturity Total Fair Value Years 2&3 Years 4&5 Ycar I (in lhmuumls) Levell Level 2 Lcvel3 Fair value of contracts outstanding at end of period $ $ $ $ (11,228) (7,609) (3,619) $ (II ,228) $ (7,609) $ (3,619) $ The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterpartics that have investment grade credit ratings by Moody's Investors Service and Standard & Poor's, a division of The McGraw I-I ill Companies, Inc., or with countcrparties who have posted collateral to cover potential credit exposure. Therefore, the Company docs not anticipate market risk exposure from nonperformance by the countcrparties. For additional infonnation, see Note I to the financial statements under "Financial Instruments" and Note I0 to the financial statements. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the usc of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the usc and cost of over-the-counter derivatives. The impact, if any, cannot be dctennined until regulations are finalized. 11-283 SoCo FOIA Response 001333 MANAGEMENT'S DISCUSSION AND ANALYSIS (coalintMd) G1lr rowrr Comp ..y 20t0 ,\nn .. l Rr 20 II. up to $55.6 million for 2012, nnd up to $t07.3 million for 2013. At December 31, 2010, significant purchase commilmcllls were outstanding in connection with the construction pmgrnm. (g) As pan of the Company•s program to reduce S0 2 emissions fmm its coal plants. the Company has entered into vurious long·tcnn commitments for the procurement oflimcstune to be usell in flue gas dcsulfuri7.ntion equipment. (h) Natural gas purchase commilments ure based on various indices at the lime ofdctivery. Amounls rcllcetcd hnw been cstimuted b;JScd on the New York Mercantile Exchange future prices at December 3 I, 20 I 0. (i) 1l1c capacity and transmission relutcd costs nssociutcd with I'PAs arc recovered through the purchased power capacity clause. SL'C Notes 3 and 7 to the linancial statements for additional inforrnnlion. (j) Long-term service agm:mcnts include price escalation bn.~cd on inflation inlliccs. (k) 'l11c Company forecasts contributions to the qualified pension nnd other postretirement benefit plans over n thrL-c•ycar period. ll1c Company dncs not expect to be required to make any eontribulions to the qualified pension plan during the next three years. Sec Note 2 to the financial statements for additional information related lo the pension and other postretirement bcnefil plans, including estimated benefit payments. Ccnain benefit payments will be malic through the relnled bene lit plans. Other benefit payments will be mode from the Company's corporate assc1s. 11-215 SoCo FOIA Response 001335 MANAGEMENT'S DISCUSSION AND ANALYSIS (toncinutdl GulrJ'owu Comp•ny 2010 Annul Rtporl Cautionary Statement Regarding FonYard-Looking Statements The Company's 20 I0 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, fuel cost recovery and other rate actions, environmental regulations and expenditures, future earnings, access to sources of capital, economic recovery, projections for the qualified pension plan and postretirement benefit trust contributions, financing activities, start and completion of construction projects, impacts of adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 20 I0, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 20 I 0, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forwardlooking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which the Company is subject, DS well as changes in application of existing laws and regul11tions; current and future litigation, regulatory investigations, proceedings or inquiries, including FERC matters and the EPA civil11ctions against the Comp11ny; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; VDriDtions in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population, and business growth (and declines), and the effects of energy conserYDtion measures; available sources and costs of fuels; effects of inri11tion; ability to control costs and avoid cost overruns during the development and construction of facilities; investment performance of the Company's employee benefit plans; Ddvances in technology; state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers; the direct or indirect effect on the Company' s business resulting from terrorist incidents and the threat of terrorist incidents; interest rate rtuctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings; the ability of the Company to obtain additional generating capacity at competitive prices; catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC. The Company expressly disclaims any obligation to update any rorward-looklng statements. 11-286 SoCo FOIA Response 001336 STATEMENTS OF INCOME For the Years Ended December 31,2010,2009, and 2008 Gulf Power Company 2010 Annual Report 2010 2009 2008 (ill tlmuscmclf) Operating Revenues: Retail revenues Wholesale revenues, non-affiliates Wholesale revenues, affiliates Other revenues Total o~eratins revenues Operating Expenses: Fuel Purchased power, non-affiliates Purchased power, affiliates Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total o~eratins ex~enses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Interest income Interest expense, net of amounts capitalized Other income (ex~ense), net Total other income and (exEense) Earnings Before Income Taxes Income taxes Net Income Dividends on Preference Stock Net Income After Dividends on Preference Stock $1,308,726 109,172 110,051 62,260 1,590,209 $1,106,568 94,105 32,095 69,461 1,302,229 $1,120,766 97,065 106,989 62,383 1,387,203 742,322 41,278 55,948 280,585 121,498 101,778 1,343,409 246,800 573,407 23,706 68,276 260,274 93,398 94,506 1,113,567 188,662 635,634 29,590 79,750 277,478 84,815 87,247 1,194,514 192,689 23,809 423 (38,358) (4,075) (18,201) 170,461 53,025 117,436 6,203 $111.233 9,969 3,155 (43,098) (4,064) (34,038) 158,651 54,103 104,548 6,203 $ 98.345 7,213 123 (51,897) p,011~ ~47,572! 199,228 71,514 127,714 6,203 $1211511 The accompanying notes nrc an integral part ufthcsc linnalciul statements. 11-287 SoCo FOIA Response 001337 STATEl\IENTS OF CASII I'LOWS Fur tile \'tars Ended Drcrmhrr 31, 2010,211119,and 211118 Gulf l'o"·u Company 2010 Annunllhport 20111 2009 2008 (m thmucmtb) Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating uctivities -Depreciation and amortization, total Deferred income taxes Allowance for equity funds used during construction Pension, postretirement, und other employee benefits Stock based compensation expense Hedge settlements Other, net Changes in certain current assets and liabilities --Receivables -Prepayments -Fossil fuel stock ·Materials and supplies -Prepaid income taxes ·Property damage cost recovery -Other current assets ·Accounts payable -Accrued taxes ·Accrued compensation -Other current liabilities Net cash provided from operating nctivities lnnsting Actil·ities: Property additions Investment in restricted cash from pollution control revenue bonds Distribution of restricted cash from pollution control revenue bonds Cost of removal net of salvage Construction pnyubles Payments pursuant to long-tenn servke agreements Other investing activities Net cash used for investing activities Finuncing Activities: lnereu.~e (decrease) in notes payable, net Proceeds-· Common stock issued to parent Capitol contributions from parent company Pollution control revenue bonds Senior notes Other long·tenn debt issuances Redemptions·· Pollution control revenue bonds Senior notes l'uyment of preference stock dividends Payment of common stock dividends Other financing activities Net cu.~h provided from linancing activities Net Change in Cnsh und Cnsh E•Juh·ulents Cnsh uml Cosh Eguil·nlents nt lleginning of Year Cush und Cash EcJuimlenl.~ 111 End nf\'eur Supplemental Cush l'low Information: Cash paid during the period for·· Interest (net of $2,875, $9,489 and $3,973 cupitali1.cd. respectively) Income taxes (net of refunds) Noncash decrease in notes payable related to energy services Noncash transactions • accrued property odditions at year-end Sl27,714 $ 117,436 $ 104.548 127,897 82,6111 (7,213) (23,964) 1,1111 l,S311 (4,126) 99,564 (16.545) (23,809) 1.769 933 (5,173) 93,607 23,949 (9,969) 1.585 765 (5.2211) (4,934) (36,687) (111,796) 15,766 (6,2SI) (29,6311) 83,245 (192) (75.145) (1,642) (6.355) 10.746 (12) 7.890 (2.404) (6.3311) IU,255 194,231 (49,886) (310) (36,765) 8.927 (416) 26,143 3 (4.561) (6,511) 570 6.417 147,942 (421.309) (49,188) 42.841 (9,751) (23.603) (7.421) (5) (468.436) (377.790) 55 15,683 1,427 5,122 7,471 267,7811 (285,793) 6,347 (1,145) (21,S81) (6,1111) (262) (308,445) (8,713) 37.244 (5.468) 6.044 (3<18,(183) 4,451 (49,599) 107,438 511,01111 2,242 21,01111 3011,01111 135,000 22,032 130.4011 140,1100 75,32<1 37.0110 110.000 s (215,515) (6,2113) ( 1114,31111) (3.253) <18,422 7,757 8,677 16,434 S-12,521 17,224 14,475 (1,214) (6.203) (89.3011) { 1.677) 279.439 5.234 3.<143 $ 8.677 $40,336 73.889 (8,309) 42.050 (37,0110) (1.300) (6,057) (81 ,700) {4.869) 198,836 (1.905) 5.348 $ 3.443 $39.956 40,176 61.006 ll1e accompanyinj notes Me an integml pan or these (in;ancialsuuements 11-288 SoCo FOIA Response 001338 BALANCE SHEETS At December 31,2010 and 2009 Gulr Power Company 2010 Annual Report Assets 2010 2009 (ill 1/rousum/s) Current Assets: Cash and cash equivalents Restricted cash and cash equivalents Receivables -Customer accounts receivable Unbilled revenues Under recovered regulatory clause revenues Other accounts and notes receivable Affiliated companies Accumulated provision for uncollectible accounts Fossil fuel stock, at average cost Materials and supplies, at average cost Other regulatory assets, current Prepaid expenses Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Plant in service, net of depreciation Construction work in progress Total property, plant, and equipment Other Property and Investments Deferred Charges and Other Assets: Deferred charges related to income taxes Prepaid pension costs Other regulatory assets, deferred Other deferred charges and assets Total deferred charges and other assets Total Assets $ 16,434 $ 8,677 6,347 74,377 64,697 19,690 9,867 7,859 (2,014) 167,155 44,729 20,278 58,412 3,585 485,069 64,257 60,414 4,285 4,107 7,503 (1,913) 183,619 38,478 19,172 44,760 3,634 443,340 3,634,255 1,069,006 2,565,249 209,808 2,775,057 16,352 3,430,503 1,009,807 2,420,696 159,499 2,580.195 15,923 46,357 7,291 219,877 34,936 308,461 $3 584 939 39,018 190,971 24,160 254.149 $3.293.607 The accompanyins notes nrc nn intesrnl pan of these linunciul statements 11-289 SoCo FOIA Response 001339 BALANCE SHEETS At December 31,2010 and 2009 Gulf Power Company 2010 Annual Report Liabilities and Stockholder's Equity 2010 2009 (ill tlumsatzds) Current Liabilities: Securities due within one year Notes payable Accounts payable -Affiliated Other Customer deposits Accrued taxes -Accrued income taxes Other accrued taxes Accrued interest Accrued compensation Other regulatory liabilities, current Liabilities from risk management activities Other current liabilities Total current liabilities Long-Term Debt (Sec accompanying statements) Deferred Credits and Other Liabilities: Accumulated deferred income ta.xes Accumulated deferred investment ta.x credits Employee benefit obligations Other cost of removal obligations Other regulatory liabilities, deferred Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Preference Stock (Sec accompanying statements) Common Stockholder's Equity (Sec accompanying stutcmcntsl Total Liabilities and Stockholder's Equity Commitments and Contingent Matters (Sec notes) $110,000 93,183 $140,000 90,331 46,342 68,840 35,600 47,421 80,184 32,361 3,835 7,944 13,393 14,459 27,060 9,415 19 766 449,837 1,114,398 1,955 7,297 10,222 9,337 22,416 9,442 20,092 471,058 978,914 382,876 8,109 76,654 204,408 42,915 132,708 847,670 2,411,905 97,998 1,075,036 $3,584,939 297,405 9,652 109,271 191 ,248 41,399 92.370 741,345 2, 191,317 97,998 1,004,292 $3.293.607 The accompanying notes nrc nn intcgml pan of these financial stutcmcnls 11-290 SoCo FOIA Response 001340 STATEMENTS OF CAPITALIZATION At December 31,2010 and 2009 Gulf Power Company 2010 Annual Report 2009 2010 (in Long Term Debt: Long-tenn notes payable 4.35% due 2013 4.90% due 2014 4.75% to 5.90% due 2016-2044 Variable rates (0.35% at 111110) due 20 I 0 Variable rates (0. 71% at 1/1/11) due 20 II Total lons-tenn notes Ea~able Other long-tenn debt -Pollution control revenue bonds -1.50% to 6.00% due 2022-2049 Variable rates (0.39% to 0.47% at 111111) due 2022-2039 Total other lons-tenn debt Unamortized debt discount Totallong-tenn debt (annual interest requirement-- $51.9 million) Less amount due within one ~ear Lons-tcrm debt excludins amount due within one ~ear Prcrerrcd and Prcrcrcncc Stock: Authorized - 20,000,000 shares--preferred stock - I 0,000,000 shares--preference stock Outstanding- $1 00 par or stated value -- 6% preference stock -- 6.45% preference stock - 1,000,000 shares (non-cumulative) Total preference stock (annual dividend reguirement -- $6.2 million) Common Stockholder's Equity: Common stock, without par value-Authorized - 20,000,000 shares Outstanding- 2010: 3,642,717 shares Outstanding- 2009: 3,142,717 shares Paid-in capital Retained earnings Accumulated other comErehensive income (loss) Total common stockholder's eguit~ Total Caeitalization $ 60,000 75,000 676,971 tlumsarul~) $ 110,000 921,971 239,625 69,330 308,955 {6,528) 218,625 69,330 287,955 (6,527) 1,224,398 110,000 1,114,398 1,118,914 140,000 978,914 53,886 44,112 53,886 44,112 97,998 97,998 ~2,727) 1,075,036 $212871432 2009 (perce/11 oftotal) 60,000 75,000 452,486 140,000 110,000 837,486 303,060 538,375 236,328 2010 253,060 534,577 219, 117 (2,462) 1,004,292 $2.081.204 48.7% 47.0% 4.3 4.7 47.0 100.0% 48.3 100.0% The accompanying notes ure an integral part of these linancial statements. 11-291 SoCo FOIA Response 001341 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY F'or the Years Ended December 31,2010, 2009,nnd 2008 Gulf Power Com pnny 2010 Annunl Report Number or Common Shares Issued Common Stock Pnid-ln CRf!iiRI Accumulated Other Comprehensive Income {Loss) Retnined Earn in~ Totnl (ill tlrousa11dt) Balance at December 31,2007 Net income after dividends on preference stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Chanse in benefit elan measurement date Balance at December 31,2008 Net income after dividends on preference stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Chanse in benefit elan measurement date Balance at December 31,2009 Net income after dividends on preference stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balnnce at December 31 22010 1,793 $118,060 $435,008 $181,986 $(3,799) 98,345 98,345 76,539 ( 1, 133) 1,793 1,350 118,060 511,547 (81,700) (1,214) 197,417 (4,932) 111,233 (89,300) (233) 219,117 135,000 23,030 2,470 (89,300) (233) 1,004,292 23,030 2,470 253,060 500 50,000 534,577 (2,462) 121,511 3,798 (265) 32643 $303,060 $538,375 76,539 (1,133) (81,700) (1,214) 822,092 111,233 135,000 3,143 $731,255 {104,300! $236.328 $(2,727) 121,511 50,000 3,798 (265) {104.300! $1,075,036 The ;~~;companying notes arc an integral part of these financial statements. 11-292 SoCo FOIA Response 001342 STATEMENTS OF COMPREHENSIVE INCOME For the Ye11rs Ended December 31,2010, 2009,and 2008 Gulr Power Company 2010 Annual Report 2009 2010 2008 (illtllousa/lds) Net income after dividends on preference stock Other comprehensive income (loss): QualifYing hedges: Changes in fair value, net of tax of$(542), $1,132, and$( I,077), respectively Reclassification adjustment for amounts included in net income, net oftax of$376, $419, and $366, respectively Total other comprehensive income (loss) Comprehensive Income $121,511 $111,233 $98,345 (863) 1,803 (1,716) 598 (265) $121,246 667 2,470 $113.703 583 (I ,133) $97.21 2 The accompanying notes urc an integral part or these financial statements. 11-293 SoCo FOIA Response 001343 NOTES TO FINANCIAL STATEMENTS Gulrl'o,.·er Company 2010 ,\nnual l(tporl I. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Gulf Power Company (the Company) is a wholly owned subsidiarY of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies- the Company, Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), and Mississippi Power Company (Mississippi Power)- are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiarY companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiarY companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company's nuclear power plants. Certain prior years' data presented in the financial statement have been reclassified to conform to the current year presentation. The equity method is used for entities in which the Company has significant innuence but does not control. The Company is subject to regulation by the Federal Energy RegulatorY Commission (FERC) and the Florida Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatorY commissions. The preparation of financial statements in conformity with GAAP requires the usc of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statement have been reclassified to conform to the current year presentation. Affiliate Trnnsnclions The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $99 million, $87 million, and $86 million during 20 I0, 2009, and 2008, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they nrc reasonable. The FERC pern1its services to be rendered at cost by system service companies. The Company has agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $8.9 million, $3.9 million, and $8.1 million and Mississippi Power $25.0 million, $20.9 million, and $22.8 million in 20 I0, 2009, and 2008, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information. The Company entered into a power purchase agreement (PPA), with Southern Power for a total of approximately 292 megawatts (MWs) annually from June 2009 through May 2014. Expenses associated with the PPA were $14.7 million, $13.2 million, and none in 2010, 2009, and 2008, respectfully. These costs have been approved for recovery by the Florida PSC through the Company's purchase power capacity cost recoverY clause. Additionally, the Company had $4.2 million of deferred capacity expenses included in prepaid expenses and other regulatorY liabilities, current in the balance sheets at December 31,2010 and 2009, respectfully. See Note 7 under "Fuel and Purchased Power Commitments" for additional information. The Company has an agreement with Alabama Power under which Alabama Power will make transmission system upgrades to ensure firm deliverY of energy under a non-affiliate PPA. Revenue requirement obligations to Alabama Power for these upgrades are estimated to be $135 million for the entire project. These costs are estimated to begin in 20 I 2 and will continue through 2023. These costs have been approved for recovery by the Florida PSC through the Company's purchase power capacity cost recoverY clause and by FERC in the transmission facilities cost allocation tariff. 11·294 SoCo FOIA Response 001344 NOTES (co•llnuclll Gutr !'ower Company 2010 Ann .. t Rtporl TI1e Company provides incidental services to and receives such services from other Southern Company subsidiaries which arc genernlly minor in durntion and amount. Except as described herein, the Company neither provided nor received any significant services to or from affiliates in 2010,2009, or 2008. The traditional operating companies, including the Company, and Southern Power jointly enter into various types of wholesale energy, naturnl gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. Sec Note 7 under "Fuel and Purchased Power Commitments" for additional information. In 20 I0, the Company purchased an assembly fluted compressor from Georgia Power and an unbucketed turbine rotor from Southern Power for $3.9 million and $6.3 million, respectively. The Company also sold a universal distance piece to Southern Power, a compressor rotor and blades to Georgia Power and a turbine rotor and blades to Mississippi Power for $0.6 million. $3.9 million, and $6.2 million, respectively. There were no significant affiliate transactions for 2009. In 2008, the Company sold a turbine rotor assembly and a distance piece component to Southern Power for $9.4 million and $0.7 million, respectively. These affiliate transactions were made in accordance with FERC and state PSC rules and guidelines. II-29S SoCo FOIA Response 001345 NOTES (rontinuul) Gulr Po'l'·rr Company 2010 Annual Rrporl Regulatory Assets and Liabilities The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the eiTects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2010 2009 Note (in thousands) Deferred income tax charges Deferred income tax charges - Medicare subsidy Asset retirement obligations Other cost of removal obligations Deferred income tax credits Loss on reacquired debt Vacation pay Under recovered regulatory clause revenues Over recovered regulatory clause revenues Property damage reserve Fuel-hedging (realized and unrealized) losses Fuel-hedging (realized and unrealized) gains PPA charges Generation site selection/evaluation costs Other assets Environmental remediation PPA credits Other liabilities Retiree benefit ~Inns, net Total assets (liabilities), net 42,352 4,332 (4,31 0) (204,408) (9,362) 15,874 8,288 17,437 (17,703) (27,593) 15,024 (2,376) 52,404 12,814 833 61,749 (7,536) (930) 741930 $ 31,819 $ $ 39,018 (4,371) ( 191 ,248) (11,412) 14,599 8,120 2,384 (14,510) (24,046) 15,367 (190) 8,141 8,373 131 65,223 (7,536) (715) 91,055 $ (1,617! (a) (b) (aj) (a) (a) (c) (dj) (e) (e) (I) (gj) (gj) (j,k) (I) (ej) (hj) (j,k) (I) ~ilil Nolc: 'lllc recovery and nmurti7.nlion periods for these regulatory assets and (liabilities) nrc as follo"'s: (a) (b) (c) (d) (c) (f) (g) (h) (i) (j) (k) (I) Asset retirement and removal assets and liabilities nrc recorded, deferred income tax assets me recovered, and deferred income lax linbililies nrc umor1i1.cd over I he related properly Iives, which may runge up to 65 years. Asset relirement and removal liabilities will be scllled and trued up following completion of the related activities. Recovered and umor1ir.cd over periods not exceeding l4 years. Sec Nole 5 under "Current and Deferred Income Tuxcs"li1r additional information. Recovered over cilhcr lhe remaining life of the original issue or, if refinanced, over the life of the new issue, which may runge up to40 years. Rc,ordcd as earned by employees and recovered as paid, gcncmlly wilhin one year. Re,orded and re,ovcred or nmor1iz.cd as approved by lhe !'lorida I'SC, generally wilhin one year. Recorded nnd re,overed or amortized as approved by the Florida r•sc. Fuel·hedging assets nnd liabilities nrc rccogni1.cd over the life orthc underlying hedged purchase conlmcls, which generally do not exceed four years. Upon final scnlcment, costs nrc rt..:ovcrcd lhrough the fuel cost recovery clause. Recovered through lhe envinmmcnlnl cosl recovery clause when the remediation is performed. Recovered and nmor1izcd over the average remaining service period which may mnge up to IS years. Includes S 166 thousand related to other postretiremcnl benefits. Sec Nole 2 nnd Note 5 for additional information. Nol earning n return as o1Tse1 in nne base by n corresponding asset or linbilily. Recovered over lhe life oflhc I'!'A for periods up to 14 years. Deferred pursuan11o Florida Statute while the Company continues to evaluate certain potential new generation projt'Cts. In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write oiT or reclassify to accumulated other comprehensive income (OCl) related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. ll-2% SoCo FOIA Response 001346 NOTES (conliA•ttll Gulrl'o"u Company 2010 Annual Rtporl Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projecled fuel cost over or under recovery is expected to exceed I 0% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustmenls to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. Sec Note 3 under "Retail Regulatory Matters" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than I% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emissions allowances as they arc used. Income Rnd Other TRxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remiued to these agencies arc presented net on the statements of income. In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional infom1ation. rroperty, rlant, nnd Equipment Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction. The Company's property, plant, and equipment consisted of the following at December 31 : 2010 2009 (ill lfiiiiiStJII· 2010 Ann ..J Rtporl In February 2009, the Company submined its 2009 ECO Plan notice which proposed an increase in annual revenues for the Company of approximately $1.5 million. In June 2009,the Mississippi PSC approved the ECO Plan with the new rates effective in June 2009. On July 22, 20 I0, the Company filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units I and 2. These units are jointly owned by the Company and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million. The project is scheduled for completion in the fourth quarter 2014. The Company's portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through the ECO Plan. 1-learings on the certificate request were held by the Mississippi PSC on January 25,2011 with a final order expected by February 28, 20 II. The ultimate outcome of this maller cannot be determined at this time. Fuel Co.f t Rectwery The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred on November I 5, 20 I0. The Mississippi PSC approved the retail fuel cost recovery factor on December 7, 2010, with the new rates effective in January 20 II. TI1c retail fuel cost recovery factor will result in an annual decrease in an amount equal to 5.0% of total 20 I0 retail revenue. At December 31, 20 I0, the amount of over recovered retail fuel costs included in the balance sheets was $55.2 million compared to $29.4 million at December 31, 2009. The Company also has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective January I, 20 II, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 3.5% of total 20 I0 MRA revenue. EITcctivc February I, 20 II, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 7.0% of total 20 I 0 MB revenue. At December 31, 2010, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $17.5 million and $4.4 million compared to $16.8 million and $2.4 million, respectively, at December 31, 2009. The Company's operating revenues arc adjusted for diiTcrcnces in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this decrease to the billing factor will have no significant effect on the Company's revenues or net income, but will decrease annual cash flow. In October 2010, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of the Company's fuelrelated expenditures included in the retail fuel adjustment clause and energy cost management clause (ECM) for 20 I0. TI1e audit is scheduled to be completed in 20 II. The ultimate outcome of this maller cannot be determined at this time. A similar audit was conducted beginning in August2009 for the years 2009 and 2008. The audit was completed in December 2009 with no audit findings. In October 2008, the Mississippi PSC opened a docket to investigate and review interest and carrying charges under the fuel adjustment clause for utilities within the State of Mississippi including the Company. In March 2009, the Mississippi PSC issued an order to apply the prime rate in calculating the carrying costs on the retail over or under recovery balances related to fuel cost recovery. In May 2009, the Company filed the carrying cost calculation methodology as part of its compliance filing. Legislation Stimulu.f Fu11di11g On April28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S. Department of Energy (DOE), fornmlly accepting a $165 million grant under the American Recovery and Reinvestment Act of2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. The Company will receive, and will match, $25.9 million under this agreement. The ultimate outcome of this matter cannot be detennined at this time. Ueultllcurc RcftJrm On March 23, 2010, the PPACA was signed into law and, on March 30,2010, the Acts, which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced ns part of the Medicare Prescription Drug, Improvement, and Modernization Act of2003 (MPDIMA). Since the 2006 tax year, the Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer's income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer's income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by 11-349 SoCo FOIA Response 001399 MANAGEMENT'S DISCUSSION AND ANALYSIS (continutdl Mississippi l'owrr Compan)' 2010 Annual Rrporl the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in lax law must be recognized in the period enacted regardless of the effective date; however, ns a result of state regulatory trentment, this change had no material impact on the Company's financial statements. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and related employee benefit plan costs. Any future impact on the Company's financial statements cannot be detennined at this time. See Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information. Income Tnx Matters Tax Methot/ cifAccmmtillg for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company' s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 20 I0. The new tax method resulted in net positive cash flow in 2010 of approximately $4.7 million for the Company. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized Ia." benefit has been recorded for the change in the tax accounting method for repair costs. Sec Note 5 to the finnncinl statements under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this rnntter cnnnot be detcrn1ined at this time. Bmms Depreciatia11 On September 27, 2010, the Small Business Jobs and Credit Act of20 10 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 20 II). Additionally, on December 17, 20 I0, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 20 I0 and through 20 II (and for certain long-tern1 construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which could have a significant impact on the future cash flows of the Company. The application of the bonus depreciation provisions in these acts in 20 I 0 provided approximately $28 million in increased cash flow. The Company estimates the potential increased cash flow for 20 II to be between approximately $20 million and $25 million. llltemul Rel'l!lllle CcJt/e Sectio11 199 Dm11e.~tic Prmlucticm Detl11ctitm The American Jobs Creation Act of2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The deduction is equal ton stated percentage of quali lied production activities net income. The percentage is phased in over the years 2005 through 20 I 0. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 20 I0, and none is projected to be available for 20 II. See Note 5 to the financial statements under " Effective Tax Rate" for additional information. Integrated Coal Gasification Combined Cycle In January 2009, the Company filed for a Certificate of Public Convenience and Necessity (CPCN) with the Mississippi PSC to allow the acquisition, construction, and operation of the IGCC project located in Kemper County, Mississippi. The Kemper IGCC would utilize an IGCC technology with an output capacity of582 megawatts (MWs). The estimated cost of the plant is $2.4 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2). The plant will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. In conjunction with the plant, the Company will own a lignite mine and equipment and will acquire mineral reserves located around the plant site in Kemper County. The estimated capital cost of the mine is approximately $214 million. On Mny 27, 2010, the Company executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations. The agreement is effective June I, 2010 through the end of the mine reclamation. The plant, subject to federal and state reviews nnd certain regulatory approvals, is expected to begin commercial operation in May 2014. As part of its filing, the Company requested certain rate recovery treatment in accordance with the Base load Act. 11-350 SoCo FOIA Response 001400 MANAGEMENT'S DISCUSSION AND ANALYSIS lIISrllltf.t) Other regulatory assets, deferred Employee benefit obligations $ 8,618 (60,733) $ 14,332 (63,482) Presented below arc the amounts included in regulatory assets at December 31, 20 I0 and 2009 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 20 II. 2010 2009 Estimated Amortization in 2011 (illlfiOII.WIIIf.t) Prior service cost Net (gain) loss Transition obligation Other regulatory assets, deferred $ (2,873) 11,092 399 $ 8,618 $ (1,107) 14,811 628 $ 14,332 $ (188) 234 228 11-379 SoCo FOIA Response 001429 NOTES (nnlinutdl i\lissis~ippi Powtr Company 20 I 0 Annual Rtport The changes in the balance of regulalory assets related lo lhe olher poslrelirement benefit plans for lhe plan years ended December 31, 20 I0 and 2009 are presented in the following table: Regulatory Assets (illliWII.fcllltf!) $ 20,491 (2,648) (2,592) Balance at December 31, 2008 Net gain Change in prior service cosls/transilion obligation Reclassification adjustments: Amortizalion of transition obligation Amortization of prior service costs Amortizalion of net gain Total reclassification adjustmenls Total change Balance at December 31,2009 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustmenls Total change Balance at December 31,2010 (307) (51) (561) (919) (6,159) $ 14,332 (3,316) (1,824) (228) 57 (403) (574) (5,714) $ 8,618 Components oflhe other postretirement benefil plans' net periodic cost were as follows: 2010 2009 2008 (ill tlwuswuls) $ 1,305 4,763 (1,826) 574 $4,816 Service cost Interest cost Expected return on plan assets Net amortization Net eostretircmenl cost $ 1,328 5,535 (1,783) 919 $5,999 $ 1,396 5,199 ( 1,805) 1.066 $5,856 The Medicare Prescription Drug, Improvement, and Modernization Act of2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced lhe Company's expenses for the years ended December 31, 2010,2009, and 2008 by approximately $1.6 million, $1.7 million, and $1.8 million, respectively, and is expected to have a similar impact on future expenses. Future benefit payments, including prescription drug benefits, renee! expected future service and are eslimated based on assumplions used lo measure the APBO for lhe other postretiremenl benefit plans. Eslimaled benefit paymenls are reduced by drug subsidy receipts expected as a result of lhe Medicare Act as follows: Benefit Payments Subsidy Receipts Total (ill tllSippi Powtr Company 2010 Annual Rtporl were used lo finance the acquisition and construction of buildings and immovable equipment in connection with the Company's construction of the Kemper IGCC. Securities Due Wilhin One Yenr At December 31,2010 and 2009, Ihe Company had scheduled maturities of capital leases due within one year of$1.4 million and $1.3 million, respectively. At December 31, 2010, the Company had planned the redemption of the second series revenue bonds issued in December 20 I0 in the amount of $50.0 million for February 20 II. In addition, a long term bank loan of $80 million matures in March 20 I I and a $125.0 million term loan matures in September 20 II. Maturities through 2013 applicable to total long-term debt are as follows: $256.4 million in 20 II; $0.6 million in 20 12; and $50.0 million in 2013. There are no scheduled maturities in 2014 and 2015. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required lo make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount oftax-exempt pollution control revenue bonds outstanding at December 31, 20 I 0 and 2009 was $82.7 million. In September 2008, the Company was required to purchase a total of approximately $7.9 million of variable rate pollution control revenue bonds that were lendered by investors. In December 2008, the bonds were successfully remarkctcd. On the statement of cash now for 2008, the $7.9 million is presented as proceeds and redemptions. Outstanding Classes or Cnpilnl Stock The Company currently has preferred stock (including depositary shares which represent one-fourth of a share of preferred stock) and common stock authorized and outstanding. The preferred stock of the Company contains a feature that allows the holders to elect a majority of the Company's board of directors if dividends arc not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, this preferred stock is presented as "Cumulative Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The Company's preferred stock and depositary preferred stock, without preference between classes, rank senior to the Company's common stock with respect to payment of dividends and voluntary or involuntary dissolution. Certain series of the preferred stock and depositary preferred stock are subject to redemption at the option of the Company on or after a specified date (typically live or I 0 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the stock. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Bnnk Credil Arrangements At the beginning of20ll, the Company had total unused committed credit agreements with banks of$161 million, all ofwhich expire in 20 II. Approximately $41 million of the facilities contain two-year tenn loan options and $65 million contain one-year term loan options. The Company expects to renew its credit facilities, as needed, prior to expiration. In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the bunks. Commitment fees average less than 3/8 of 1% for the Company. Compensating balances nrc not legally restricted from withdrawal. The credit arrangements contain covenants that limit the ratio of indebtedness to capitalization (each as defined in the arrangements) to 65%. For purposes of these definitions, indebtedness excludes long-term debt payable to affiliated trusts and, in certain cases, other hybrid securities. In addition, the credit arrangements contain cross default provisions that would trigger nn event of default if the Company defaulted on other indebtedness above n specified threshold. At December 31, 20 I 0, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowing. 11-398 SoCo FOIA Response 001448 NOTES (tontinurd) Mississippi l'owrr Company 20t0 Annualllrporl This $161 mill ion in unused credit arrangements provides required liquidity support to the Company's borrowings through a commercial paper program. At December 31, 20 I 0 and 2009, lhe Company had no commercial paper outstanding. The credit arrangements also provide support to the Company's variable rate tax-exempt bonds totaling $90.1 million. Subsequent to December 31, 2010, $50.0 million of revenue bonds were redeemed on February 8, 20 II , reducing liquidity support to $40.1 million. During 20 I 0, the maximum amount outstanding for commercial paper was $63.0 million and the average amount outstanding was $12.0 million. During 2009, the maximum amount outstanding for commercial paper was $66.7 million and the average amount outstanding was $15.9 million. The weighted average annual interest rate on commercial paper was 0.3% for 20 I 0 and 0.3% for 2009. 7. COMMITMENTS Construction Program The construction program of the Company is currently estimaled to include a base level investment of $818 million in 20 II, $1.0 billion in2012, and $878 million in 2013. Included in these estimated amounts are expenditures related to the Kemper IGCC of$665 million, $813 million, and $616 million in 2011, 2012, and 2013, respectively, which are net ofSMEPA 's 17.5% expected ownership share of the Kemper IGCC of approximately $354 million and $91 million in 2012 and 2013, respectively. Also included in these estimated amounts arc environmental expenditures to comply with existing statutes and regulations of$45 million, $94 million, and $127 million for 20 II, 2012, and 2013, respectively. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital e.xpenditures will be fully recovered. At December 31, 20 I0, significant purchase commitments were outstanding in connection with the ongoing construction program. Capital improvements to generating, transmission, and distribution facilities, including those to meet environmental standards, will continue. Sec Note 3 under "Integrated Coal Gasification Combined Cycle" for additional infonnalion. Long-Term Service Agreements The Company has entered into a long-tcnn service agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the lensed combined cycle units at Plant Daniel. The LTSA provides that GE will cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in the LTSA. In general, the LTSA is in effect through two major inspection cycles of the units. Scheduled payments to GE under the LTSA, which arc subject to price escalation, are made monthly based on estimated operating hours of the units and are recognized as expense based on actual hours of operation. The Company has recognized $12.6 million, $13.3 million, and $9.4 million for 20 I0, 2009, and 2008, respectively, which is included in other operations and maintenance expense in the statements of income. Remaining payments to GE under the LTSA are currently estimated to total $106.7 million over the next nine years. However, the LTSA contains various cancellation provisions at the option of the Company. The Company also has entered into a LTSA with Alstom Power, Inc. for the purpose of securing maintenance support for its Chevron Unit 5 combustion turbine plant. In summary, the LTSA stipulates that Alstom Power, Inc. will perfonn a ll planned maintenance on the covered equipment, which includes the cost ofalllnbor and materials. Alstom Power, Inc is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the LTSA. In general, this LTSA is in effect through two major inspection cycles. Scheduled payments to Alstom Power, Inc., which are subject to price escalation, are made at various intervals based on actual operating hours of the unit. Payments to Alstom Power, Inc. under the LTSA are currently estimated to total $17.9 million over the remaining term of the LTSA, which is approximately seven years. However, the LTSA contains various cancellation provisions at the option of the Company. Payments made to Alstom Power, Inc. under the LTSA prior to the performance of any planned maintenance are recorded ns a prepayment in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed. After the LTSA expires, the Company expects to replace it with a new contract with similar tenns. 11·399 SoCo FOIA Response 001449 NOTES j'onlinurd) J\lississippll'owrr Company 21lt0 Annual Rrport Fuel Commitments To supply a portion of the fuel requirements of the generating plants, the Company has entered into various long-tem1 commitments for the procurement of fossil fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emissions allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31,2010. Total estimated minimum long-term commitments at December 31,2010 were as follows: Commitments Natural Gas Coal (ill tlmusuml.<) $180,653 138,530 108,465 82,367 94,645 162,723 $767.383 2011 2012 2013 2014 2015 2016 and thereafter Total $324,360 122,400 23,005 8,440 960 36,480 $515,645 Coal commitments include a minimum annual management fcc of $38 .I million beginning in 2014 from the executed 40-year management contract with Liberty Fuels, LLC related to the Kemper IGCC. Additional commitments for fuel will be required to supply the Company's future needs. SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally Iiable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Lenses Pla11t Da11ie/ Combi11ed Cycle Ge11eruti11g U11its In 200 I, the Company began the initial I 0-year term of the lease agreement for a I,064-MW natural gas combined cycle generating facility built at Plant Daniel (Facility). The lease arrangement provided a lower cost altemntive to its cost bnsed rate regulated customers than a traditional rntc base asset. Sec Note 3 under "Retnil Regulatory Matters- Performance Evaluation Plan" for a description of the Company's formulary rate plan. In 2003, the Facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with the Company. Simultaneously, Juniper entered into a restructured lease agreement with the Company. Juniper has also entered into leases with other parties unrelated to the Company. The assets leased by the Company comprise less than 50% of Juniper' s assets. The Company is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease agreement is treated as an operating lease for accounting purposes as well as for both retail and wholesale rate recovery purposes. For income tax purposes, the Company retains ta.x ownership. The initial lease term ends in 20 II and the lease includes a purchase and renewal option based on the cost of the Facility at the inception of the lease, which was $370 million. The Company is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. In April2010, the Company was required to notify the lessor, Juniper, if it intended to terminate the lease ntthe end of the initial term expiring in October 2011. The Company chose not to give notice to terminate the lease. The Company has the option to purchase the Plant Daniel combined cycle generating units for approximately $354 million or renew the lease for approximately $31 million annually for I 0 years. The Company will have to provide notice of its intent to either renew the lease or purchase the facili ty by July 20 II . If the lease is renewed, the agreement calls for the Company to amortize nn additional I 7% of the initial completion cost over the renewal period. Upon termination of the 11-400 SoCo FOIA Response 001450 NOTES lconlinutdl Mississippll'own Com puny 20t0 Annuatt{tporl lease, at the Company's option, it may either exercise its purchase option or the Facility can be sold to a third party. If the Company does not exercise either its purchase option or its renewal option, the Company could lose its rights to some or all of the I ,064 MWs of capacity at that time. The ultimate outcome of this matter cannot be determined at this time. The lease provides for a residual value guarantee, approximately 73% of the acquisition cost, by the Company that is due upon termination of the lease in the event that the Company does not renew the lease or purchase the Facility and that the fair market value is less than the unamortized cost of the Facility. A liability of approximately $2 million, $3 million, and $5 million for the fair market value of this residual value guarantee is included in the balance sheets at December 31,2010,2009, and 2008, respectively. Lease expenses were $26 million, $26 million, and $26 million in 2010,2009, and 2008, respectively. The Company estimates that its annual amount of future minimum operating lease payments under this arrangement, exclusive of any payment related to the residual value guarantee or purchase or renewal options, as of December 31 , 20 I0, nrc as follows: Minimum Lense Pnyments {itrliWIIStJIICfS) 2011 20 12 and thereafter $28,291 Total commitments $28.291 Otlrer Operuti11g Lea.fe.f The Company and Gulf Power have jointly entered into operating lease agreements for the usc of 745 aluminum railcars. The Company has the option to purchase the rai Icars at the greater of lease tem1ination value or fair market value, or to renew the leases at the end of the lease tcnn. The Company also has multiple operating lease agreements for the use of additional rai Icars that do not contain a purchase option. All of these leases are for the transport of coal to Plant Daniel. The Company's share (50%) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $3.5 million in 2010,$4.0 million in 2009, and $4.0 million in 2008. The Company' s annual railcar lease payments for 20IIthrough 2015 will average approximately $1.1 million and afier 2015, lease payments total in aggregate approximately $1.0 million. In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson and operating leases for barges and tow/shill boats for the transport of coal at Plant Watson. The Company's share (50% at Plant Daniel and 100% at Plant Watson) of the leases for fuel handling was charged to fuel handling expense in the amount of$0.7 million in 2010 and $0.6 million in 2009. The Company's annual lease payments for 20 II through 2014 will average approximately $0.2 million for fuel handling equipment. The Company charged to fuel stock and recovered through fuel cost recovery the barge transportation leases in the amount of $8.4 million in 20 I 0 and $8.4 million in 2009 related to barges and tow/shift boats. The Company's annual lease payments for 2011 through 2014 with respect to these barge transportation lenses will average approximately $7.9 million. 8. STOCK COMPENSATION Stock Option Plnn Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives. As of December 31, 20 I0, there were 281 current and former employees of the Company participating in the stock option plan and there were I0 million shares of Southern Company common stock remaining available for awards under this plan and the Performance Share Plan discussed below. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period or three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no Inter than 10 years alter the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting. The estimated fair values of stock options granted in 2010,2009, and 2008 were derived using the Black-Scholes stock o ption pricing model. Expected volatility was based on historical volatility of Southern Company's stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected tenn that represents the period of time that options granted to 11+401 SoCo FOIA Response 001451 NOTES (conlinurd) Missinippi l'owrrCompany 2010 Annualltrporl employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of slock options granted: Yen r Ended December 31 Expected volatility Expected tenn (ill years) Interest rate Dividend yield Weighted average grant-date fair value 2010 17.4°/o 5.0 2.4% 5.6"/o $2.23 2009 15.6% 5.0 1.9% 5.4% $1.80 2008 13.1% 5.0 2.8% 4.5% $2.37 The Company's activity in the stock option plan for 2010 is summarized below: Outstanding at December 3 I, 2009 Granted Exercised Cancelled Outstnnding nt December 31,2010 E:u:rcisnble at December 31,2010 Shnres Subject Weighted Avernge Exercise Price to Option 1,856,656 $31.83 361,352 31.19 (371,799) 28.86 (2,839) 32.38 1,843,370 $32.30 1,161,617 $32.60 The number of stock options vested, and expected to vest in the future, as of December 31, 2010 was not significantly different from the number of stock options outstanding at December 3 I, 20 I 0 as stated above. As of December 3 I. 20 I 0, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $10.9 million and $6.5 million, respectively. As of December 31, 20 I0, there was $0.2 million of total unrecognized compensation cost relnted to stock option nwards not yet vested. That cost is expected to be recognized over n weighted-average period of approximately 10 months. For the years ended December 31, 20 I 0, 2009, and 2008, total compensation cost for stock option awards recognized in income was $0.8 million, $0.9 million, and $0.7 million, respectively, with the related tax benefit also recognized in income of$0.3 million, $0.3 million, and $0.3 million, respeclively. The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. The total intrinsic value of options exercised during the years ended December 3 I, 20 I 0, 2009, and 2008 was $2.7 million, $0.4 million, and $3.7 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1.0 million, $0.2 million, and $1.4 million for the years ended December 3 I, 2010, 2009, and 2008, respectively. Perrormnnce Share Plan In 20 I0, Southern Company implemented the pcrfonnance share program under its omnibus incentive compensation plan, which provides performance share award units to a large segment of employees ranging from line management to executives. The perfonnance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that relire prior to the end of the three-year period receive a pro rain number of shares, issued at the end of the performance period, based on aclual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year perronnance period which measures Soulhern Company's relative perrormance against a group of industry peers. The performance shares are delivered in common stock following the end of the SoCo FOIA Response 001452 NOTES (co11tlnu~IIJ Mksissippi J>cnnr Company 2010 Ann11al Rtporl perfonnance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target perfonnance share amount. The fair value of perfonnance share awards is detennined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year perfonnance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. E:usands): Residential Commercial Industrial Other Total retail Wholesale- non-affiliates Wholesale- affiliates Total Average Revenue Per Kilowatt-Hour (crnts): Residential Commercial Industrial Total retail Wholesale Total sales Residential Average Annual Kilowatt-Hour Usc Per Customer Residential Average Annual Revenue Per Customer Plant Nameplate Capacity Ratings (year-eml) lrne~:untts) Maximum Peak-Hour Demand lrnc~:awatts): Winter Summer Annual Load Factor lpmcntJ Plant Availabili!! Fossil-Steam lementJ Source of Energy Supply lpcrcent): Coal Oil and gas Purchased power From non-affiliates From affiliates Total 2010 2009 2008 2007 2006 $256,994 266,406 267,588 6,924 797,912 287,917 41,614 1,127,443 15,625 $1l143l068 $245,357 269,423 269,128 7,041 790,949 299,268 44,546 1,134,763 14,658 $1.149.421 $248,693 271,452 258,328 6,961 785,434 353,793 100,928 1,240,155 16,387 $1.256.542 $230,819 247,539 242,436 6,420 727,214 323,120 46,169 1,096,503 17,241 $1.113.744 $214,472 215,451 211 ,451 5,812 647,186 268,850 76,439 992,475 16,762 $1.009.237 2,296,157 2,921,942 4,466,560 38,570 9,723,229 4,284,289 774,375 1417811893 2,091,825 2,851,248 4,329,924 38,855 9,311,852 4,651 ,606 839,372 14.802.830 2,121,389 2,856,744 4, 187,101 38,886 9,204,120 5,016,655 I ,487,083 15.707.858 2,134,883 2,876,247 4,317,656 38,764 9,367,550 5, 185,772 1,026.546 15.579.868 2,118,106 2,675,945 4, 142,947 36,959 8,973,957 4,624,092 1,679,831 15.277.880 11.19 9.12 5.99 8.21 6.51 7.63 I 1.73 9.45 6.22 8.49 6.26 7.67 I 1.72 9.50 6.17 8.53 6.99 7.90 10.81 8.61 5.61 7.76 5.94 7.04 10.13 8.05 5.10 7.21 5.48 6.50 15,130 13,762 13,992 14,294 14,480 $1,693 $1,614 $1 ,640 $1 ,545 $1 ,466 3,156 3,156 3,156 3,156 3,156 2,792 2,638 57.9 93.8 2,392 2,522 60.7 94.1 2,385 2,458 6 1.5 91.6 2,294 2,512 60.9 92.2 2,204 2,390 61.3 81.1 43.0 41.9 40.0 43.6 58.7 28.6 60.0 27.1 63.1 26. 1 1.3 13.8 100.0 3.3 13. I 100.0 4.4 8.3 100.0 3.0 9.9 100.0 3.5 7.3 100.0 11-410 SoCo FOIA Response 001460 SOUTHERN POWER COMPANY FMANCLAL SECTION SoCo FOIA Response 001461 MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Suulhrrn l'owrr Comp1ny and Subsidiary Cumpaniu 2010 Annuli Rrporl The management of Southern Power Company (the "Company") is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of2002 and as defined in Exchange Act Rule 13n15(1). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system arc mel. Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in llltemal Control- llltcgratcd Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 20 I 0. Oscar C. Harper, IV President and Chief Executive Omccr Michael W. Southern Senior Vice President and Chief Financial Omccr February 25, 201 I 11-412 SoCo FOIA Response 001462 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Southern Power Company We have audited the accompanying consolidated balance sheets of Southern Power Company and Subsidiary Companies (the "Company") (a wholly owned subsidiary of Southern Company) as of December 31, 20 I 0 and 2009, and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 20 I0. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements (pages 11-434 to 11-456) present fairly, in all material respects, the financial position of Southern Power Company and Subsidiary Companies at December 31, 20 I 0 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31. 2010, in conformity with accounting principles generally accepted in the United States of America. Atlanta, Georgia February 25, 20 II 11-413 SoCo FOIA Response 001463 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Southern l'owtr Company and Subsidiary Companies 2010 Annual Rtporl OVERVIEW Business Activities Southern Power Company and its wholly-owned subsidiaries (the Company) construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the wholesale market. The Company continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives. In general, the Company has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities. The Company is continuing construction of an electric generating plant in Cleveland County, North Carolina. This plant will consist of four combustion turbine natural gas generating units with a total expected generating capacity of720 megawatts (MW). The units are expected to begin commercial operation in 2012. The Company has entered into long-term PPAs for 540 MWs of the generating capacity of the plant. The Company is also continuing construction of the Nacogdoches biomass generating plant near Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in late 2009 and the phmt is expected to begin commercial operation in 2012. The entire output of the plant will be sold under a long-tenn PPA. As of December 31, 2010, the Company had units totaling 7,880 MWs nameplate capacity in commercial operation. The weighted average duration of the Company's wholesale contracts exceeds 11.5 years, which reduces remarketing risk. The Company's future earnings wi II depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets. Sec FUTURE EARNINGS POTENTIAL herein for additional infonnation. Key Performance Indicators To evaluate operating results and to ensure the Company's ability to meet its contractual commitments to customers, the Company focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (EFOR) and net income. Peak season EFOR defines the hours during peak demand times when the Company's generating units arc not available due to forced outages (the lower the better). Net income is the primary measure of the Company's financial perfonnancc. The Company's actual performance in 20 I 0 did not meet targets in these key perfomtance areas. The Company did not meet peak season EFOR targets due to unplanned outages at Plant Stanton and Plant Harris. See RESULTS OF OPERATIONS herein for additional information on the Company's net income for 2010. Earnings The Company's 2010 net income was $130.0 million, a $25.8 million decrease over 2009. This decrease was primarily due to higher operations and maintenance expenses, higher depreciation and amortization, and profit recognized in 2009 on a construction contract with the Orlando Utilities Commission (OUC) whereby the Company provided engineering, procurement, and construction services to build a combined cycle unit for the OUC. These decreases were partially offset by lower interest e.xpense, net of mnounts capitalized. The Company's 2009 net income was $155.9 million, an $11.5 million increase over 2008. This increase was primarily due to increased margins associated with the operation ofPiunt Franklin Unit3 for nil of2009, increased generation from the Company's combined cycle units due to lower natural gas prices, and profit recognized under a construction contract with the OUC. These favorable impacts were partially offset by a loss recognized on the transfer of DeSoto County Generating Company, LLC (DeSoto) to Broadway Gen Funding, LLC (Broadway) in December 2009, gains recognized in income in 2008 related to the sale of an undeveloped tract of land in Orange County, Florida to the OUC, and the receipt of a fee for participating in an asset auction as an unsuccessful bidder. Additionally, depreciation increased due to the completion of Plant Franklin Unit3 in June 2008 and an increase in depreciation rates. Interest expense increased due to a reduction of capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008. 11-4 14 SoCo FOIA Response 001464 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS So•lhtrn l'owtr Com11•ny and Sulllihliary Cumpanits 2010 AIIIIMall(t~~Url The Company's 2008 net income was $144.4 million, a $12.7 million increase over 2007. This increase was primarily due to increased capacity sales to requirements service customers, market sales of uncontracted generating capacity, a gain on the sale of an undeveloped tract of land in 2008, a loss on the gasifier portion of the integrated coal gasification combined cycle (IGCC) project in 2007, and the receipt of a fcc for participating in an asset auction in 2008 as an unsuccessful bidder. These increases were partially offset by transmission service expenses and tariff penalties incurred in 2008, timing of plant maintenance activities, increased general and administrative expenses associated with the implementation of the Federal Energy Regulatory Commission (FERC) separation order, and increased depreciation associated with Plant Oleander Unit 5 and Plant Franklin Unit 3 being placed into commercial operation in December 2007 and June 2008, respectively. RESULTS OF OPERATIONS A condensed statement of income follows: Increase (Decrease) from Prior Yenr 2009 2010 Amount 2010 2008 (inmillitm.t} Operating revenues Fuel Purchased power Other operations and maintenance Loss (gain) on sale of property Loss on IGCC project Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Interest expense Profit recognized on construction contract Other income (expense), net of amounts capitalized Income taxes Net income $ 1,129.1 391.5 170.1 147.4 0.5 s 119.0 17.8 846.3 282.8 76.1 0.5 (0.4) 76.8 130.0 $ s 182.5 159.1 26.1 10.8 (4.5) $ (366.9) 20.9 0.9 213.3 {30.8) (8.9) (12.8) 9.6 (0.8) (367.6) 0.7 1.8 13.3 (8.0) (7.3) $ 11.5 (8.9) (25.8) ( 192.3) ( 184.0) (II. I) 11.0 $ 341.5 186.1 128.1 12.7 (6.0) (17.6) 14.5 2.0 319.8 21.7 4.0 $ 4.3 9.3 12.7 Operuti11g Re••em1es Operating revenues in 2010 were $1.1 billion, a $182.5 million ( 19.3%) increase from 2009. This increase was primarily due to a $377.2 million increase in energy and capacity revenues under new and existing PPAs. $80.8 million associated with higher revenues from energy sales that were not covered by PPAs due to more favorable weather in 20 I0 compared to 2009, and a $46.8 million increase in revenues from power sales under the Intercompany Interchange Contract (II C). These increases were partially offset by a $321.4 mill ion decrease in energy and capacity revenues associated with the expiration of PPAs in December 2009 and May 20 I 0. Operating revenues in 2009 were $946.7 million, a $366.9 million (27.9%) decrease from 2008. This decrease was primarily due to lower natural gas prices that reduced energy revenues. This decrease was partially offset by increased capacity and energy revenues from the operation of Plant Franklin Unit3 and a PPA relating to four units at Plant Dahlberg that began in June 2009. Operating revenues in 2008 were $1 .3 I billion, a $341 .5 million (35.1%) increase from 2007. This increase was primarily due to increased short-term energy revenues from uncontracted generating units, increased energy revenues due to higher natural gas prices, and increased revenues from a full year of operations at Plant Oleander Unit 5. These increases were partially offset by decreased demand under existing PPAs due to less favorable weather in 2008 compared to 2007. The increase in fuel revenues was accompanied by an increase in related fuel costs and did not have a significant impact on net income. 11-415 SoCo FOIA Response 001465 MANAGEMENT'S DISCUSSION AND ANALYSIS (rontinurtll Soutllern 1'0\nr Company anti SuhsiLiiary Compnnir• 21110 ,\nnuallhporl Capacity revenues are an integral component of the Company's PPAs with both affiliate and non-afliliate customers and generally represent the greatest contribution to net income. Energy under the PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges. Details of these PPA capacity and energy revenues are as follows: 2010 2009 2008 (ill millions) Capacity revenuesAffiliates Non-am liates Total Energy revenuesAffiliates Non-affiliates Total Total PPA revenues $ $ 190.6 257.4 448.0 46.1 399.9 446.0 894.0 $ $ 287.6 185.7 473.3 192.8 173.8 366.6 839.9 $ $ 279.2 165.2 444.4 263.6 249.0 512.6 957.0 Wholesale revenues that were not covered by PPAs totaled $228.2 million in 20 I0, which included $134.0 million of revenues from affiliated companies. Wholesale revenues that were not covered by PPAs totaled $98.9 million in 2009, which included $64.0 million of revenues from affiliated companies. Wholesale revenues that were not covered by PPAs totaled $349.2 million in 2008, which included $95.5 million of revenues from affiliated companies. These wholesale sales were made in accordance with the IIC, as approved by the FERC. These non-PPA wholesale revenues will vary from year to year depending on demand and the availability and cost of generating resources at each company that participates in the centralized operation and dispatch of the Southern Company system fleet of generating plants (power pool). Fuel am/ PurciiUsetl Power E.~:pe1ues Fuel costs constitute the single largest expense for the Company. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company's fuel and purchased power expenditures arc as follows: 2010 2009 2008 (ill millimu) Fuel Purchased power-non-affiliates Purchased ~ower-afliliatcs Total fuel and ~urchased ~ower ex~enses $ $ 391.5 72.7 97.4 561.6 $ $ 232.5 79.3 64.6 376.4 $ $ 424.8 132.2 195.8 752.8 In 2010, total fuel and purchased power expenses increased by $185.2 million (49.2%) compared to 2009. Total fuel and purchased power expenses increased $77.3 million primarily due to an 8.7% increase in the average cost of natural gas and a 36.4% increase in the cost of purchased power and $107.9 million due to an increase in kilowatt-hours (KWH) generated and purchased. In 2009, total fuel and purchased power expenses decreased by $376.4 million (50.0%) compared to 2008. This decrease was driven by a 56.0% decrease in the average cost of natural gas and a 41.3% decrease in the average cost of purchased power. Additionally, purchased power volume decreased 25.2% primarily due to increased generation at the Company's combined cycle units as a result of lower natural gas prices. These decreases were partially offset by a 31.2% increase in generation at the Company' s combined cycle units as a result of lower natural gas prices. In 2008, total fuel and purchased power expenses increased by $314.2 million (71.6%) compared to 2007. This increase was driven by a 58.9% increase in generation due to operations at Plant Franklin Unit 3, an 11 .9% increase in the average cost of natural gas, and a 107.9% increase in the average cost of purchased power. 11--416 SoCo FOIA Response 001466 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) So•t~ern l'ower Company and S•bsidiary Comp..iu 2010 ,h•llal Report In 2010, fuel expense increased by $159.1 million (68.4%) compared to 2009. Fuel expense increased $31.7 million primarily due to an 8.7% increase in the average cost of natural gas and $127.4 million due to an increase in KWHs generated. In 2009, fuel expense decreased by $192.3 million (45.3%) compared to 2008. This decrease was driven by a 56.0% decrease in the average cost of natural gas. This decrease was partially offset by a 3 1.2% increase in generation at the Company's combined cycle units as a result of lower natural gas prices. In 2008, fuel expense increased by $186.1 million (78.0%) compared to 2007. This increase was driven by a 58.9% increase in generation primarily due to operations at Plant Franklin Unit 3 and an 11.9% increase in the average cost of natural gas. In 20 I0, purchased power expense increased $26.1 million ( 18.1%) compared to 2009. Purchased power expense increased $45.6 million due to an increase in the average cost of purchased power, partially offset by a $19.5 million decrease due to fewer KWHs purchased. In 2009, purchased power expense decreased $184.0 million (56.1 %) compared to 2008, primarily due to a 41.3% decrease in the average cost of purchased power. Additionally, purchased power volume in 2009 decreased 25.2% due to increased generation at the Company's combined cycle units as a result of lower natural gas prices. Purchased power expense increased $128.1 million (64.1%) in 2008 when compared to 2007, primarily due to a 107.9% increase in the average cost of purchased power. The Company's PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is accompanied by an increase or decrease in related fuel revenues and docs not have a significant impact on net income. The Company is responsible for the cost of fuel for units that are not covered under PPAs. Power from these units is sold into the market or sold to affiliates under the II C. Purchased power expenses will vary depending on demand and the availability and cost of generating resources available throughout the Southern Company system and other contract resources. Load requirements nrc submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by the Company, affiliate-owned generation, or external purchases. Oilier Operutimr.~ a11d MuilltetJUIICe E.v:pe11.~e.~ In 20 I 0, other operations and maintenance expenses increased$ I 0.8 million (7.9%) compared to 2009. This increase was primarily due to $4. I million of additional expense associated with the passage ofhealthcare legislation in March 2010 and $4.2 million related to generating plant outages and maintenance, mainly at Plants Stanton, Barris, and Franklin. See FUTURE EARNINGS POTENTIAL- "Legislation- 1-lealthcare Reform" herein for additional information regarding healthcare legislation. In 2009, other operations and maintenance expenses decreased $11. I million (7.5%) compared to 2008. This decrease was due primarily to transmission tariff penalties recognized in 2008, reduced transmission expenses due to a decrease in power sales into the market, and the timing of plant outages. In 2008, other operations and maintenance expenses increased$ I 2.7 million (9.4%) compared to 2007. This increase was due primarily to the timing of plant maintenance activities, transmission tariff penalties, and additional administrative and general expenses as a result of costs incurred to implement the FERC compliance plan. Sec Note 3 to the financial statements under "FERC Matters" for additional information. L11ss (Guill) (Ill Sale !1/ Pr(lperiJ' In December 2009, the Company recorded n loss of$5.0 million on the divestiture of DeSoto. In January 2008, the Company recorded a gain of$6.0 million on the sale of an undeveloped tract oflnnd. Loss mr IGCC Pmject In November 2007, the Company and the OUC mutually agreed to tenninnte the construction of the gasifier portion of the IGCC project, originally planned as a joint venture; however, the Company continued construction of the gas-fired combined cycle generating facility, owned solely by the OUC. The Company recorded a loss in the fourth quarter 2007 of$17.6 million related to the cancellation of the gasifier portion of the IGCC project. This loss consists of the write-off of construction costs of $14.0 million and an accrual for termination payments of$3.6 million. All termination payments were completed in 2008. 11·417 SoCo FOIA Response 001467 MANAGEMENT'S DISCUSSION AND ANALYSIS lconlinutdl Soulhtrn l'owrr Compan)' and Subsidiary Compnnit• 2010 ,\nnual Rtporl Depreciation uml Amrmizatimr In 2010, depreciation and amortization increased $20.9 million (21.3%) compared Ia 2009. This increase was primarily related to a $6.7 million increase associated with the acquisition of \Vest Georgia Generating Company LLC (West Georgia) and the divestiture of DeSoto in December 2009 which resulted in an increase in property, plant, and equipment of$120.2 million. The increase was also due to $7.5 million of equipment retirements and a $6.5 million increase in depreciation rates related primarily to increased starts and run-hours at the Company's generating plants. In 2009, depreciation and amortization increased $9.6 million ( 10.9%) compared to 2008. This increase was primarily due to the completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented during 2009. In 2008, depreciation and amortization increased $14.5 million ( 19.7%) due to the completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented in January 2008. Sec ACCOUNTING POLICIES - "Depreciation" herein for additional information regarding the Company's ongoing review of depreciation estimates. Sec also Note I to the financial statements under "Depreciation" for additional information. lntere.~t Expeme, Net rifAmmmts Cupitulizctl In 20 I0, interest expense, net of amounts capitalized decreased $8.9 mill ion (I 0.4%) compared to 2009. This decrease was primarily due to $10.5 mill ion of additional capitalized interest associated with the construction of the Cleveland County combustion turbine generating plant and the Nacogdoches biomass plant, partially offset by $0.7 million associated with an increase in interest expense on commercial paper and $0.7 million associated with interest rate swaps on senior notes. In 2009, interest expense, net of amounts capitalized increased $1.8 million (2.1 %) compared to 2008. This increase was primarily due to a $5.5 million decrease in capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008, partially offset by a $1.7 million decrease in short-term borrowing levels during 2009 ami a decrease in amortization of interest rate derivatives of $2.1 million. In 2008, interest expense, net of amounts capitalized increased $4.0 million (5.1 %) compared to 2007. lllis increase was primarily the result of a decrease in capitalized interest as a result of the completion of Phmt Oleander Unit 5 in December 2007 and Plant Franklin Unit 3 in June 2008, partially offset by a decrease in short-term borrowing levels in 2008. Profit Recognized mr Cmrstr11ctimr Cmrtruct Pro lit recognized on the construction contract with the OUC whereby the Company has provided engineering, procurement, and construction services to build a combined cycle unit for the OUC was $0.5 million in 20 I 0 and $13.3 million in 2009. No profit or loss on this contract was recognized in 2008. Construction activities commenced in 2006 and were substantially completed in 2009. Otlrer flrcmne (E:cpense), Net The change in other income (expense), net for 2010 as compared to 2009 was not material. Other income (expense), net was an expense of $0.4 million in 2009 versus income of $7.6 million in 2008. This change was primarily due to a $6.4 million fee received in 2008 for participating in an asset auction. The Company was not the successful bidder in the asset auction. Other income (expense), net increased $4.3 million ( 131.1%) in 2008. This increase was primarily due to a $6.4 million fee received in 2008 for participating in an asset auction. The Company was not the successful bidder in the asset auction. 11-418 SoCo FOIA Response 001468 MANAGEMENT'S DISCUSSION AND ANALYSIS (coali ..rdJ Souchrrn ro.,·rr Comp•ny ud Subsidiny Comp•nin 2010 AnnuAl Rrporl IIIC(Itllt! TU.'\CS In 2010, income taxes decreased $8.9 million ( 10.4%) compared to 2009. This decrease was primarily due to $12.0 million associated with lower pre-ta.x earnings and $3.7 million of tax benefits associated with the construction of the Nacogdoches biomass plant. These decreases were partially offset by a $6.7 million increase in Alabama state taxes. Alabama's state tax liability is reduced by a deduction for federal income taxes paid. Due to increased bonus depreciation and incentives associated with new plant construction, the federal tax liability was significantly reduced, resulting in a higher overall state tax e.xpense. Also contributing to the increase in state taxes was the application of the resulting higher state tax rate to the deferred income tax balance. In 2009, income taxes decreased $7.3 million (7.8%) compared to 2008. This decrease was due to changes in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction, lower state income taxes, and tax benefits received under convertible investment tax credits (ITCs). Higher pre·ta.x earnings partially offset these decreases. Sec Note 5 to the financial statements for additional information. Income taxes increased S9.3 million ( 11.2%) in 2008 primarily due to higher pre·tax earnings ami changes in the Section 199 production activities deduction. Effects or lnRalion The Company is party to long-term contracts renecting market-based rates, including in nation expectations. Any adverse effect of in nation on the Company's results of operations has not been substantial in recent years. FUTURE EARNINGS POTENTIAL General The results of operations for the past three years are not necessarily indicative of future earnings rotential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's competitive wholesale business. The level of future earnings also depends on numerous factors including the Company's ability to achieve sales growth while containing costs, regulatory matters, creditworthiness of customers, total generating capacity available in the Southeast, the successful remarkcting of capacity as current contracts expire, and the Company's ability to execute its acquisition strategy and to construct generating facilities. Other factors that could innuence future earnings include weather, demand, generation patterns, and O)JCrationallimitations. Recessionary conditions have lowered demand and have negatively impacted capacity revenues under the Company's PPAs where the amounts purchased nrc based on demand. The Company is unable to predict whether demand under these PPAs will return to pre-recession levels. The timing and extent of the economic recovery is uncertain and will impact future earnings. Power Sales Agreements The Company's sales are primarily through long-term PPAs. The Company is working to maintain and expand its share of the wholesale market. The Company expects that many areas of the market will need capacity in 2017. The Company's PPAs consist of two types of agreements. The first type, referred to as n unit or block sale, is a customer purchase from a dedicated plant unit where all or a portion of the generation from that unit is reserved for that customer. The Company typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that the Company serve the customer's capacity and energy requirements from a combination of the customer's own generating units and from Company resources not dedicated to serve unil or block sales. The Company has rights to purchase power provided by the requirements customers' resources when economically viable. 11-4 19 SoCo FOIA Response 001469 MANAGEMENT'S DISCUSSION AND ANALYSIS (rontinurdl Southrrn l'owrr Company and Subsidiary Companies 2010 Annunlltrport The Company has entered into the following PPAs over the past three years: Date 2010 City of Seneca Georgia Electric Membership Corporation (EMCsl ''' MWs l'lont Unassigned Unassigned Comract Term June 2010 October 20 10"' 30''' 423 th> 7110-6115 01115-12127''' December 2009 December 2(){)9 October 2009 June 2009 157'"' 151 100 509 West Georgia West Georgia Nacogdoches Oleander 12109-4/29 6/10-5/30 6/12-5/32 1116-5/21 December 2008 November 2008 November 2008 November 2008 August2008 July 2008 Jul~ 2008 180 180 180'" 100 151 360''' 85 Cleveland Cleveland Clewland Purchased '" Rowan l/12-12131 1112-12136 1112-12136 1112-12121 1111 -12114 1110-12134 "' 10113-9/23 1IDl2 Municipol Electric Authority of Georgia (MEAG l'owefl '"' Georgia Energy Cooperative, Inc. (GEC) ••• Austin Energy •·• Seminole Electric Cooperotivc. Inc. (Seminole)'"' ~ North Carolina Municipal Power Agency No. I (NC~II'AI) North Carolina Electric Membership Corpomtion (NCEMC) NCEMC Encrb'YUnitcd Electric Membership Corporation (Energy United) The Encrb'Y Authority, Inc. EMCs''' Florida Municil!all'ower Ai!enc:i IFMI'A)';' (a) (b) (c) (d) (c) (f) (g) (h) (i) Una.~signed Stanton 'l11esc agreements, signed in October and December 2010, ore c.,tcnsions of cunent agreements with II Georgia EMCs. Nine ugrcements were e~tcnded from 2015through 2024, one agreement \\US extended from 2018 through 2027, and one agreement wos extended from 2018 through 2024. Assumed contract through the West Georgia acquisition in 2009. Assumed contract through the Nacogdoches Power LI.C acquisition in 2009. Commercial opcrolion ofl'lant Nacogdoches is expected to begin in June 2012. 111is ogrccmenl is an extension of the current agreement with Seminole for l'lonl Oleander. !'ower purchases under this agreement will increase over the term of the agreement 45 MWs will be sold from 20l2through 2016.90 MWs will be sold from 2017 through 2018, und ISO MWs will be sold from 2019 through 2036. !'ower to serve this agrL"Cment will be purchased under a third pany agreelllent for resole to EnergyUnited. ·nrc purchases w1ll be resold at cost. 11rcse agreements ore extensions of current agreements with I0 Georgia EMCs. E1ght agreements were extended from 2010 through 2031 and two agreements were cxtendL-d from 2013 through 2034. Represents overage annual capacity purchases. This agreement is nn extension of the current agreement with I'M I'A for l'lunt Stnnlon The Company has PPAs with some of Southern Company's traditional operating companies and with other investor owned utilities, independent power producers, municipalities, and electric cooperatives. Although some of the Company's PPAs arc with the traditional operating companies, the Company's generating facilities are not in the traditional operating companies' regulated rate bases, and the Company is not able to seek recovery from the traditional operating companies' ratepayers for construction, repair, environmental, or maintenance costs. The Company expects that the capacity payments in the PPAs will produce sufficient cash nows to cover costs, pay debt service, and provide an equity return. However, the Company's overall profit will depend on numerous factors, including efficient operation of its generating facilities and demand under the Company's PPAs. As a general matter, existing PPAs provide that the purchasers are responsible for either procuring the fuel or reimbursing the Company for the cost of fuel relating to the energy delivered under such PPAs. To the extent a particular generating facility docs not meet the operational requirements contemplated in the PPAs, the Company may be responsible for excess fuel costs. With respect to fuel transportation risk, most of the Company's PPAs provide that the counterparties are responsible for transporting the fuel to the particular generating facility. Fixed and variable operation and maintenance costs will be recovered through capacity charges based on dollars-per-kilowatt year or energy charges based on dollars-per-MW hour. In general, the Company has long-term service contracts with General Electric and Siemens AG to reduce its exposure to certain operation and maintenance costs relating to such vendors' applicable equipment. See Note 7 to the financial statements under "Long·Term Service Agreements" for additional information. 11-.42() SoCo FOIA Response 001470 MANAGEMENT'S DISCUSSION AND ANALYSIS (conlinutdl Soulhtrn l'owtr Company and Subsidiary Companies 2010 Annuallltporl Many of the Company's PPAs have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that Standard & Poor's, a division ofThe McGraw Hill Companies, Inc. (S&P), or Moody's Investors Service (Moody's) downgrades the credit ratings of the counterparty to an unacceptable credit rating or if the counterparty is not rated or fails to maintain a minimum coverage ratio. TI1e PPAs are expected to provide the Company with a stable source of revenue during their respective terms. The Company has entered into long-term power sales agreements for an average of 79% of its available capacity for the next live years and 68% of its available capacity for the next I 0 years. Environmental Matters The Company's operations arc subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, such as requirements related to greenhouse gases or changes to existing statutes or regulations, could affect many areas ofthe Company's operations. While the Company's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be detennined at this time. Because the Company's units nrc newer gas-fired generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal-fired generating facilities or older gas-fired generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the availability of water withdrawal rights, uncertainties regarding aesthetic impacts such as increased light or noise, and concerns about potential adverse health impacts, can, however, increase the cost of siting and operating any type of future electric generating facility. The impact of such statutes and regulations on the Company cannot be detennined at this time. Curba11 DitJxidr! Litigutimt Kil•ulina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. Tile plaintiffs nrc the governing bodies of an lnupiat village in Alaska. The plaintiiTs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and arc therefore jointly and severally liable for the plaintilfs' damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims arc without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants' motions to dismiss the case based on lack o f jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs' failure to establish the standard for determining that the defendants' conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals fo r the Ninth Circuit challenging the district court's order dismissing the case. On January 24, 20ll , the defendants filed a motion with the U.S. Court o f Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in a similar case. The u ltimatc outcome of this matter cannot be determined at this time. 11+42 1 SoCo FOIA Response 001471 MANAGEMENT'S DISCUSSION AND ANALYSIS tcnnlinuttll Soulhtrn l'ol\'tr Compan)' and Subsidiary Companits 2010 Annual Rtpllrl Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the Kivalina case, courts have been debating whether private parties and slates have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed privale party claims againsl certain oil, coal, chemical, and ulility companies alleging damages as a resull of Hurricane Kalrina. The court ruled !hat lhc parties lacked standing to bring the claims and lhe claims were barred by lhe polilical queslion doclrine. In Oclober 2009, the U.S. Court of Appeals for lhe Fifth Circuil reversed the districl court and held lhallhe plainliffs did have standing to assert their nuisance, trespass, and negligence claims and none ofthe claims were barred by the political queslion doclrine. On May 28, 20 I0, however, lhe U.S. Court of Appeals for the fifth Circuil dismissed the plaintiffs' appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January I0, 20 II, the U.S. Supreme Court denied the plainliffs' pelition lo reinstate the appeal. This case is now concluded. Etnoiromllelttal Statute.~ atJd Regulatimu Air Quality Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (N02 ), which established a new one-hour standard, became effective on April 12,2010. Although none of the areas in which the Company operates generating assets arc expected to be designated as nonallainment for the N0 2 slandard, based on currenl ambient air quality monitoring data, the new NOz standard could result in significanl additional compliance and operational costs for units that require new source penniuing. On April 29, 20 I0, the EPA issued a proposed Industrial Boiler (IB) Maximum Achievable Control Technology rule that would establish emissions limits for various hazardous air pollutants lypically emitted from induslrial boilers, including biomass boilers and start-up boilers. The EPA issued the final rules on February 23, 20 II and, at the same time, issued a notice of intent to reconsider the final rules to allow for additional public review and comment. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time. Gltlha/ Climate ls.mes Although the U.S. House of Representatives passed the American Clean Energy and Security Acl of2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas emissions, neilher this legislation nor similar measures passed the U.S. Senate before the end of the 2010 session. Federallegislalive proposals that would impose mandatory requirements relaled to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are expected to continue to be considered in Congress. The financial and operational impacts of climate or energy legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of 1echnologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on natural gas and biomass prices, and cost recovery through PPAs. 11·422 SoCo FOIA Response 001472 MANAGEMENT'S DISCUSSION AND ANALYSIS lA I that could require collateral, but not accelerated payment, in the event of a downgrade of the Company's credit. The Duke Energy PJ>A delines the downgrade to be below BBB- or Baa3. The NCMJ>A I PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade for both J>PAs. Market Price Risk The Company is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, the Company takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions arc monitored using techniques including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis. At December 31, 20 I 0, the Company had no variable long-term debt outstanding. Therefore, there would be no effect on annualized interest expense related to long-term debt ifthe Company sustained a 100 basis point change in interest rates. Since a significant portion of outstanding indebtedness bears interest at fixed rates, the Company is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot be determined at this time. Because energy from the Company's facilities is primarily sold under long-term PJ>As with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. The changes in fair value of energy-related derivative contracts for the years ended December 3 I were as follows: 2010 2009 Changes Changes Fair Value (illmillitmJ) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes~·~ Contracts outstanding at the end of the period, assets (liabilities), net (a) $3.4 (2.0) $ (3.5) 1.5 (1.5) $ (3.5) (4.9) $ (3.5) Current pcnod changes also mclude the changes m fan value of new contracts entered Into during the pcnod, tf any For the year ended December 3 I, 20 I 0, there was no change in the total fair value of the energy-related derivative contracts. For the year ended December 3 I, 2009, there was a $6.9 mill ion decrease in the fair value positions of the energy-re lated derivative contracts, which is due to both volume and price changes in power and natural gas positions. 11-43(} SoCo FOIA Response 001480 MANAGEMENT'S DISCUSSION AND ANALYSIS tronlinutdl Soulhtrn rowtr Comp1ny and Subsidiary Companies 2010 ,\nnual Rtporl The net hedge positions at December 31, 20 I0 and December 31, 2009 and respective period end dates that support these changes were as follows: December 31,2010 December 31. 2009 0.9 2.7 $(2.JJ) $ (0.36) 13.0 8.3 2.0 $0.11 $0.29 $- $ (0.04) Power (net sold) Megawatt hours (MWH) (in millions) Weighted average contract cost per MWH above (below) market prices (in dollars) Natural gas (net purchase) Commodity- million British thermal unit (mmBtu) Location basis- million mmBtu Commodily- weighted average contrncl cost per mmBtu above (below) markel prices (in dollars) Location basis- weighted average contract cost per mmBtu above (below) markel prices (in dollars) At December 3 I, the net fair value of energy-related derivalive contracts by hedge dcsignalion was refleclcd in the financial stalcments as assets (liabilities) as follows: Assel (Liability) Derivatives 2010 2009 (ill millicm.t ) $ (2.5) ( 1.0) $ (3.5) $ (1.0) (2.5) $ (3.5) Cash flow hedges Not designaled Total fair value Gains and losses on energy-relaled derivatives used by lhc Company to hedge anticipaled purchases and sales arc initially deferred in olhcr comprehensive income before being recognized in income in the same period as lhe hedged transaclion. Gains and losses on cncrgy-relaled derivative contracts thai are not designnted or faillo qualify as hedges arc recognized in lhe slalcmcnls of income as incurred. Tolal net unrealized pre-tax gnins (losses) recognized in lhc slalcmcnls of income for the years ended December 31 , 20 I 0, 2009, and 2008 for energy-related derivative contracts that arc not hedges were$( 1.5) million, $(5.2) million, and $0.9 million, respeclivcly. The Company uses ovcr-thc-counlcr contracts that arc nol exchange-traded but are fair valued using prices which arc aclively quolcd, and lhus fall inlo Level 2. Sec Note 8 lo lhc financial slalcmenls for further discussion of fair value mcasurcmcnls. The maturilics of the energy-related derivative conlracts and the level of the fair value hierarchy in which they fall at December 3 I, 20 I 0 were as follows: December 31,2010 Fair Value Mensuremenls Total Fair Value Maturit~ Year I Years 2&3 Years 4&5 (ill mil/icms) $ $ Level I Levc12 Level) Fair value of conlracts outstanding al end of period $ $ (3 .5) (3.6) (0.3) 0.4 $(3.5) $ (3.6) $ (0.3) $ 0.4 The Company is exposed to market price risk in the event of nonperformance by counlerparties lo energy-relaled dcrivalive conlracts. The Company only enters inlo agreements wilh countcrpartics lhat have inveslment grade credit ratings by S&P and Moody's or with counterpartics who have posted collatcrallo cover polcnlial credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counlerparties. See Nole I to the financial slatements under "Finnncial Instruments" and Nole 91o the financial statemenls for additional inrormntion. 11-431 SoCo FOIA Response 001481 MANAGEMENT'S DISCUSSION AND ANALYSIS (concinurdl Soulhrrn rower Company and Subsidiary Cnmpnir~ 2010 Annunllbporl The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 20 I0 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the usc of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations arc finalized. Cnpilnl Requirements nnd Contractual Obligations The capital program of the Company is currently estimated to be $540 mill ion for 20 II, $144 mill ion for 20 12, and $37 million for 2013. These amounts include estimales for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and the Company's ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. The Company is currently constructing a four-unit combustion turbine generating plane in Cleveland County, North Carolina and a biomass generating facility in Sacul, Texas. See FUTURE EARNINGS POTENTIAL- "Construction Projects" herein for additional information. Ocher funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes I, 6, 7, and 9to the financial statements for additional information. Contractual Obligations 2011 20122013 20142015 Aller 2015 Uncertain Timing 1c 1 Total (i11millimu) Long-term debc1• 1 Principal Interest Energy-related derivative obligations1b1 Operating leases Unrecognized tax benefits and interest1c1 Purchase commitments1d1 Capita1 1c1 Natural gas10 Biomass fuel181 . Purchased powerh1 Long-tenn service agreements1' 1 Total (aI $ 74.3 5.8 0.5 539.6 338.2 7.8 48.8 $1,015.0 $ 575.0 $ 525.0 $ 200.0 112.6 76.7 267.7 0.4 1.0 0.9 22.3 181.2 485.9 295.2 229.2 32.0 36.0 110.0 99.6 105.1 241.7 86.6 101.0 878.3 $1,574.3 $1,139.9 $1,949.2 2.3 $1,300.0 531.3 6.2 24.7 2.3 $ 2.3 720.8 I ,348.5 178.0 454.2 I, 11 4.7 $5,680.7 $ All amounLs are reflccled based on final malurily dales. 'lltc Company plans In rclire higher-cost securities and replncc these nbligulinns with lower-cost capital if market conditions penn it. (bl For additional infonnation, sec Noles I aml9 tn the llnanciul statemcnls. (c) The liming related lo lhe realization ofS2J million in unrecognized tux benefits and corresponding interest payments 111 mdiVIdual years beyond 12 months cannot be reasonably and rdiobly estimated due to uncertainties in the timing ofthe cfTective settlement of to~ pos1t1ons Sec Note 5 111 the linunc1nl slnlcmcnlS for oddilional infonnalion. The Company generally docs not enter into non-cancelable commitments for olher operations and maintenance e~penduurcs Tolal other operations and maintenance expenses for the last three years were S 147.4 million, S136.7 million, and$ 14 7.7 million, respectively (d) (el 'lltc Company provides fnrecasled capilal expenditures for a lhrec·ycar period. Amounts represent eslimates for polential plnnl acquisllions and new construction us well us ongoing cupiwl imprnvemenLs. (f) Natural gus purchase commitmcnLs ore based on various indices at the time of delivery. Amounts rcllcctcd have been csttmatcd bused nn the New York Mercantile Exchange future prices at December 31, 20 I 0. (gl Uiomass fuel commitmenLs arc bused on minimum committed tonnage of wood waste purchases for l'lant Nacogdoches l'lant Nacogdoches IS expected to begin commercial operation in 2012. AmnunLs rcllcctcd include price escalation based on inllation indices (h) Purchased power commilments of$71 .5 million in 2012-2013,$74.4 million in 2014-2015, and $241 7 m1lllon after 2015 Will be resold under a tlmd party agreement to EncrgyUnited. The purchases will be resold at cost. (i) Long-term service ogrecmcnLs include price escalation based on inllation indices. H-432 SoCo FOIA Response 001482 MANAGEMENT'S DISCUSSION AND ANALYSIS (rontinurtll Soulhrrn l'owrr Company anti Subsidiary Companirs 2010 Annual Rrporl Cnutionnry Stntcment Regnrding Fonvnrd-Looking Statements The Company's 20 I 0 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning environmental regulations and expenditures, financing aclivilies, impacts of the adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009. impact of recent hcahhcarc legislation. impact of' the Small Business Jobs and Credit Act of20 I0. impact ofthe Tux Relief. Unemployment Insurance Reauthori7.ation. and Job Creation Act uf20 I0. eslimaled sales and purchases under new power sale and purchase agreements, impacts of revisions to depreciation estimates, start and completion of construction projects, lilings with federal regulatory authorities, impacts of adoption of new accounting rules, plans and estimated costs for new generation resources. and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anlicipates," "believes," "eslimaces," "projects," "predicts," "polential," or "continue" or che negntive of these terms or ocher similar terminology. There are various factors thai could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: the impact of recent and future federal and stale regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, irnplementalion of the Energy Policy Act of2005, environmental laws including regulation of water quality and emissions of sulfur, mercury, carbon, soot, particulate muller, hazardous air pollutants, and other substances, financial reform legislation, and changes in tax and olher laws and regulations lo which the Company is subject, as well as changes in application of existing laws and regufalions; current and future liligation, regulatory investigations, proceedings, or inquiries, including FERC matters; the effects, extent, and liming of the entry ofaddilional competition in the markets in which the Company operates; variations in demand for electricity, including those relaling to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and lhe effects of energy conservation measures; available sources and costs of fuels; effects of inflation; advances in technology; state and federal rate regulations; the ability lo control costs and avoid cosl overruns during the development and construction of facilities; internal restructuring or other restrucluring options lhat may be pursued; potenlial business strategies, including acquisitions or disposilions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterpnrties of the Company to make payments as and when due and to perform as required; the ability to obtain new short· and long-term contracts with wholesnle customers; the direct or indirecl effect on the Company's business resulting from terrorist incidents and lhe threat of terrorist incidenls; interesl rale fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings; the ability of the Company to obtain additional generating capacity at competitive prices; calastrophic events such as fires, earthquakes, e.'(pfosions, floods, hurricanes, droughls, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard-setting bodies; and other factors discussed elsewhere herein and in other reports (including the Fonn I0-K) filed by the Company from time to time with the Securilies and Exchange Commission. The Company expressly disclaims amy obligation to update any fonvard-looking statements. 11-433 SoCo FOIA Response 001483 CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,2010, 2009,and 2008 Southern Power Company and Subsidiary Companies 2010 Annual Report 2010 2009 2008 (illllmuscmcls) Operating Revenues: Wholesale revenues, non-affiliates Wholesale revenues, affiliates Other revenues Total operating revenues Operating Expenses: Fuel Purchased power, non-affiliates Purchased power, affiliates Other operations and maintenance Loss (gain) on sale of property Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Interest expense, net of amounts capitalized Profit recognized on construction contract Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Net Income $751,575 370,630 6,940 1,129,145 $394,366 544,4 I 5 7,870 946,651 $667,979 638,266 7,296 1,313,541 391,535 72,653 97,408 147,433 478 119,026 17,818 846,351 282,794 232,466 79,355 64,587 136,655 4.977 98,135 16,920 633,095 313,556 424,800 132,222 195,743 147,711 (6,0 15) 88,511 17,700 1,000,672 312,869 (76,111) 470 (372) (76,013) 206,781 76,759 $130,022 (84,963) 13,296 (374) (72,041) 241,515 85,663 $155.852 (83,212) 7,594 (75,618) 237,251 92,892 $144.359 The :~<:companying nolcsorc on integral part of these financial stutcmcnts 11-434 SoCo FOIA Response 001484 CONSOLIDATED STATEMENTS OF CASH FLOWS For lh~ \'ears Ended D~c~mber 31,2010, 2009,and 2008 Southern Pow~r Company and Subsidiary CompRnics 2010 Annual Report 2010 2009 2008 (in tllrm.,.mJs) Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating activities -Depreciation and amortization, total Deferred income taxes Convertible investment tax credits received Deferred revenues Mark-to-market adjustments Accumulated billings on construction contract Accumulated costs on construction contract Profit recognized on construction contract Loss (gain) on sale of property Other, net Changes in certain current assets and liabilities--Receivables -Fossil fuel stock -Materials and supplies -Prepaid income taxes -Other current assets -Accounts payable -Accrued taxes -Accrued interest -Other current liabilities Net cash ~rovided from opcratin!;l activities Investing Activities: Property additions Cash paid for acquisitions Sale of property Change in construction payables, net Payments pursuant to long-term service agreements Other investing activities Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds - capital contributions Payment of common stock dividends Net cash ~rovided from (used for) financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Supplemental Cash Flow Information: Cash paid during the period for-Interest (net of$12,110, $1,624 nnd $7,075 capitalized, respectively) Income taxes (net of refunds and investment tax credits) Noncash value of business exchanged in West Georgia acquisition Noncash transactions- accrued property additions at year-end $130,022 $155,852 $144,359 132,802 33,981 26,400 (5,586) 1,492 401 (65) (470) 505 5,708 110,427 22,950 16,800 2,288 5,204 48,451 (46,765) ( 13,296) 4,977 5,630 (703) (925) 85,619 (110,096) (22,674) 2,604 443 4,784 (167) 655 15,928 53 305 327,121 (9,717) 2,738 (5,345) 16,296 (298) 2,043 88 7 (199) 318,131 (11,156) (2,640) 2,773 (21,338) 1,413 10,451 (I ,622) (252) (3,575) 264,265 (299,602) (49,964) 4,000 31,290 (41,598) (721) (306,631) (137,133) ( 194, 156) 84 13,435 (46,120) ( 184) (364,074) 84,956 6,659 (107,100) (15,485) 5,005 7,152 $12.157 118,948 2,353 ( 106.100) 15,201 (30,742) 37,894 $ 7.152 $63,229 (6,246) $ 73,064 30,220 70,839 15,474 46,764 102,783 70,338 (6,015) 4,851 5,073 (7,529) (31,725) (I ,625) (85,770) (49,748) 3,642 (94,500) (140,606) 37,889 5 $ 37.894 $ 69,716 47,611 2.039 The accompanying notes arc an integral part of these finonciol slotcmcnts. 11-435 SoCo FOIA Response 001485 CONSOLIDATED BALANCE SHEETS At December 31,2010 and 2009 Southern Power Company and Subsidiary Companies 2010 Annual Report Assets 2009 2010 (iu 1/wu.w mds) Current Assets: Cash and cash equivalents Receivables-Customer accounts receivable Other accounts receivable Affiliated companies Fossil fuel stock, at average cost Materials and supplies, at average cost Prepaid service agreements - current Prepaid income taxes Other prepaid expenses Assets from risk management activities Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Plant in service, net of depreciation Construction work in progress Total property, plant, and equipment Other Property and Investments: Goodwill Other intangible assets, net of amortization of $693 and $17 at December 31. 20 I0 and December 31 , 2009, respectively Total other property and investments Deferred Charges and Other Assets: Prepaid long-tenn service agreements Other deferred charges and assets -- affiliated Other deferred charges and assets-- non-affiliated Total deferred charges and other assets Total Assets $12,157 $ 7,152 76,508 1,979 19,673 13,663 33,934 41,627 652 3,343 2,160 20 205,716 28,873 2,064 38,561 15,351 31,607 44,090 5,177 3,176 4,901 6,754 187.706 3,038,877 535,800 2,503,077 427,788 2,930,865 2,994,463 439,457 2,555,006 153,982 2,708,988 1,839 1,794 48,426 50,265 49, 102 50,896 69,690 3,275 16,540 89,505 $3 276 351 74,513 3,540 17.410 95.463 $3.043.053 The accompanying notes ore on integral part of these linanciol slnlcmcnts 11-436 SoCo FOIA Response 001486 CONSOLIDATED BALANCE SHEETS At December 31,2010 and 2009 Southern Power Company nnd Subsidiary Companies 2010 Annual Report Liabilities and Stockholder's Equity 2010 2009 (ill t/I Tuesday, March 06, 2007 8:56 AM Madden, Diane R.; Sarkus, Thomas A. Russia!, Thomas Re: Fwd: Target License Fees for Repayment Agreement - Confidential DianeThese new target license fees raise the expected repayment amounts above the minimum needed for reasonable assurance of repayment. The proposed (b) (4) Increase In target license fees needs to be sufficiently documented. This satisfies my concerns as long as Tom Russia I thinks that this approach Is sufficently binding for KBR. Minimum repayment rate required .... (b) (4) and (b) (4) per day Proposed (b) (4) of Increased target license fees .... (b) (4) and (b) (4) per day Charlie >>>Diane Madden 3/6/2007 8:28AM>» Charlie and Tom, Ken Markel asked that I forward this message from Southern for you to look at In reference to the issues raised about repayment on Southern Company's Continuation Application for Budget Period 2. Does this satisfy your concerns? Please let me know what you think. THANKS! Diane »>Diane Madden 3/5/2007 4:38PM>>> Ken, Here Is the response from Southern concerning repayment Diane >>>"Pinkston, Tim E." 3/5/2007 4:27PM»> The information In this email should be treated as confidential and subject to the restriction on the title page of our continuation application for Budget Period 2 under Cooperative Agreement DE·FC26-06NT42391. Our response to your comments on the repayment agreement follows. Target license fees to third parties for the TRIG technology are set by that DOE reviewed prior to signing of the Cooperative Agreement. The target license fees are currently(b) (4) (b) (4) (b) (4) (b) (4) have agreed to modify the target license fees In (b) (4) In proportion to the requested (b) (4) Increase In DOE cost sharing. This proposed change would Increase the target fees to (b) (4) electric power applications and (b) (4) (b) (4) Let me know if you need more Information or have questions. 1 SoCo FOIA Response 001509 Tum 4f13f2003? 6:45 PM Tom and Fran: SoCo FOIA Response 001510 Southern Company Services, Inc. Jennifer B. Morrison 600 North Eighteenth Street Rin 7N·B374 Birmingham, Alabama 35291·8122 205-257-6730 jenmorri@southernco.com A SOUTHERN COMPANY Hnt:rgy to Scrl•t• Your \%rid April 17,2007 Diane Rcvay Madden US Department of Energy/NETL MS 922-342C 626 Cochrans Mill Road Pittsburgh Pennsylvania 15236 Dear Diane, I am enclosing three (3) original copies of the Amended and Restated Repayment Agreement among SCS, DOE, an9 KBR, which have been executed by the appropriate SCS and KBR representatives. Please have the appropriate DOE representative sign these documents and return two (2) fully executed originals to me at the address shown above. (b) (4) I very much appreciate your assistance in and coordination of this matter. Please do not hesitate to contact me if you have any questions or concerns regarding the enclosed materials. Sincerely, .~)j.N\~.i ~ -6.11~ ?;,~nifer ilf:"'viorrison /\Horney for Southern Company Services, Inc. Enclosures cc: Tim Pinkston SoCo FOIA Response 001511 SoCo FOIA Response 001512 SoCo FOIA Response 001513 14 Mar ?9 97 12:57p p.1 (b) (4) (b) (4) UNANIMOUS CONSENT OF DIRECTORS OF SOUTHERN POWER COMPANY TO ADOPTION OF ACTIONS AND RESOLUTIONS JN T.mrJ OF MF.ETING i. The undersigned, being all of the members of the Board of Director~; of Southern Power Company, a Delaware corporation (the "Company"), by written consent rursuant to the General Corporation Law of Delaware, cfo hereby adopt as of March 29, 2007, the following resolutions: RF..SOLVED: That the continuation of the design, engineering and construction of the Gasification Island Project is hereby approved, subject to approval by the Orlando Utilities Commission of amendments to existing agreements and approval by the United States Department of Energy (the "DOE") of additional funding for the Gasification Island Project; RESOLVED FURTHER: That U1e officers of Ule Company and the officers of Southern Company Services, Inc., acting as agent for the Company, are hereby aulhorizcd, in their discretion. to execute amendments, substantiaiJy consistent with !;uch documents presented at the meeting of the Company's Board of Directors on March 26, 2007, to the following agreements: • • • Orlando Gasification Project Construction and Ownership Participation Agreement, Gasification Island Capacity Purchase Agreement and DOE Cooperative Agreement: RESOLVED FURTHER: That tile officers are hereby authorized ro execute any other agreements, amendments, guaranties, instruments and/ol' t·egulatory applications to carry out tlte intent of the foregoing resolutions and any and all actions of the officers prior co the date hereof relative to the Gasification Island Project are hereby ratified, confilmed and appro,•ed. use or disclosure of dala on this sheet Is subjeello lhe reslriclion on I he lllle page of the BP 2 Contlnuallon Appllcallon for Cooperative Agreement No. OE·FC·06NT423G1. SoCo FOIA Response 001515 .Mar 29.07 12:57p p2 (b) (4) (b) (4) RESOLVED FURTHER: That the total expenditures for capital additions and improvements for the years 2007-2009 approved by the Board of Dil'ectors of the Company on Febmary 28, 2007 are hereby revised as follows: 2007 - $257.8 mil1ion 2008-$537.1 million 2009- $865.0 million RESOLVED FURTHER: That the officers are hereby authori7.ed and directed to consider, the forecast figures when planning the financial needs of the Company, to announce to the public such forecast figures when infonnation will benefit the public or when required by law and to take such other actions concerning forecast figures which legal counsel advises are appropriate; and RESOLVED FURTHER: That the officers arc hereby authorized to reallocate expenditures, within the limits of the approved budget for capital additions and improvements, to address changes in priorities due to competitive needs or forecast changes. as they deem appropriate. IN WITNESS WHEREOF, U1e undersigned have hereunto set their hnnds as rs of c corporation effective as of the day and year ft.rst above written. -auJL<&wv W. Paul Bowers Thomas A. Fanning Q. Edison Holland. Jr. David M. Ratcliffe Use or dlsclosUfe of data on this sheet Is subject to the restriction on the title page olthe BP 2 Continuation AppAcatlon for Cooperative Agreement No. DE·FC·OONT42391. SoCo FOIA Response 001516 UNANIMOUS CONSENT OF DIRECTORS OF SOUTHERN POWER COMPANY TO ADOPTION OF ACTIONS AND RESOLUTIONS IN LIEU OF MEETING The undersigned, being all of the members of the Board of Directors of Southern Power Company, a Delaware corporation (the "Company''), by written consent pursuant to the General Corporation Law of Delaware, do hereby adopt as of March 29. 2007, the following resolutions: RESOLVED; That the continuation of the design, engineering and construction of the Gasification Island Project is hereby approved, subject to approval by the Orlando Utilities Commission of amendments to existing agreements and approval by the United States Department of Energy (the "DOE") of additional funding for the Gasification Island Project; RESOLVED FURTHER: That the officers of the Company and the officers of Southern Company Services, Inc., acting as agent for the Company, are hereby authorized, in their discretion, to execute amendments, substantially consistent with such documents presented at the meeting of the Company's Board of Directors on March 26,2007, to the following agreements: • • • Orlando Gasification Projt"..ct Construction and Ownership Participation Agreement. Gasification Island Capacity Purchase Agreement and DOE Cooperative Agreement; RESOLVED FURTHER: That the officers are hereby aulhorized to execute any olhcr agreements, amendments, guaranties, instruments and/or regulatory applications to carry out the intent of the foregoing resolutions and any and all actions of the officers prior to the date hereof relative to the Gasification Island Project are hereby ratified, confirmed and approved. Use or disclosure of dale on this sheells subjecllo lhe restriction on lhe Ulle page ollhe BP 2 Continuation Apptlcallon lor Cooperative Agreement No. DE-FC 06NT42391 . 10'd SoCo FOIA Response 001517 ** 2B'39ijd 1~101 ~* RF.SOLVED FURTHER: Tiaat the lot.al expenditures for capital additions and imp(ovements for the yem·s 2007-2009 approved by the Board of Directors of the Company on February 28, 2007 are hereby revised as foHows; I r I i I ! 2007-$257.8 million 2008-$537.1 million 2009- $865.0 million RESOLVED FURTHER: That the officers are hereby authorized and directed to consider, the forecast figures when planning the financial needs of the Company, to announce to the public sucb forecast figures when infonnation will benefit the public or when required by law and to take such othe.r actions concerning forecast figures which legal counsel advises are appropriate; and RESOLVED FURTHER: That the officers arc hereby authorized to reallocate expenditures, within the limits of tltt: approved budget for capital additions and improvements, ro address changes in priorities due to competitive needs or forecast changes, as they deem appropriate. IN WITNESS WHEREOF, the undersigned have hereunto set their hands as Directors of the corporation effective as of the day and year first above written. W. Paul Bowers Thomas A. Fanning Use 01 disclosure of data on this sheet is subject to the resllldlon on the lille page of the BP 2 Continuation Application for Cooperative Agreement No. DE-FC-06NH2391. 20 ' d SoCo FOIA Response 001518 MAR,29'2007 11:46 404 506 0394 SOUTHERN CO./TO:-! FANNING nun P.oo11ooz UNANIMOUS CONSENT OF DIRECTORS OF SOUTHERN POWER COMPANY TO ADOPTION OF ACTIONS AND RESOLUTIONS IN LffiU OF MEETING The undersigned, bcJng all of the members of the Board of Directors of Southern Power Company, a Delaware corporation (the "Company''), by written consent pursuant to the General Corporatjon Law of Delaware, do hereby adopt as of March 29, 2(107, the following resolutions: Rf::SOLVED: 11tat the continuation of r.he design, engineering o11d consf:l;uction ofthe Gasification lslond Project is h~reby approved, subject t.o approval by tbe Orlendo Utilities Commission of amendments tQ existing agreements and approval by tho United States Department of Energy (the .. DOE") of additional funding for tbe Gasification lsJM4 Project; RESOLVED FURTHER: Tbat Ute officers of rhe Company and the officers of Southern Company Services, Jnc., acting as agent for the C9mpany, ate hereby authori1.ed, in their djscretion, to execute amendments, substantially consistent with such documents presented at the: meeting of the Company•s Board ofDirectors on March 26,2007, to the following agreements: • • • Orlando Gasification Project Comtruction and Ownership Participntion Agreement, Gasification Island Capacity Purchase Agceement and DOE Cooperative Agreement; RESOLVEP FUR11JER: Thnt the officers are hereby authorized to execute any otb.er agreements, runendmcnts, guaranties, instroments and/or regulntocy applicatiOJIS to carry out the Intent of the foregoing resolutions and any and all actions of the officer.J prior to the date hereof relative to the Gositication Island Project are hereby ratified, confurocd and approved. Use or disclosure of data on this sheet Is subject to the reslrlctlon on the tU!e page of the BP 2 Conllnuallon Application for Cooperative Agreement No. DE·FC·06NT42391. SoCo FOIA Response 001519 H~R.~9'2007 11:46 40~ 506 0394 SOUTHERN CO./TOI1 FTINIHNG 114847 P.002/002 ~· I RESOLVED FURTHER: That the total expenditures for capital additions and improvements for tlte years 2007~2009 approved by the Board of Directors of IJ1c Company on February 28, 2007 are hereby revised as follows; 2007 -$257.8 million 2008 -$53 7.I roillion 2009- $865.0 million RESOLVBD FURTHER: That the officers are hereby authorized and directed to consider, the forecast figures when planning the financial needs of the Company, to annowtce to the public such forecast figures when information will benefit the public or when required by law and to take such other actions conccmJng forecast figures which legal counsel advises are appropriate; and RESOLVED FURTHER: Thot rhe officers ore hereby authorized to reallocate expenditures, within the limits of the approved budget for capital additions and improvements, to address cbn.nges jn priorities due to competitive oeetls or forecast changes, as they deem appropdare. IN WITNESS WHEREOF. the undersigned have hereunto set fheir hands as Directors of the corporation effective as of the day and year first above written. w. Paul Bowers G. Edjson Holland, Jr:. David M. RatcUffe Use or disclosure of data on this sheells subject to the restriction on lhe IItie page of the BP 2 Conllnuallon Application for Cooperative Agreement No. DE-FC-06NT42391. SoCo FOIA Response 001520 Use or disclosure or data on this sheet is subject to the restriclion on the title page or the BP 2 Continuation App!lcatlon for CooperaUve Agreement No. DE-FC26·06NT423!11. (b) (4) (b) (4) SoCo FOIA Response 001521 Use or dlsclosu1e of data on this sheet Is subject to the restriction on the tille page of the BP 2 Conllnuallon Application for Cooperative Agreement No. DE·FC26·06NT42301. (b) (4) SoCo FOIA Response 001522 ATTACHMENT D AMENDED AND RESTATED REPAYMENT AGREEMENT DE-l<'R26·06NT42392 This Amended and Rc.~tated Repayment Agreement by and between the United States Department of Energy (DOE), Southern Company Services, Inc. (SCS), and Kellogg Brown & Root LLC (successor to the rights and obligations of Kellogg Brown & Root, Inc.) is made and entered into as of April __, 2007. This Amended and Resuued Repayment Agreement supersedes and replaces the Repayment Agreement entered into on February 22, 2006. This Amended and Restated Repayment Agreement ratifies and confirms the rights and obligations of thr: parties- as amended herein -which becante effective on February 22, 2006. In consideration of the United States Department of Energy (DOE) support for a clean coal technology Demonstratiou Project uuder the DOE's Clean Coul Power Initiative, for which SCS and KBR, both being defined herein as an "Obligor,'' acknowledge that they will receive substantial benefit, the Obligors hereby agree to repay the Department of Energy in accordance with the terms and conditions set forth below. At·Uclc I. Generol Objective The purpose of this Repayment Agreement is to set forth the conditions under which the Obligors shall repay to DOE an amount up to, but not to exceed, the DOE share puid under Cooperative Agreement Number DE-FC26· 06NT42391, such obligation being the direct responsibility of each Obligor and being for the direct benefit of DOE, as accomplished via the aud upon the terms set forth herein. (b) (4) Article II. Definitions "Cooperative Agreement" mean!'i the financial a.~sistancc award made by lhe United States Department of Energy (DOE) to SCS, Instrument Number DE·FC26-06NT42391 on January 30, 2006, and subsequent amendments. "DOE Share" means the portion of the total project costs paid by DOE under the Cooperative Agreement. "Obligor" means the organizations that are responsible for repayment under this Repayment Agreement, SCS and KBR, as stated above. "Obligor" includes these organizations' successors and assigns. "Repayment Perind" means the period of time during which a transaction becomes subject to repayment under this Repayment Agreement. "Total Project Costs" means the totnl umount of allowable direct and indirect costs incurred 11nd paid, in part, by DOE under Coopcrntivc Agreement. "Dentonstration Technology'' shall mean the transport reactor-based gasification/IGCC technology which is proposed for demonstration under the Cooperative Agreement, including all past, current, and future information and intellectual property developed by, on behalf of, or together by, SCS or KBR, as Obligors, and their respective affiliates, present and future, that enhances or improves the performance of the transport reactor in its application as u coal gasifier for the production of raw synthesis gas which subsequently may be further processed to produce electricity (and/or steam), chemicals, or fuels. "Demonstration Project" shall mean the Integrated G11silicntion Combined Cycle (IGCC) power plant project being undertaken by SCS and DOE under the Cooperative Agreement Number DB-FC26.Q6NT42391. "Southern Company Services Affiliates" shall mean any subsidiary of, and under common control of, their single parent, The Southern Company, whether a first tier subsidiary of The Southern Comp;my or any lower tier subsidiary of the first tier subsidiary. SoCo FOIA Response 001523 Article Ill. Repayment Per~od The Repayment Period shall begin on the date of the first sale of the Demonstration Technology or on the date specified in the Cooperative Agreement for the end of the Demonstration Period, whichever occurs first. However, if SCS withdraws or tenninntcs its participation nnder the Cooperative Agreement, or if the 11roject is terminated in accordance with Paragraph 2.34 (Termination) of the Cooperative Agreement or terminated ·due to POE's disapproval of a continuation application in accordance with Paragraph 2.11 (Continuation Application) of the Cooperative Agreement, this Repayment Period shall begin on the date the Cooperative Agreement is tem1inated. The Repayment Period shall expire 20 years after the date the Repayment Period begin3. Obligors' obligation to repay DOE expires on the date the entire DOE share has been repaid, or the date on which repayments for all transactions entered into during the Repayment Period have been made, whichever occurs first. This Repayment Agreement may be terminated upon a determination by the Secretary of Energy, or designee, that repayment places an Obligor at a competitive disadvantage In domestic or international markets. Arlicle IV. Basis for Repavment Though collection of payment to DOE by the Obligors shall be cumulative and consolidated into single payments submitted by SCS to DOE, each Obligor is Individually responsible to DOE for amounts due to DOE from the Obligor. DOE shall have a direct claim against an Obligor for breach of the tenns of this Repayment Agreement by the Obligor. The obligations of either Obligor under this Repayment Agreement shnll survive the expiration, termination, transfer, assignment, novation, sale, merger, consolidation, or other change in control of, an Obligor until the expiration of the repayment obligation to DOE. The annual amount of repayment to DOE by the Obligors is to be comprised of the cumulative effect of the provisions in Article IV (i), (ii), and (iii): (I) KBR shall pay to SCS, for transfer by SCS to DOE, an amount equal to (b) (4) of the license fees and/or royalties actually retained by KDR from licensing of the Demonstration Technology to third-party users for the production of electricity (nndJor steam), chemicals, or fuels, after satisfying guaranty or warranty responsibilities. Distributions made by KBR to SCS are considered to be included In the amount actually retained by KBR. In the event that KBR does not charge a license fee to a third party for any installation orthe Demonstration Technology, KBR will be deemed to have incurred a license fee in an amount equivalent to the license fee on the most recent prior project of substantially similar scope utilizing the Demonstration Technology and in the pro rata amount of the size of such installation. If no prior license has been granted, the amount due to DOE shall be calculated at(b) (4) (or equivalent) of installed cnpacity. KBR shall not be responsible for such fee if SCS and KBR (b) (4) mined and explicitly documented that the market for that project will not bear this license fee. SCS agrees that It shall not accept any compensation in lieu of royalties due from KBR under the (b) (4) (b) (4) In the event that SCS sells directly to third parties, SCS shall pay directly to DOE (b) (4) of the license fees and/or royaltiC3 actually retained by SCS from licensing of the Demonstration Technology to third·party users for the production of electricity (andJor steam), chemicals, or fuels, after satisfying guarantee or warranty responsibilities. In the event that SCS does not charge n license fee to a third party for any installation of the Demonstration Technology, SCS will be deemed to have incurred R license fee In the nmount equivalent to the license fee on the most recent prior project of substantially similar scope and in the pro rata amount of the size of the in5tallalion. If no prior license has been granted, the amount due to DOE shall be calculated at (or equivalent) of installed capacity. (b) (4) A transaction shall be subject to repayment under this provision if an Obligor enters into a license or contract for sale during the Repayment Period notwithstanding that repayment may occur after the Repayment Period. Repayment shall accrue after satisfying guaranty or warranty responsibilities. For any commercial application of the Demonstration Technology by SCS, or SCS affiliates, for the production of electricity (and/or steam), excluding this Demonstration Project, SCS agrees to pay to DOE a one lirnc fee o(b) (4) of initial, actual tested perfonnance for each commercial application. Such payment to DOG shall be prorated by SCS', or SCS affiliates', initial percentage of ownership of such facility. An installation shall be subject to repayment under this provision if SCS, or SCS affiliates, breaks ground for the installation during (ii) 2 SoCo FOIA Response 001524 the Repayment Period, notwithstanding that repayment may occur after the Repayment Period. Repayment shall aecme upon the declaration of commercial operation. For any commercial application of the Demonstration Technology by SCS, or SCS affiliates, for the production of chemicals and fuels, excluding this Demonstration Project, SCS agrees to pay DOE a one lime fee of for each (b) (4) ercentage ownership of such facility. An installation shall be subject to repayment under this provision if SCS, or SCS affiliates, breaks ground for the installation during the Repayment Period, notwithstanding that repayment may occur aner the Repayment Period. Repayment shall accrue upon the declamtion of commercial operation. (iii) Arlicle V. Schedule for RepAyment Payments to DOE by SCS of the cumulative amounts required for the period shall be due within 60 days after each one-year period following the start of the Repayment Period for Repayment Agreement DE-FR26-06NT42392. Checks shall be made out to the US Department of Energy and be mailed to the Financial Management Division, USDOE, NETL, Post Office Box 10940,626 Cochrans Mill Road, Pittsburgh, Pennsylvania 15236-0940. Article VI. Reporting and Record Retention Requirements (A) Annugl Report to DOE Within 60 days after the end of each one year period, the Obligors shall prepare a consolidated report and SCS shall submit such report to DOE which, for the one year period just elapsed, provides the applicable data described below: (I) The total dollar amount of repayment accruing to DOE. (2) A description of each transaction from which the repayment obligation accrued. (3) The total nmount paid to DOE for all years and the amount of the DOE share remaining to be paid in succeeding years under this Repayment Agreement. Notwithstanding that SCS will submit the Annual Report to DOE, the responsibility for submittal of information to prepare the report, and the responsibility of preparation of the report, falls equally on the Obligors. DOE shall have n direct claim against either Obligor for failure to comply with the requirements of this clause. (B) Commercialization Report For a period of five (5) years aOer completion of the Demonstration Project, the Obligors shall be equally responsible For submitting a Commercialization Report describing the Obligors' progress and success in commercializing the technology used during the project as well as technology derived from that used during the project. The purpose of the Commercialization Report is to assist DOE to determine the benefits obtained from Government support of technology development. The Commercialization Report is independent from the Annual Report required by the Repayment Agreement and is not limited to the sale or licensing of "Demonstration Technology" as that tenn Is defined in this Repayment Agreement. The Commercialization Report shall include a discussion of the Obligors' efforts to commercialize the technology. The Commercialization Report shall also include descriptions and locations (or proposed locations) of all significant technology embodied in the Demonstration Project, or derived from technology embodied in the Demonstration Project, that was sold or licensed during the preceding year (whether or not such transactions were subject to repayment under the terms of the Repayment Agreement). The Commercialization Report shall also include a discussion of any impediments to the commercialization of the technology. It is understood and agreed by DOE that the Commercialization Report shall be in a level of detail that is not required to contain Limited Rights Data or Protected Data as defined in the Cooperative Agreement, recognizing that the commerciali:c.ation efforts involve proprietary and confidential business information which will necessarily bo accorded secrecy treatment. The Commercialization Report shall be due on December 31 of each year. DOE shall look to each Obligor for compliance with its applicable portion of the requirements of this clause and obtain performance directly from the responsible Obligor. 3 SoCo FOIA Response 001525 (C) Period of Retention With respect to each annual report to DOE, the Obligors shall retain, for the period of time prescribed in this paragraph, all related financial records, supporting documents, statistical records, and any other records the Obligors reasonably consider to be pertinent to this Repayment Agreement. The period of required retention shall be from the date each such record is crcnted or received by an Obligor until three years after one of the following dates, whichever is earlier: the date the related annual report is received by DOE, the date this Repayment Agreement expires, or the date final payment to DOE is received. · If any claim, litigation, negotiation, Investigation, audit, or other action involving the records starts before the expiration of the three-year retention period, the Obligors shall retain the records until such action is completed and nil related issues are resolved, or until the end of the three-year retention period, whichever is later. The Obligors shall not be required to retain any records, which have been transmiued to DOE by an Obligor. (D) Authorized CQ~ Copies made by microfilm, photocopying, or similar methods may be substituted for original records. Records originally created by computer may be retained on an electronic medium, provided such medium is "read only" or is protected in such a manner thai the electronic record can be authenticated as nn original record. (E) Access to Records DOE and the Comptroller General of the United States, or any of their authorized representatives, shall have the right of access to any books, documents, papers, or other records (including those on electronic media) which are pertinent to this Repayment Agreement. The purpose of such access is limited to the making of audits, cxamlnnlions, excerpts, and transcripts. The right of access described in this paragraph shall last as long as an Obligor retains records, which arc pertinent to this Repayment Agreement. (F) Rcstrjctjons on Public Djselosure The Federal Freedom of Information Act (S U.S.C. Section 552) does not apply to records an Obligor is required to retain by the terms of this Repayment Agreement. Unless otherwise required by law or n court of competent jurisdiction, an Obligor shall not be required to disclose such records to the public. (G) Flow Down of Records, Retention. and Access Requirements Obligor~ shall include clauses substantially similar to the record retention and access requirements set forth in sections (C) and (E) orthis Article in all agreements when necessary to fulfill the Obligors' obligations under this Repayment Agreement. Arliele VII. ~ If either Obligor is responsible for the failure of SCS to make payment within the time specified in Article V, or is responsible for SCS' failure to submit the annual report within the time specified In Article VI, the Obligor which is In default of its own obligations under this Repayment Agreement and fails to cure the default within 30 days after receipt of written notice of the default from DOE, notwithstanding any provision of the Cooperative Agreement, Its flow down provisions, or this Repayment Agreement to the contrary, that Obligor shall pay to DOE the amount of $100.00 per day for every business day that the payment or report is delayed due to the fault of that Obligor. Obligors and DOE agree that such amount represents DOE's reasonable costs and acknowledge that the liquidated damages set forth herein are an adequate remedy for default and shall not be considered a penalty. Nothing contained herein shall preclude DOE from pursuing any other remedy against an obligor which may be available for the payment of moneys due including interest thereon in accordance with applicable statutes and regulations. 4 SoCo FOIA Response 001526 Arlh:le VIII. ~ Disputes arising under this Repayment Agreement shall be subject to the procedures set ronh in 10 CF'R 600.22 Disputes and Appeals. UNITED STATES DEPARTMENT OF ENERGY OBLIGOR (Kellogg Brown & Root LLC (as successor to the rights and obllga lions of Kellogg Brown & Root, Inc.)) Signature: Signature:----------=----- Name: Date: Name: Title: Contracting Officer: Title: (b) (4), (b) (6) (b) (4), (b) (6) ate: 11 ,.Af,.'J~ '?..D Monday, March 12, 2007 11:59 AM Russia!, Thomas RE: IRS You have permission to use the memo from Troutman. I should have a draft letter to you shortly. Randall E. Rush Director, Power Systems Development Facility Southern Company Generation Highway 25 North P. 0. Box 1069 Wilsonville, AL 35186 *Internal:S-824-5842 *External: (205) 670-5842 *Cell: (b) (6) *Linc:( (b) (6) *Fax:(205) 670-5843 ) E-mail:rerush@southernco.com -----Original Message----From: Thomas Russia! [mailto:Thomas.Russial@NETL.DOE.GOV] Sent: Sunday, March 11, 2007 10:34 AM To: Rush, Randall E. Subject: Re: IRS b 5 SoCo FOIA Response 001528 I35 SoCo FOIA Response 001529 Dunlap, Ann C. From: Sent: To: Subject: Attachments: "Rush, Randall E." Monday, March 12, 2007 1:09 PM Russia!, Thomas Draft IRS Problem letter to DOE.doc Draft IRS Problem letter to DOE.doc Tom, comments on this draft <> SoCo FOIA Response 001530 The pmpose of this letter is to advise you of a serious problem that has arisen on the Orlando transport gasification demonstration project. This project is the cornerstone of Southern Company's and om partne (b) (4) ability to deliver the Irnnsport Integrated Qasification (TRIGTM) technology to both the powet· and the coal-to-liquids markets. We arc nearing completion of Phase I - Project Definition and have submitted a Continuation Application to begin Phase II- Design and Construction. The Phase I work was completed during an unprecedented period of inOntion in the cost of materials and labor that has increased the cost of all major energy and inll·astntcture projects worldwide. Working cooperatively with out· partners and the Depat·tment of Energy (DOE) we have devised a plan that we believe will allow the project to go forward in spite of a 60% capital cost increase. Final decisions on the details of this plan are expected by all parties by March 31. In order to meet project schedule mnjor equipment procurement must begin the first week of April. However, we were udvised last week that the Intemal Revenue Service (IRS) has determined that the DOE tlmds being provided to the project under Public Law _ are now deemed to be taxable. I am sure that your staff can apprise you of the details behind the IRS' view on taxability and on the unexpected nature of this determination. Th~ effect of this decision by the IRS is to make the project uneconomic based on current information. (b) (4) Southern and would be willing to consider developing another deal if DOE were agreeable, but even if that were possible any new deal will add significant cost and delay demonstration of a critical new gasification technology. A key aspect of TRIGTM is its ability to cost-effectively process high ash, high moisture and low rank coals such as subbituminous and lignite. These coals make up half both the coal supply in both the U.S. and the world. Without a timely, commercial demonstration ofTRJG™ options for future coal-based power will decrease and cost will increase. Southern and (b) (4) have an aggressive progmm to commercialize TRIGTh1, but a mid2010 commercial operating date for the Orlando project is a critical aspect of this progmm. At least two key customers have expressed a clear requirement that the Orlando unit must become operational for them to consider usc ofTRIGTM at their facilities. The inability to execute the Orlando pmject, a delay from extended renegotiations there or relocation to another site will require us to seriously rethink our ability to profitably continue in the gasification supply market. Under the circumstances we believe that the best course of action is for the Secretary or his designee to determine that the current repayment plan should be waived in order to avoid creating a competitive disadvantage for TRIGn.t in domestic and intemational markets. We understand that this will allow DOE project funding to be treated as a "contribution to capital" and render these funds non-taxable as income. If the DOE funds were later determined to be non-taxable without the waiver Southern and (b) (4) gree to reinstatement of the repayment agreement as originally negotiated. SoCo FOIA Response 001531 A thank you in advance for you consideration ofthis request. The world badly needs new methods of using our abundant coal reserves. Southern and (b) (4) are moving aggressively to provide TRJGTM as one such improved method. Please do not hesitate to contact me iff can offer clarification or answer any questions you may have. SoCo FOIA Response 001532 Dunlap, Ann C. From: Sent: To: Subject: Thomas Russial Wednesday, March 14, 2007 9:09AM Rush, Randall E. Re: letter from Paul Bowers to Secretary Bodman requesting Orlando Repayment Vaiver bS >>> 11 Rush, Randall E." 3/13/2007 3:57PM>>> Please see the attached letter to Secretary Bodman from Paul Bowers President of Southern Company Generation requesting waiver of the the Orlando project repayment requirements. As we discussed if this issue can be resolved we need to know by 3/22 if at all possible- by 3/31 at the very latest. < > Randall E. Rush Director, Power Systems Development Facility Southern Company Generation Highway 25 North P. 0. Box 1069 Wilsonville, AL 35186 *Internal:B-824-5842 *External:(205) 670-5842 *Cell: ( (b) (6) *Linc:( (b) (6) *Fax:(205) 670-6843 ) E-mail:rerush@southernco.com SoCo FOIA Response 001533 Dunlap, Ann C. From: Sent: To: Cc: Subject: Madden, Diane R Tuesday, March 27, 2007 2:35 PM Markel, Kenneth Russial, Thomas (b) (4) Info received from about construction cost index Ken, (b) (4) Tim Pinkston just sent this paragraph that he received from n response to the question about the construction cost index escalation. Your decision whether or not to add it. (b) (4) SoCo FOIA Response 001534 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Robbins, Brittley K. Thursday, April OS, 2007 11:42 AM Russial, Thomas Madden, Diane R. Fwd: RE: Revised Repayment Agreement DOE·SCS-KBR Repayment Agreement-- Amended and Restated (4·5·07).doc Tom: Please review the Repayment Agreement as revised by scs. Clearly, the grammatical corrections are acceptable but I wanted to know what you think about the whole "Amended and Restated" language. Thanks, Brittley >>> "Morrison, Jennifer B." 4/5/2007 10:22 AM >>> Brittley, I am working with Tim and Charles on matters related to Agreement Number DE-FCZ6-06NT42391, including the Repayment Agreement that is the subject of your e-mail below. Tim and I have reviewed the document that you sent and have just one question/concern. We wondered why this amended agreement did not reference the fact that it Is an amended version of the agreement. For the sake of clarity, we would like to suggest the addition of some clarifying language that documents and preserves the "history" of this contract. As you will see from the attached redllned version of the document, the new language that we are suggesting is minimal, but it memorializes the fact that there was a prior version of the agreement. Please note that it retains the same effective date (February 22, 2006) with respect to the parties' rights and obligations. For consistency, we may want to consider using the phrase "Amended and Restated Repayment Agreement" throughout the document. You will also note that, In the attached version, I have made three changes of a grammatical nature: (i) a correction to the spelling of "Affiliates" on page 2 In the definition of "Southern Company Services Affiliates;" (il) the insertion of"Inc." after Southern Company Services In the signature block; and (iii) modification of KBR's name to omit the comma (which Is how KBR's name appears on Its Incorporation documents). Please contact Tim or me If you have any comments or concerns regarding these matters. I would enjoy the opportunity to meet you over the telephone to discuss this and any other items with you. ,, ti Regards, Jennifer Jennifer B. Morrison Senior Attorney Southern Company Services, Inc. 600 North 18th Street Binningham, Alabama 35203 205-257-6730 (phone) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its atlachments may contain proprietary information of Southern Company and/or its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is 1 SoCo FOIA Response 001535 intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this email, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and Is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Pinkston, Tim E. Sent: Wednesday, April 04, 2007 11:25 AM To: Morrison, Jennifer B. Subject: FW: Revised Repayment Agreement From: Brittley Robbins [mallto:Brittley.Robblns@NETL.DOE.GOV] Sent: Friday, March 30, 2007 3:32 PM To: chender@southernco.com; Pinkston, Tim E. Cc: Madden, Diane Subject: Revised Repayment Agreement Charles and Timothy: I first want to introduce myself as the new Contract Specialist assigned to the "Demonstration of a 285MW Coalbased Transport Gasifier" project (DE-FC26-06NT42391). I have heard only good things about both of you and look forward to working with you. In response to a request from Tim, I have attached a copy of the revised Repayment Agreement. The following information has been revised: under Article IV, numbers were updated In paragraphs (i), (II), and (iii). Also, two grammatical changes were made: (1) the first paragraph was corrected to combine the two sentences into one sentence, separated by a comma, and (2) under Article VI. A, the first sentence was corrected by removing the words "of the". Please feel free to contact me with any questions. I have prepared a no-cost time extension to revise the end date of Budget Period 1 to 04/30/2007. It should be mailed out on Monday but I can also fax you a copy If you would like. Thanks again, Brittley Robbins Contract Specialist, DOE-NEll Acquisition and Assistance Division (412) 386-5430 •' 2 SoCo FOIA Response 001536 ATTACHMENT I> AI\'IENDED AND RESTATED REPAYMENT AGREEMENT DE-Fil26-06NT42392 This Amended and Re.~tatcd Repaym~nt Agreement by and between the United States 1Jcll311lllent pf Energy mom. Sonthcm Company Services, Inc. (SCSl. and Kellogg Brown & as of April Root. Inc. (KORl is made and entered into . 2007. This Amended nnd RestattJd Repayment Agreement supersedes nnd replaces the Repayment Agreement entered into on 1:ebruary 22. 2006. This Amended and Restated Retl:l\'ntent Agreement rntilies and confirms the rh?.hts and obligations of the Jlscd, provides the applicable data described below: .I (I) The total dollar amount of repayment accruing to DOE. (2) A description of each transaction from which the repayment obligntionoccrucd. (3) The total amount paid to DOE for all years and the amount of the DOE share remaining to be paid in succeeding years under this Repayment Agreement. Notwithstanding that SCS will submit the Annual Report to DOE, the responsibility for submittal of infonnation to prepnre the report, nnd the responsibility of preparation oftl1e report, falls equally on the Obligors. DOE shall have o direct clnim against either Obligor for failure to comply with the requirements of this clause. (B) Cormnercinlization Report for n period of five (5) years after completion of the Demonstration Project, the Obligors shall be equally responsible for submilting a Commercialization Report describing the Obligors' progress and success in commercializing the technology used during the project as well as technology derived from that used during the project. Tire purpose of the Cormnercinlization Report is to assist DOE to determine the benefits obtnined from Govenunent support of technology development. The Commercialization Report is independent from the Annunl Report required by the Repayment Agreement and is not limited to the sale or licensing of "Demonstrotion Technology" as that term is defined in this Repayment Agreement. The Commercialization Report shall include a discussion of the Obligors' efforts ,to eormncrciali7.e the technolog)'. The Commercializ11tion Report shall also include descriJltions and locations (or proposed locations) of all significant technology embodied in the Demonstrntion Project, or derived !Tom technology embodied in the Demonstrntion Project, that was sold or licensed 3 SoCo FOIA Response 001539 during the preceding year (whether or not such transactions were subject to repayment under the terms of the Re1>ayment Agreement). The Commercialization Repott shall also include a discussion of any impediments to the connnercialization of the technology. It is understood and agreed by DOE thnt the Commerciali;mtion Report shall be in a level of detail thnt is not required to contain Limited Rights Data or Protected Data as delined in the Cooperative Agreement, recognizing tlmt the commercinlization efforts involve proprietary and confidential business information which will necessarily be nccorded secrecy treatment. The Commerciali7.ation Repon shall be due on December 31 of each year. DOE shnll look to each Obligor for compl iancc with ils applicable portion of the requirements of this clause and obtain performance directly from the responsible Obligor. (C) Period of Retention With respect to each annual rep011 to DOE, the Obligors shall retain, for the period of lime prescribed in this paragraph, all related financial records, supporting documents, statistical records, nnd any other records the Obligors reasonably consider to be pc1tinent to this Repayment Agreement. The period of required retention shall be from the date each such record is created or received by an Obligor until three years after one of the following dates, whichever is earlier: the date the related annual report is received by DOE, the date this Repayment Agreement expires, or the date finalJ>ayment to DOE is received. If nny claim, litigation, negotiation, investigution, audit, or other action involving the records starts before the e;>;piration of the three-year retention period, the Obligors shall retain the records until such action is completed and nil related issues are resolved, or until the end of the three-ycnr retention period, whichever is Inter. The Obligors shall not be required to retain any records, which have been transmitted to DOE by nn Obligor. (D) Authorized Copies Copies made by microfilm, photocopying, or similar methods may be substituted for original records. Records originally created by computer may be retained on nn electronic medium, provided such medium is "read only" or is protected in such n manner that the electronic record can be authenticated ns nn original record. (E) Access to Records DOE and the Comptroller General of the United States, or any of their authorized representatives, shall have the right of access to any books, documents, papers, or other records (including those on electronic rncdin) which arc pe11incnt to this Repayment Agreement. The purpose of such access is limited to the making of andits, examinations, excerpts, and transcripts. The right of access described in this paragraph shall last as long as nn Obligor retains records, which are pertinent to this Repayment Agreement. (F) Restrictions on Public Disclosure The Federal Freedom of lnfommtion Act (5 U.S.C. Section 552) does not apply to records an Obligor is required to retain by the terms of this Repayment Agreement. Unless otherwise required by law or a cou11 of competent jurisdiction, nn Obligor shall not be required to disclose such records to the public. (G) Flow Down of Records, Retention. and Access Requirements Obligors shall include clauses substantinlly similar to the record retention and access requirements set forth in sections (C) and (E) of this Article in nil agreements when necessary to fulfill the Obligors' obligations under this Repayment Agreement. Article VII. Default If either Obligor is responsible for the failure of SCS to make payment within the time specincd in At1icle V, or is responsible for SCS' failure to submit the nnnual report within the time specified in Anicle VI, the Obligor which is in defnult of its own obligations under this Repayment Agreement and fails to cure the default within 30 days after receipt of written notice of the default from DOE, notwithstanding nny provision of the Cooperative Agreement, its tlow down Jlrovisions, or this Repayment Agrecmertt to the ~:ontrary, that Obligor shall pay to DOE the amount of S100.00 per dny for every business day thnt the payment or report is delayed due to the fault of that Obligor. Obligors and DOE ngrec that such amount represents DOE's rensonable costs nnd acknowledge that the liquidated 4 SoCo FOIA Response 001540 damages set lbrllt herein nre an adequate remedy for default and shall not be considered a penalty. Nothing contained herein shall preclude DOE from pursuing any other remedy against an obligor which may be available for the payment of moneys due including interest thereon in accordance with applicable statutes and regulations. Article VIII. Disputes Disputes arising under this Repayment Agreement shall be subject to the procedures set lbrth in I0 CFR 600.22 Disputes and Appeals. UNITED STATES DEPARTMENT OF ENERGY OBLIGOR (Kellogg1 Brown & Uoot, Inc.) Signature: - - - - - - - - - - = : - - - - Name: Date: Title: Contrncting Officer: Signature: - - - - - - - - - = - - - - Name: Date: Title: OBLIGOn (Soul hem Compnny Scniccs~) Signature: - - - - - - - - - - - - - Name: Date: Title: ,i ' s SoCo FOIA Response 001541 Dunlap, Ann C. From: Sent: To: Subject: Robbins, Brittley K. Friday, April 06, 2007 12:41 PM Russial, Thomas Fwd: RE: Revised Repayment Agreement bS »> Brittley Robbins 4/5/2007 11:42 AM »> Tom: Thanks, Brlttley >>> "Morrison, Jennifer B." < JENMORRI@southernco.com > 4/5/2007 10:22 AM >>> _,' • bS Brlttiey,I am working with Tim and Charles on matters related to Agreement Number DE·FC26-06NT42391, including the Repayment Agreement that is the subject of your e-mail below. Tim and I have reviewed the document that you sent and have just one question/concern. We wondered why this amended agreement did not reference the fact that it Is an amended version of the agreement. For the sake of clarity, we would like to suggest the addition of some clarifying language that documents and preserves the history of this contract. As you will see from the attached redllned version of the document, the new language that we are suggesting is minimal, but it memorializes the fact that there was a prior version or the agreement. Please note that It retains the same effective date (February 22, 2006) with respect to the parties rights and obligations. For consistency, we may want to consider using the phrase Amended and Restated Repayment Agreement throughout the document. You will also note that, In the attached version, I have made three changes of a grammatical nature: (i) a correction to the spelling of Affiliates on page 2 in the definition of Southern Company Services Affiliates; (ii) the insertion of Inc. after Southern Company Services in the signature block; and (Ill) modification of KBRs name to omit the comma (which Is how KBRs name appears on its incorporation documents). Please contact Tim or me if you have any comments or concerns regarding these matters. I would enjoy the opportunity to meet you over the telephone to discuss this and any other Items with you. Regards, Jennifer Jennifer B. Morrison Senior Attorney Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205·257-6730 (phone) 205-257-6381 (fax) lenmorri@southernco.com This e·mail and any of Its attachments may contain proprietary Information of Southern Company and/or Its affiliate that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e-mail is intended solely for the use of the Individual or entity for which It Is intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the SoCo FOIA Response 001542 contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or Its affiliates and is prohibited. If you are not the Intended recipient of this e·mall, please notify the sender Immediately by return e·mall and permanently delete the original and any copy or printout of this e·mail and any attachments. Thank you. From: Pinkston, Tim E. Sent: Wednesday, April 04, 2007 11:25 AM To: Morrison, Jennifer B. Subject: FW: Revised Repayment Agreement From: Brittley Robbins [mallto;Brittley.Robbins@NETL.DOE.GOV) Sent: Friday, March 30, 2007 3:32 PM To: chender@southernco.com ; Pinkston, Tim E. Cc: Madden, Diane Subject: Revised Repayment AgreementCharles and Timothy: I first want to introduce myself as the m!w Contract Specialist assigned to the "Demonstration of a 285MW Coal-based Transport Gasifier" project (DE-FC26-06NT42391). I have heard only good things about both of you and look forward to working with you. In response to a request from Tim, I have attached a copy of the revised Repayment Agreement. The following information has been revised: under Article IV, numbers were updated in paragraphs (1), (il), and (iii). Also, two grammatical changes were made: (1) the first paragraph was corrected to combine the two sentences Into one sentence, separated by a comma, and (2) under Article VI. A, the first sentence was corrected by removing the words "of the". Please feel free to contact me with any questions. I have prepared a no-cost time extension to revise the end date of Budget Period 1 to 04/30/2007. It should be mailed out on Monday but I can also fax you a copy If you would like. Thanks again, Brittley Robbins Contract Specialist, DOE-Nffi Acquisition and Assistance Division (412) 386·5430 2 SoCo FOIA Response 001543 Dunlap, Ann C. From: Sent: To: Subject: Attachments: "Rush, Randall E." Friday, April 13, 2007 5:29 PM Russial, Thomas Documents Required for Approval of BP 2 REDACTED Execution Version(b) (4) Cost Re-Alignment letter (4_13_2007) (2).pdf; DOE· SCS-KBR Repayment Agreement-- Amended and Restated (4-13-07).doc; SPC Board Resolution· signed (2).pd (b) (4)SCS MOA Amendment Two {4-13-07) (2).pdf (b) (4) Board.pdf Attached are the documents DOE requires for final approval to proceed to Budget Period 2. Diane Madden DOE Project Manager has been sent a password protected version. Since you are DOE Counsel I have sent you a version without passwords. (b) (4) (b) (4) The repayment agreement, the are the final versions, but are in the pro vide PDF copies of the fully executed documents by Tuesday of next week. Note that the (b) (4) has financial info redacted. You will probably want to call to discuss. I will be in (b) (4) y. The only change to the repayment agreement from the previous version is the name of KBR and language recognizing Kellogg Brown & Root LLC as having successor rights and obligations of Kellogg Brown & Root, Inc. Call me on my cell phone at • • • • • if you have questions. b6 Have a good weekend. (b) (4) (b) (4) <> Randall E. Rush Director, Power Systems Development Facility Southern Company Generation Highway 25 North P. 0. Box 1069 Wilsonville, AL 35186 *Internal:8-824-5842 *External:(205) 670-5842 *Cell: ( (b) (6) *Linc:( (b) (6) *Fax:(205) 670-5843 ) E-mail:rerush@southernco.com SoCo FOIA Response 001544 SoCo FOIA Response 001545 Mar 29 ,07 12:57p (b) (4) (b) (4) p.1 UNANIMOUS CONSENT OF DIRECTORS OF SOUTHERN POWER COMPANY TO ADOPTION OF ACTIONS AND RESOLUTIONS IN OF MI~ETING l l r.mr.r I i I .. ~ The undersigned, being all of the members of the Board of Directors of Southern Power Company, n Delaware corporation (the "Company''), by written consent pursuant to the General Corporation Law of Delaware, do hereby adopt as of March 29, 2007, the following resolutions: RESOLVED: That the continuation of the design, engineering and construction of the Gasification Island Project is hereby approved, subject to approval by the Orlando Utilities Commission of amendments to existing agreements and approval by the United States Department of Energy (the "DOE") of additional funding for the Gasification Island Project; RESOLVED FURTHER: That the officers of the Compnny and the officers of Southern Company Services, Inc., acting as agent for rhe Company, are hereby authorized, in their discretion. to execute amendments, substantially consistent wHh such documents presented at the meeting of the Company's Board of Directors on March 26, 2007, to the following agreements: • • • Orlando Gasification Project Constmction and Ownership Participation Agree~nent. Gasification Island Capacity Purchase Agreement and DOE Cooperative Agreement~ ReSOLVED FURTHER: That the officers are hereby authorizt::d to execute any other agreements, amendments, guaranties, insu-uments and/or regulatory applications to corry out the intent of the foregoing resolutions and any and all actions of the officers prior to dte date hereof relative to the Gasification Island Project are hereby ratified, confinned. and approved. use or disclosure or data on this sheet is sub]eclto the restrlcl!on on the title page of the BP 2 continuation Application lor Cooperative Agteement No. OE-FC·08NT42391. SoCo FOIA Response 001546 Mar 29.07 12:57p (b) (4) (b) (4) p.2 RESOLVED FURTHER: That tl1e total expenditures for capital additions and improvements for the years 2007-2009 approved by the Board of Directol'S of the Company on February 28, 2007 are hereby revised as follows; 2007 - $257.8 million 2008-$537.1 million 2009 - $865.0 million RESOLVED FURTHER: That the officers are hereby authorized and directed to consider, the forecast figures when planning the financial needs of the Company, to announce to the public such forecast figures when information will benefit the public or when required by law and to take such other actions concerning forecast figures which legal counsel advises are appropriate; and RESOLVED FURTI-lER: That the officers arc hereby authorized to reaflocate expenditw-es, within the limits of the approved b\tdgel for capital additions and improvements, to address changes in priorities due to competitive needs or forecast changes, us they deem appropriate. rN WlTNESS WHEREOF, the undersigned have hereunto set their hands as rs of he corporation effective as of the day and year fu·st above wl'itten. o.-JL~ W. Paul Bowers Thomas A. Fatming G. Edison Holland, Jr. David M. Ratcliffe use or disclosure or data on this sheet ts sub)ectto the restrictlon on the t~le page of lhe BP 2 Continuation Application !Of Cooperative Agreement No DE-FC-06NT4239 f · SoCo FOIA Response 001547 UNANIMOUS CONSEN'J' OF DIRECTORS OF SOUTHERN POWER COMPANY TO ADOPTION OF ACTIONS AND RESOLUTIONS IN LIEU OF MEETING .-' The undersigned, being all of the members of the Board of Directors of Southern i; Power Company, a Delaware corporation (the "Company''), by written consent pursuant lo the General Corporation Lnw of Delaware, do hereby adopt as of March 29, 2007, the following resolutions: RESOLVBD: That the continuation of the design, engineering and construction of the Gasification Island Project is hereby approved, subject to approval by the Or1audo Utilities Commission of ameudme.nts to existing agreements and a.pprovall>y the United States Deparunent of Energy (the "DOE") of additional funding for the Gasification bland Project; RESOLVED FURTIJER: That the officers of the Company and the officers o( Southern Company Services, Inc., acting as agent for the Company, are hereby authorized, in their discretion, to execute amendments, substantially consistent with such documents presented at the meeting of the Company's Board of Directors on March 26,2007, to the following agrC'.ements: • • • Orlando Gasification Project Construction and Ownership Participation Agreement, Gasification Island Capacity Purchase Agreement and DOE Cooperative Agt"eement; RESOLVED FURTHER: That the officers are hereby authorized to execute any other agreements, amendments, guaranties, instrumentS and/or regulatory applications ro carry out the intent of the foregoing resolutions and any and all actions of the officers prior to the date hereof relative to the Gasification Island Project are hereby rarified, confirmed aud approved. Use ar disclosure or data on lhls sheet Is subject to the restriction on the title page ollhe BP 2 Continuation Application for Cooperative Agreement No. DE·FC·OONT-42391. 10 . d SoCo FOIA Response 001548 RESOLVED FURTHER: That the total expenditures for capital additions and improvements for the years 2007-2009 approved by the Board of Directors of the Company on Febmary 28. 2007 are hereby revised as follows; 2007- $?.57.8 million r I 2008-$537.1 million 2009 - $865.0 million RESOLVED FURTllER: That the officers are hereby authorized and directed to consider, the forecast figures when planning the financial needs of the Company, to announce to the public such forecast figures when infonnation will benefit the public or when required by Jaw and to take such other actions concerning forecast figures which legal counsel advises are appropriate; and RESOLVED FURTHER: That the ofticcrs arc hereby aulhorized to reallocate expenditures, within the limits of the approved bndget for capital additions and improvements, to address changes in priorities due to competitive needs or forecast changes, as they deem appropriate. IN WITNESS WHEREOF, the undersigned have hereunto set their hands as Directors of the corpOration effective as of the day and year first above written. W. Paul Bowers Tboroas A. Fanning Use or disclosure or data on this sheet Is subject to the restricllon on the IItie page ol the BP 2 Conllnuatfon Application for Cooperative Agreement No. DE-FC-06NT423g1 20 'd SoCo FOIA Response 001549 HAR,29 '2007 11:46 4 0' 506 0394 SOUTHERN CO./TO:·I FANIH!fC #t947 l'.OOl/002 UNANIMOUS CONSENT OF DlRECfORS OF SOUTHERN POWER COMPANY TO ADOPTION OF ACTIONS AND .RESOLUTION5 IN LmU OF MEETJ.NG The undersigned, bcJng all of tho members of the Board of Directors of Southern Power Company, a Delaware corpora lion (the "Company"), by written consent pursuant to the Geneml Corporofjon Law of Delaware, do hereby adopt as of MH{ch 29, 2007, the following resolutions; Rr~OLVEJJ: That the continuation of the design, engineedng und. construction ofU1e Gasification Island Project is hereby approved, subject t.o app.cova.l by tbe Orlando Utilities Commission of amendmen~ to e:'Cisting agreerneots and approval by the United States Department of Energy (fllc ''DOE") of additional funding for the Gasification Island Project; RESOLVED FURTiiER: That the officers of the Compooy and the officers ofSoutJu~m Company Servfces, Inc., acting as Rgent for the C9mpany. arc hereby autbori7.ed, in their discretion, to eKccute amendments, substantially consistent with such docwnents presented at the meeting offlte Company•s Board.ofDircctors on March 26, 2007, lo the following agreements; • • • Odando Gasification Project Construction Md Ownersbjp Participation Agreement, Gasification Islnnd Capacity Purchase Agreement and DOE CooperatJve Agreement; RESOLVED FUR1lJER: That the officers are hereby authorized to execute any other agreements, amendments, gullllUlties, instrwnents and/or regulatory applications t() carry out the Intent of the foregoing r.esolutfons and any and all actlons of t11e offic~ prior to the date hereof relative to dtc Gosificationlslan.d Project are hereby mtificd, confl.ll.Oc:d and approv~d. Use or disclosure or data on lhis sheet Is subject to the restriction on the title page ol the BP 2 Continuation Application for Cooperative Agreement No. DE·FC·06NT4239t. SoCo FOIA Response 001550 MltR.•29'2007 11:46 40•1 506 039-1 SOUTHERN CO./T0l1 FTINNING !1(847 r.oouoo2 RESOLVED FURTHER: TI1at rhe total expenrutures for capital additions au.d improvements for the years 2007-2009 approved by the Board ofDirector.s of the Company on February 28, 2007 ore hen;;by revised as follows; 2007 - $257.8 million 2008 - $53 7.1 roillion 2009-$865.0 million RESOT...VED FURTI1ER: That the officers arc hereby authori7..ed and directed to consider, the forecast figures when plnnning the financial needs of the Company, to annom1ce to the public such forecast figUJ'es when information will benefit the public or when required by lnw IUJd to take such other actions conCCJning forecast figwes which legal counsel advises are appropriate; and RESOLVED FURTHER: That f.he officers ore hereby authorized to reallocate expenditures, wit11in the limits of the approved budget for capital additions and. improvements, to address changes in priorities due to competitive needs or forecast changes, as they deem appropriate. IN WJ.TNESS WHEREOF, the 1mdersigned have hereunto set their hands os Directors of the:: CQrporation effective as of the day and year first above written. W. Paul Bowers ~~~ G. Edison Holland, Jr. David M. Ratcliffe Thomas A. Fanning · Use or disclosure of data on lhis sheet Is subject to the restriction on the title page of the BP 2 Continualion Application for Cooperative Agreement No. DE·FC-06NT42391. SoCo FOIA Response 001551 ATTACHMENT D AMENDED AND RESTATED HF.PAVMENT AGl~F.EMENT DE-Fn26-D6NT42392 This Amended and Restated Repayment Agreement b)' and between the United States Depnrtment of Energy (DOE), Southern Company Services, Inc. (SCS), and Kellogg Brown & Root LLC (successor to the rights and obligations of Kellogg Brown & Root, Inc.) is made and entered into ns of April __, 2007. This Amended and Restated Repayment Agreement supersedes and replaces the Repayment Agreement entered into on february 22, 2006. This Amended and Restated Repayment Agreement ratifies nnd confirms the rights and obligations of the parties - as amended herein - which became effective on February 22, 2006. In consideration of the United States Department of Energy (DOE) support for a clean coal technology Demonstration Project under the DOE's Clean Coal Power Initiative, for which SCS and KBR, both being defined herein as an "Obligor," acknowledge that the)' will receive substautial benefit, the Obligors hereby agree to repay the Department of Energy in accordance with the terms and conditions set forth below. Al"ticlc I. General Objective The purpose of this Repayment Agreement is to set forth the conditions under which the Obligors shall repay to DOE nn amount up to, but not to exceed, the DOE share paid under Coopenttive Agreement Number DE-FC26· 06NT42391, such obligntion being the direct responsibility of each Obligor and being for the direct benefit of DOE, as nccomplished via and upon the terms set forth herein. (b) (4) Article II. Delinitions "Cooperative Agreement" means the financial assistance award made by the United States Deportment of Energy (DOE) to SCS, Instrument Number DE-FC26·06NT42391 on January 30, 2006, and subsequent amendments. "DOE Share" means the portion of the total Jlroject costs paid by DOE under the Cooperative Agreement. "Obligor" means the organizations that nrc responsible for repayment under this Repn)•mcnt Agreement, SCS and KBR, as stated above. ''Obligor" includes these organizations' successors and assigns. "Repayment Period" means the period of time during which 11 transaction becomes subject to repayment under this Repayment Agreement. "Total Project Costs" means the total amount of allowable direct and indirect costs incurred nnd paid, in pa11, by DOE under Cooperative Agreement. "Demonstration Technology" shall mean the transport reactor-based gasification/IGCC technology which is proposed for demonstration under the Cooperative Agreement, including all past, current, and future infonnntion and intellectual property developed by, on behalf of, or together by, SCS or KBR. as Obligors, and their respective affiliates, present and future, that enhances or improves the perfomtancc of the transport reactor in its npplicntion as a coni gnsi ficr for the production of raw synthesis gas which subsequently may be further processed to produce electricity (and/or steam), chemicals, or fuels. "Demonstration Project" shnll mean the Integrated G11sificntion Combined Cycle (IGCC) power plant project being undertaken by SCS and DOE under the Cooperative Agreement Number DE-FC26-06NT42391 . "Southern Company Services Affiliates" shall menn any subsidiary of, und under common control of. their single parent, The Southem Company, whether a first tier subsidiary of The Southern Company or any lower tier subsidiary of the first tier subsidiary. SoCo FOIA Response 001552 Al'ticle Ill. Repnyment Period The Rcpnyment Period shall begin on the date of the first sale of the Demonstration Technology or on 1he date specified in the Cooperative Agreement for the end of the Demonstrntion Period, whichever occurs first. However, if SCS withdraws or tenninates its participation under the Cooperati\•e Agreement, or if the project is terminated in nccordnnce with Pamgrnph 2.3•1 (Termination) of the Cooperative Agreement or terminated due to DOE's disapprovnl of 11 continuation npplicntion in accordance with Parngraph 2.11 (Continuntion Application) of the Cooperative Agreement, this Repayment Period shnll begin on the date the Cooperntive Agreement is terminated. The Repayment Period shall expire 20 years aller the date the Repayment Period begins. Obligors' obligation to repay DOE expires on the date the clllire DOE shore hns been re1>aid, or the date on which repayments for all transactions entered into during the Repnyment Period have been mnde, whichever occurs first. This Repayment Agreement may be terminated upon a delenninnlion by the Secretary of Energy, or designee, that repayment places an Obligor at a competitive disadvantage in domestic or intcrnntionnlmnrkets. Al'ticle IV. Basis for Rcr>!l)'lllent Though collection of payment to DOE by the Obligors shall be cumulative and consolidated into single payments submitled by SCS to DOE, each Obligor is individually responsible to DOE for nmounts due to DOE !Tom the Obligor. DOE shall haven direct claim ngninst 1111 Obligor for breach of the terms of this Repayment Agreement by the Obligor. The obligations of either Obligor under this Repayment Agreement shall survive the expirntion, termination, transfer, assignment, nov!ltion, sale, merger, consolidation, or other change in control or, an Obligor until the expiration of the repayment obligation to DOE. The annual nmounl of repayment to DOE by the Obligors is to be comprised of the cumulative effect of the provisions in Article IV (i), (ii), and (iii): (i) KBR shall pay to SCS, for transfer by SCS to DOE, an amount equal Ia (b) (4)of the license fees and/or royalties actually retained by KBR from licensing of the Demonstrntion Technology to third-pnrty users for the production of electricity (andfor steam), chemicals, or fuels, after satisfYing guaranty or warranty responsibilities. Distributions made by KBR to SCS are considered to be included in the amount actually retained by KBR. In the c\•entthat KBR does not charge a license fcc ton third party for nny instnllation of the Demonstration Technology, KBR will be deemed to have incun·ed a license fee in nn amount equivalent to the license fee on the most recent prior project of substantially similar scope utilizing the Demonstration Technology and in the pro rata amount of the size of such installation. If no prior license has been granted, the nmount due to DOE shall be cnlculntcd at (or equivalent) of installed capacity. KBR shall not be responsible for such fee if SCS (b) (4) and KDR have mutually determined nnd explicitly documented that the market for thai project will not bear this license fcc. SCS agrees thnt it shnll not 11ccept any compensation in lieu of roy!!lties due from KBR under the (b) (4) In the event that SCS sells directly to third pnrtics, SCS shall pay directly to DOE (b) (4) of the license fees andfor royalties actually retained by SCS from licensing of the Demonstrnlion Technology to third-party users for the production of electricity (andfor steam), chemicals, or fuels, nllcr sat is tying guarantee or wan·nnty responsibilities. In the event that SCS does not charge n license fee to a third pa11y for any installation of the Demonstration Technology, SCS will be deemed to have incurred a license fee in the nmount equivalent to the license fcc on the most recent prior project of substantially similar scope and in the pro mta amount of the size of the instnllntion. If no prior license has been granted, the amount due to DOE shall be calculated nt (b) (4) (or equivalent} of installed capacity. A transaction shall be subject to repayment under this provision if on Obligor enters into n license or contract for sale during the Repayment Period notwithstanding that repayment may occur after the Repayment Period. ReJ>ayment shall accrue aller satisfYing guaronty or warranty responsibililies. (ii) For any commercial application of the Demonstration Technology by SCS, or SCS alliliatcs, for the production of electricity (and/or steam), excluding this Demonstration Project, SCS agrees to pay to DOE a one lime fee of (b) (4) of initial, actual tested perfonnance for each commcrcinlapplication. Such payment to DOE shall be prorated by SCS', or SCS affiliates', initial percentage of ownership of such facility. An 2 SoCo FOIA Response 001553 installalion shall be subject to repayment under this provision if SCS, or SCS affiliates, breaks ground for the installation during the Rcl>aymcnt Period, notwithstanding that repayment may occur nlicr the Repayment Period. Repayment shall nccnte upon the declaration of commercial operation. For any commercial application of the Demonstmtion Technology by SCS, or SCS aOilintes, for the (iii) production of chemicals and fuels, excluding this Demonstration Project, SCS agrees to pay DOE a one time fee of (b) (4) for each cotmnercial application. Such payment to DOE shall be promted by SCS, or SCS affiliates, initial percentage ownership of such facility. An installation shall be subject to repayment under this provision if SCS, or SCS afliliates, breaks ground for the instnllalion during the Repayment Period, notwithstanding that rep11yment may occur after the Repayment Period. Repayment shall accrue upon the declamtion of commercial operation. At·llclc V. Schedule for Repayment Pa)•ments to DOE by SCS of the cumulative amounts required for the period shall be due within 60 days alier each one-year period following the start of the Repayment Period for Repayment Agreement DE-FR26·06NT42392. Checks shall be made out to the US Depat1ment of Encrg)' and be mailed to the Financial Management Division, USOOE, NETI., Post Office Box 10940,626 Cochmns Mill Road, Pittsburgh, Pennsylvania 15236-0940. Article VI. Reporting and Record Retention Requirements (A) Annual Report to DOE Within 60 days after the end of each one year period, the Obligors shall prepare n consolidated re1>0rt and SCS shall submit such report to DOE which, for the one year period just elapsed, provides the applicable dnta described below: (I) The total dollar amount of repayment nccnting to DOE. (2) A description of each transaction from which the repayment obligation accrued. (3)The total amount paid to DOE for nil years and the amount of the DOE share remaining to be paid in succeeding yeurs under this Repayment Agreement. Notwithstanding that SCS will submit the Annual Report to DOE, the responsibility for submittal of information to prepare the report, nnd the responsibility of (>reparation of the re(lOrt, falls equally on the Obligors. DOE shall haven direct claim against either Obligor for failure to comply with the t·cquirements of this clause. (13) Conuncrcinlization Rcnprt For a period of five (5) years after completion of the Demonstration Project, the Obligors shall be equally responsible for submitting a Commercialization Report describing the Obligors' progress and success in commercializing the technology used during the project us well ns technology derived from that used during the project. The I>UI"JlOse of the Commercialization Report is to assist DOE to detennine the benefits obt11incd from Government support of technology development. The Commercialization Report is independent from the Annual Report required by the Repayment Agreement and is not limited to the sale or licensing of "Demonstration Technology" ns that tenn is defined in this Repayment Agreement. The Commcrcializntion Report shall include a discussion of the Obligors' efforts to commercialize the technology. The Commercialization Re1>ort shall also include descriptions and locations (or proposed locations) of all significunt technology embodied in the Demonstration Project, or derived from technology embodied in the Demonstration Project, that was sold or licensed during the preceding year (whether or not such tmnsactions were subject to repayment under the tenns of the Repayment Agreement). The Commercializntion Report shall also include a discussion of nny impediments to the commerciali?.ation of the technology. It is understood and agreed by DOE thnt the Commerciali?.ation Re1>0rt shall be in a level of detail that is not required to contain Limited Rights Data or Protected Datn as defined in the Cooperative Agreement, recognizing that the commercialization efforts in volvc proprietary nnd confidential business information which will necessarily be accorded secrecy treatment. The Commercialization Report shall be due on December 31 of each year. DOE shall look to each Obligor for compliance with its oppl icable portion 3 SoCo FOIA Response 001554 of the requirements of this clause and obtain performance directly from the responsible Obligor. (C) Period of Retention With respect to each annual report to DOE, the Obligors shall retain, for the period of time prescribed in this paragraph, all related financial records, suppot1ing documents, statistical records, and any other records the Obligors reasonably consider to be JJcrtinent to this Repayment Agreement. The period of required retention shall be from the date each such record is created or received by nn Obligor until three years after one of the following dates, whichever is earlier: the dnte the related annual report is received by DOE, the date this Repayment Agreement expires, or the date finn I payment to DOE is received. If any claim, litigation, negotiation, investigation, audit, or other action involving the records starts before the expiration of the three-year retention period, the Obligors shall retain the records until such nction is COilll)leted and all related issues nrc resolved, or until the end of the three-year retention period, whichever is later. The Obligors shall not be required to retain any records, which have been transmitted to DOE by nn Obligor. (D) Authorized Copies Copies made by microfilm, photocopying, or· similar methods may be substituted for original records. Records origiunlly created by computer may be retained on an electronic medium, provided such medium is "rend only" or is protected in such n manner that the electronic record can be authemicated as an originnl record. (E) Access to Records DOE and the Comptroller Gcncrnl of the United Stoles, or nny of their nuthorizcd representatives, shall have the right of access to any books, documents, papers, or other records (including those on electronic media) which are pet1inent to this Repayment Agreement. The purpose of such access is limited to the making of nudits, e;>;aminations, excerpts, nnd tmnscripts. The right of access described in this paragraph shall lost as long as an Obligor retains records, which are pertinent to this Repayment Agreement. (F) Restrictions 011 Public Disclosure The Fedeml Freedom of Information Act (S U.S.C. Section 552) docs not npply to records nn Obligor is required to retain by the terms of this Repayment Agreement. Unless otherwise required by law or a court of competent jurisdiction, an Obligor shall not be required to disclose such records to the public. (G) Flow Down of Records. Retention, and Access Requirements Obligors shall include clauses substantially similar to the record retention and nccess requirements set forth in sections (C) and (E) of this Article in all agreements w!ten necessary to fulfill the Obligors' obligntions under this Repayment Agreement. Article VII. Default If either Obligor is responsible for the f.1ilure of SCS to make payment within the time specified in Article V, or is responsible for SCS' failure to submit the nnnual report within the time specified in Article VI, the Obligor which is in default of its own obligations under this Repayment Agreement and fails to cure the default within 30 days after receipt of written notice of the default from DOE, notwithstanding any provision of the Cooperative Agreement, its flow down provisions, or this Repayment Agreement to the contrary, thnt Obligor shall pay to DOE the amount of S I00.00 per day for every business day that the payment or report is delayed due to the f.1ult of that Obligor. Obligors ami DOE agree that such amount represents DOE's reasonable costs and acknowledge that the liquidnted damages set forth herein are an adequate remedy for def.1ult and shall not be considered a penalty. Nothing contained herein shall preclude DOE from pursuing nny other remedy against an obligor which may be available for the payment of moneys due including interest thereon in accordance with applicable statutes and regulations. 4 SoCo FOIA Response 001555 A•·ticlc VUJ. Disputes Disputes arising under this Repayment Agreement shall be subject to the procedures set forth in I 0 CFR 600.22 Disputes and Appeals. OULIGOR (Kellogg llrown & Root LLC (ns succcsso•· to the rights nnd obllgnllons or l Tuesday, Aprill7, 2007 11:15 AM Ferlic, Andrew J.; Stolzenberg, Merle P. Robbins, Brittley K. Fwd: OGP - Proposed Revision to KBR Contracting on the Orlando Project Merle and Andy I would like to assign this to you jointly - see e-mail below. Merle, I know you have provided the earlier reviews on this action and are very familiar with SCS and their accounting • system. Andy, I know you have extensive experience and knowledge with regard to the need for audits etc. and consistency In accounting systems. On this basis I would like the two of you lo confer on this situation and provide guidance to Brittley. Please note she Is looking for a reply in an expeditious manner If at all possible. Please keep her Informed of your activities. debra >>> Brlttley Robbins 4/17/2007 8:13AM >>> Deb, Can you please assign a cost/price analyst to review SCS's proposed plan of action, below? Thank you, Brittley Robbins Contract Specialist, DOE-NETL Acquisition and Assistance Division (412) 386-5430 >>>"Henderson, Charles W." 4/16/2007 7:13PM>>> (b) (4) SoCo FOIA Response 001569 (b) (4) Should you have additional questions or need more Information please call Randall Rush (b) (6) ) or me { (b) (6) Sincerely, > Charles Henderson > Admin & Project Support Manager > Power Systems Development Facility > 8-824-5844 >(b) (6) > > > 2 SoCo FOIA Response 001570 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Importance: Madden, Diane R. Wednesday, April 25, 2007 10:52 AM Russial, Thomas (b) (4) Agreement letter for your review and concurrence Marked up to show changes (b) (4) letter (4_13_2007).pdf; Signature Pages from (b) (b) (4) Letter Agreement.pdf; letter Agreement - FINAL- REDACTED.pdf (4) High THANKS II! Diane bS SoCo FOIA Response 001571 PR OPRIETA RI’ A ND CONFIDENTL4 L TRADE SECRET INFORMiI TION (b) (4) Use or disclosure of damon this sheet is subject to the restriction on the title page of the RP 2 Continuation Application for Cooperative Agreement No. DE-FC26-OGN 142391. SoCo FOIA Response 001572 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFOR1UATION (b) (4) 2 Use or disclosure of data on this sheet is subject to the restriction on the title page of the BP 2 Continuation Application for Cooperative Agreement No. DE-FC26-06NT42391 . SoCo FOIA Response 001573 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) 3 Usc or disclosure of data on this sheet is subject to the restriction on the title page oft he BP 2 Continuation Application tbr Cooperative Agreement No. DE-FC26·06NT42391. SoCo FOIA Response 001574 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) 4 Use or disclosure of datn on this sheet is subject to the restriction on the title page of the BP 2 Continuation Application for Coopemtive Agreement No. DE-FC26·06NT42391. SoCo FOIA Response 001575 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) s Use or disclosure of data on this sheet is subject to the restriction on the title page of the BP 2 Continuation Application for Cooperative Agreement No. DE·FC26·06NT42391. SoCo FOIA Response 001576 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) 6 Use or disclosure of data on this sheet is subject to the restriction on the title page of the BP 2 Continuation Application for Cooperative Agreement No. DE-FC26-06NT42391 . SoCo FOIA Response 001577 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) 7 Use or disclosure of data on this sheet is subject to the restriction on the title page ofthe BP 2 Continuation Application for Cooperative Agreement No. DE-FC26-06NT42391 . SoCo FOIA Response 001578 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) 8 Use or disclosure of data on this sheet is subject to the restriction on the title page of the BP 2 Continuation Application for Cooperative Agreement No. DE-FC26·06NT42391 . SoCo FOIA Response 001579 PROPRIETARY ANb CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) 9 Usc or disclosure of data on this sheet is subject to the restriction on the title page of the BP 2 Continuation Application for Cooperative Agreement No. DE-FC26-06NT42391. SoCo FOIA Response 001580 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) 10 Use or disclosure of data on this sheet is subject to the restriction on the title page of the BP 2 Continuation Application for Cooperative Agreement No. DE-FC26-06NT42391. SoCo FOIA Response 001581 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION Exhibit A REDACTED Exhibit B REDACTED Exhibit C REDACTED Exhibit D REDACTED D-1 Use or disclosure of data on this sheet is subject to the restriction on the title page ofthc BP 2 Continuation Application for Cooperative Agreement No. DE-rC26-06NT42391 . SoCo FOIA Response 001582 EXECUTlON VERSION (b) (4) Use or disclosure of data on Chis sheet Is subject to the restclctlon on the Ulle page of the BP2 Continuation Application for Cooperat.ve Agreement No. DE-FC26·06NT42391. SoCo FOIA Response 001583 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure of dala on this sheet Is subject lo lhe restriction on the title page of tho BP2 Conllnvotlon Application tor Cooperative Agreement No DE-FC26·06NT42391. 2 SoCo FOIA Response 001584 PROPRIETARl' AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure of data on Ihis sheet Is subject to the restriction on the ~lie page of lhe BP2 Continuation Applicalion for Cooperative Agreement No OE-FC26·08NT42:191. 3 SoCo FOIA Response 001585 PROPRIETARY AND CONFIDENTIAl. TRADE SECRET INFORMATION (b) (4) Use or disclosure of data on this sheells subject to lhe restriction on the tiUe page of the BP2 Conlinuatlon Application for Cooperative Agreement No. DE·FC26·06NT42391. 4 SoCo FOIA Response 001586 PROPRIETARJ' AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disdosure of !lata on this sheet Is subject to the restriction on the IItie pBge of the BP2 Continuation AppHcalion for Cooperative Agreement No DE-FC20·06NT42391. 5 SoCo FOIA Response 001587 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure of daia on this sheei is subject to the restricllon on lhe tiUe paoe of the BP2 Conlf~alion Applicallon for Cooperative Agreement No. DE·FC26·06NTo42391. 6 SoCo FOIA Response 001588 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure of data on this sheet is subject to the re&trictlon on the title page of the BP2 Conttnuallon AppUcal!on for Cooperative Agreement No. DE·FC26·06NT42391. 7 SoCo FOIA Response 001589 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure or data on this sheet is subject to the restriction on lhe Iitle page of the BP2 Conlinualion Appllcallon lor Cooperative Agreement No. OE-FC26·06NT42391 . 8 SoCo FOIA Response 001590 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure of dala on lhls sheet Is subject to lhe reslllcllon on the lille page ol lhe BP2 Conllnuallon Application lor Cooperative Agreement No. Oe-FC26·06NT42391. 9 SoCo FOIA Response 001591 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure of dala on this sheet Is subject to lhe reslrfcllon on the lllle page of the BP2 Conllnuation Application lor Cooperative Agreement No. DE·FC26·08NT42391. 10 SoCo FOIA Response 001592 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure of data on this sheetts subject to the restrielion on the title page of the BP2 Continuation AppiJcntion for Cooperative Agfeemcnt No. DE-FC26·06NT42391. II SoCo FOIA Response 001593 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the lllte page of the BP2 Continuation Application for Cooperative Agreement No. DE-FCZ6·06NT42391. 12 SoCo FOIA Response 001594 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION Exhibit A REDACTED Exhibit B REDACTED Exhibit C REDACTED 0-1 SoCo FOIA Response 001595 PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION Exhibit D (b) (4) SoCo FOIA Response 001596 PROPRIE TA 1?11 ND CONFIDENTIAL TRA DE ECRE INF TIGN D-3 SoCo FOIA Response 001597 PR YA ND CONFIDENTM TIMDE SECRET INFORMA WON D-rl SoCo FOIA Response 001598 CONFIDENTIAL TRADE. SECRET INFORMA WON [1-5 SoCo FOIA Response 001599 PR YAND CONFIDENTIAL TEA DE SECRET INFORMA TION D-G SoCo FOIA Response 001600 PROPIHE TAR 1? AND CONFIDENTIAL TEA DE SECRET INFORMA WON DJ SoCo FOIA Response 001601 PROPRIE TA YAND CONFIDENTIAL TRADE SECRET MA WON SoCo FOIA Response 001602 PHONE IE TAR CONFIDENTM I. TEA HE 1'3le INFORMA TIGN D-9 SoCo FOIA Response 001603 PROPRIETAR 1' AND CONFIDENTIAL TRA DE SECRET INFORMA TIDN D-IO SoCo FOIA Response 001604 PROPRIETAR PAND CDNFIDENTIAL TEA DE SECRET INFUMM WON SoCo FOIA Response 001605 From (b) (4) 04/24/2007 13:17 #053 P.002/003 PROPIUBTARY AND CONFIDENTIAL TRADE SECllET INFORMATION (b) (4) 10 Use or disclosure ol data on lhls sheells subjectlo lhe restriction on lhe title page of lhe BP2 ConUnuallon Application for Cooperative Agreement No. DE-FC20-00NT42391. SoCo FOIA Response 001606 From: (b) (4) 04/24/2007 13: 17 #053 P.003/COO PROPRIETARY AND CONFIDENTIAL TRADE SECRET INFORMATION (b) (4) ll Use or di&closure of data on this sheet is subject to the resltlcllon on the IItle page of the BP2 Conlinualion Application for Cooperative Agreement No. DE-FC26·06NT42391. SoCo FOIA Response 001607 Dunlap, Ann C. From: Robbins, Brittley K. Thursday, December 06, 2007 8:31 AM Russial, Thomas Ferlic, Andrew J.; Madden, Diane R.; Zysk, Joann C. (CONTR); Stolzenberg, Merle P. Fwd: Gasirier Subcontractor Costs Formal Letter of Claim-2.pdf; 5Dec2007.doc Sent: To: Cc: Subject: Attachments: Diane, JoAnn, Merle, and Andy: Southern sent me(b) (4)dalm letter after our call yesterday. It Is attached. Also attached are my notes from the conference call. Feel free to edit as necessary and correct me If I misinterpreted >>>"Morrison, Jennifer B." 12/5/2007 11:36 AM>>> Brittley, Diane and Merle, (b) (4) In anticipation of our conference call today, here Is a brief summary of the main components subcontract for the Orlando Project and the entity selected to perform the work for this aspect of the Project. This e-mail (and our call) Is intended to present you with the situation that we are facing with regard to one of our subcontractors and to seek your guidance on how we should respond. The(b) (4) was solely for use in the(b) (4) portion of the Project and would not be part of the(b) (4), (b) (6) of the Project. Thus, for this Item of equipment, there would be no sharing of costs between the (b) (4) (b) (4) portion of the Project (b) (4) portion of the Project and the(b) (4) was the entity selected for the(b) (4) subcontractor, pursuant to a competitive bid solicitation.(b) (4) was the only bidder to respond with a complete and technically acceptable bid (b) (4) Is a small contractor located In (b) (4) (b) (4) SCS has worked with this subcontractor on a different Government project In the past, and that working relationship was a very positive one. At the time of cancellation, progress on the(b) (4) was about one-fourth of the way along. Design work and engineering were complete; fabrication had begun In August and would continue through August 2008. (b) (4) (b) (4) Below are the categories of costs tha The total cost for the completed was approximately claiming as a result of the cancellation: Material (b) (4) (b) (4) Is proposes to charge SCS for the materials listed below: All of these have been welded out and a number of them have been welded (b) (4) has received(b) (4) SoCo FOIA Response 001608 together. . (b) (4) has received ail (b) * All(b) (4) formed (b) (4) (4) (b) (4) has received (b) (4) has received has received has Incurred the costs for (b) (4) (b) (4) (b) (4) *NOTE - There Is a question as to how to dispose of the materials that have not yet been received by(b) *NOTE (b) (4) will offer SCS a credit to take possession of all materials. Material Handling Fee (b) (4) proposes to charge SCS a materials handling fee on (4) (b) (4) (b) (4) (b) (4) (b) (4) Specialty Equipment proposes to charge SCS for of some specialty equipment that purchased to design and fabricate the gasifier. Labor- Shop labor and engineering management will be charged at a rate of respectively. This rate covers direct labor costs and shop-related overheads. (b) (4) Profit (b) (4)per hour and (b) (4) per hour, s seeking a profit on Incurred costs. (b) (4) loss of Additional Work and Potential Profit Is claiming that It Is entitled to some costs for foregone work opportunities. (b) (4) (b) (4) (b) (4) Amounts already paid to In June, SCS was Invoiced for of the total contract value for placement of orders for the materials (b) (4) , and SCS paid the full amount of that invoice. In September, SCS was invoiced and paid (b) (4)of the total contract value for(b) (4) submittal of engineering drawings, and scs paid the full amount of that invoice. SCS Invoiced DOE for these amounts. Questions - Some of our questions are as follows: (b) (4) What Is the proper disposition of the property (materials) that has already received? (b) (4) What Is the proper disposition of the property (materials) that has not received and that Is located In ? Is any portion of the foregoing costs unallowable? (b) (4) Does any additional supporting documentation need to be obtained from other than the typical documentation that Is obtained from subcontractors for Invoicing purposes? Thank you very much for helping us to determine the correct approach in this situation. We appreciate your flexibility and ability to discuss this matter with us on such short notice. Jennifer (b) Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (6) (cell) 205-257-6381 (fax) jenmorri@soulhernco.com This e-mail and any of its attachments may contain proprietary Information of Southern Company and/or Its affiliate that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e·maU is Intended solely for the use of the Individual or entity for which it is Intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this email is contrary to the rights of Southern Company and/or Its affiliates and Is prohibited. If you are not the Intended 2 SoCo FOIA Response 001609 recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 3 SoCo FOIA Response 001610 SoCo FOIA Response 001611 SoCo FOIA Response 001612 SoCo FOIA Response 001613 14 Conference Call - 12/5/2007 Award: DE-FC26-06NT42391 Southern Company Services Award Title: "Demonstration of a 285MW Coal-based Transport Gasifier'' Participants: DOE- Diane Madden (DOE Project Manager), Brittley Robbins (Contract Specialist), Merle Stolzenberg (Cost Price Analyst), Andy Ferlic (Cost Price Analyst) and JoAnn Zysk (Contracting Officer); Southern Companv Services- Jennifer Morrison (Legal Counsel), Terry Carter (Contract Specialist), Tim Pinkston (Project Manager), Richard Harbuckle, Jennifer Cox, Rob(???), and Charles Henderson (Business Officer). Issue: Southern Company Services, Inc. has requested that DOE provide guidance on settling costs associated with terminating one of their subcontracts, which was terminated because of the cancellation of work at the Orlando site. (Reference email from Southern Company dated December 5, 2007). A brief synopsis of the materials and subcontractor in question follows: The (b) (4) (b) (4) Discussion: Southern Company Services (SCS) has confirmed that none of the materials in question can be used on the new project. (b) (4) (b) (4) (DOE has shared in these costs). (b) (4) (b) (4) The question was raised as to whether or not there was a termination clause in SCS's subcontract with(b) (4) SCS slated that they do not have a subcontract with(b) (4) only a letter of intent. A termination for convenience clause is contained within the Draft subcontract and SCS is using this as the basis for their arguments. The termination for convenience clause basically reads that SCS will pay the supplier for casts incurred up to the termination. This will include materials, labor and associated overhead. (b) (4) has offered to subtract the salvage value of materials that can be returned. In some cases the credit that is being offered is higher than salvage value.(b) (4) has said that for some of the materials they can use the items elsewhere and will offer a credit to SCS for the appropriate amount. Andy questioned how SCS was going to determine whether or not the credit amount was reasonable. SCS (b) (4) to check on and value the equipment to make sure(b) (4) offer is reasonable. will be going to With regards to specialty equipment, the question was raised on whether or not there was a rationale (b) (4) behind the (b) (4) b5 (b) (4) Concerning labor, DOE confirmed with SCS that labor hours are part of the fact-finding that SCS will conduct on their site visit to(b) (4) Page 1 of 3 SoCo FOIA Response 001615 Conference Call-12/5/2007 Award: DE-FC26-06NT42391 Southern Company Services Andy explained that when you have a termination for convenience, a fixed price contract really becomes a cost-reimbursable one. Given the circumstances, the labor rates may need to be verifiable. DOE will seek input from Legal Counsel. SCS mentioned that if(b) (4)does not want to provide SCS with their labor rates, they can provide them directly to DOE. (b) (4) Material Handling Fee: (b) (4) (b) (4) While the number looks high, Andy reasoned that this Reasonable Profit may be acceptable for a Firm Fixed Price Contract. The FAR speaks to reasonable profit rates for a Cost Reimbursable Contract stating(b) (4) is reasonable. Since this is a termination for convenience and has essentially entered the realm of being cost-reimbursable (b) (4)may be high. Materials in Canada: The steel (not yet fabricated) is in Canada. In order to bring it to the United States, there is a raw material dumping fee. (b) (4) If the manufacturer fabricates it and sends it to the US, the fee would not apply but the cost of the steel would increase. Apparently, no one in Canada can use this material because it has a special thickness. (b) (4)claims the supplier cannot restock or resell in Canada so it must come to the U.S. SCS is considering contacting the supplier in Canada to confirm this claim. The steel originally came from Germany. SCS has expressed an Interest in speaking with a DOE property specialist regarding the whole situation. Brittley agreed to speak with Fran Wright to get her up to speed on the circumstances surrounding the project and have Fran call SCS (or provide SCS with Fran's phone number). The loss of additional work claim was revisited. SCS stated that they do not want to entertain it with (b) (4) It, like all of the other claims, is just what (b) (4) has proposed. SCS has not agreed to any of the claims made by (b) (4)Andy cautioned not to turn this into a stumbling block and maybe use it as a (b) (4) negotiation point to ge to come to an agreement with SCS regarding a final claim amount. Merle cautioned SCS to not ostracize (b) (4)during this process since it is likely that, given what happened with regards to soliciting the bids on this projec (b) (4) was the only technically acceptable (b) (4) may be the only capable company proposing for the new site. bidder), SCS then mentioned handling a subcontractor's subcontractor (third tier) costs. How do those costs get substantiated? Do they need to be substantiated? Andy did not think that DOE became involved at this level of subcontracting but would check into it. (b) (4) bS • the property. Schedule a call between SCS and DOE representatives regarding property issues. DOE will check to see how much of the costs need to be substantiated at a third tier subcontract level. Page 2 of3 SoCo FOIA Response 001616 Conference Call-12/512007 Award: DE-FC26-06NT42391 Southern Company Services .................................................................................................................... Post conference call, Brittley had another call with Jennifer Morrison, Terry Carter, Tim Pinkston. Charles Henderson and Richard Harbuckle regarding the (b) (4) . (b) (4) has received a letter from DCMA who recommended an overhead rate adjustment (a higher rate). (b) (4) is trying to pass these costs on to SCS who is unwilling to pay the difference. SCS would like to set up a conference call with DOE to discuss the situation. Action Items: • Jennifer will send Brittley a copy of the letter from DCMA. NOTE: It contains confidential information. • Brittley will set up an appointment to discuss the matter. Page 3 of3 SoCo FOIA Response 001617 Dunlap, Ann C. From: Robbins, Srittley K. Monday, December 17, 2007 11:33 AM Russia!, Thomas Fwd: RE: Open items (e-mail 2 of 2) (b) (4) (SCS Redline 11-6·07).DOC SCS 11·7-07).DOC Sent: To: Subject: Attachments: ; (b) (4) (App E- Reimburable Costs >>>"Morrison, Jennifer B." 12/17/2007 11:27 AM >>> Attached are the following documents (in 2 e-malls because of the size of the attachments): (i) the (b) (4) letter of Intent, (ii) the (b) (4) (b) (4) (iii) the (iv) the drart of the (b) (4) (v) Appendix E of the that was closest to final, and (b) (4) (b) (4) Please let me know if you would like for me to explain the structure of the other materials. (b) (4) or if you need Thanks, Jennifer .· ...' u Jennifer B. Morrison Southcm Company Services, Inc . 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (oflice) (cell) (b) (6) 205-257-6381 (f.'lx) jenmorri@southemco.com This e-mail and any of its attachments may contain proprietary information of Southern Company and/or its affiHate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it Is intended. If you are not the intended recipient of this email, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or Its affiliates and is prohibited. I( you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 1 SoCo FOIA Response 001618 From: Brittley Robbins [mallto:Brittley.Robblns@NETL.DOE.GOVJ Sent: Monday, December 17, 2007 9:13AM To: Morrison, Jennifer B. Subject: RE: Open items HI Jennifer, (b) (4) (b) (4) Do you have a copy of the letter of Intent with and the most recent version of the Draft subcontract with that you could provide to us? We are having an internal meeting today at 1:00 EST and it would be helpful to have these documents in order to analyze the claims. Thanks, Brittley >>>"Morrison, Jennifer B." 12/13/2007 11:06 AM>>> Thank you for the update, Brittley. I look forward to talking with you next week. In the meantime, have a good weekend I Jennifer Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Binningham, Alabama 35203 205-257-6730 (oflice) 205-568-63 05 (cell) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain proprietary information of Southern Company and/or its affiliate that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is Intended. If you are not the intended recipient of this email, any dissemination, distribution. copying, or action taken In relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. ' 3 From: Brittley Robbins [mallto:Brlttley.Robblns@NETL.DOE.GOVJ Sent: Thursday, December 13, 2007 9:53 AM To: Morrison, Jennifer B. Subject: Open items Hi Jennifer, (b) (4) tems. r have been trying to schedule DOE people for an internal meeting to discuss the open Issues and have not been able to successfully get everyone I just wanted to give you a quick update on the status of the open 2 SoCo FOIA Response 001619 together. We are scheduled to tentatively meet on Monday so hopefully I will be able to provide you with some additional DOE Input on Tuesday. Until then, I unfortunately don't have any new Information. I'll continue to keep you posted. Brlttley ., . .i 3 SoCo FOIA Response 001620 SoCo FOIA Response 001621 SoCo FOIA Response 001622 SoCo FOIA Response 001623 SoCo FOIA Response 001624 SoCo FOIA Response 001625 SoCo FOIA Response 001626 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Robbins, Brittley K. Monday, December 17, 2007 2:17PM Russia!, Thomas Fwd: RE: Open items (e-mail 1 of 2) Exhibit 1- General Conditions Major Equipment (Redlined 10·15-07).doc See attached •.. >>>"Morrison, Jennifer B." 12/17/2007 2:02PM >>> I am sorry that this is so late. I was at lunch when you sent your e-mail and left your voice mail message. Jcnniler B. Morrison Southcm Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (cell) (b) (6) 205-257-6381 (fax) jenmorri@soutl1ernco.com This e-mail and any of its altachments may contain proprietary Information of Southern Company and/or its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it Is intended. If you are not the intended recipient of this email, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Brittley Robbins [mailto:Brittley.Robbins@NETL.DOE.GOV] Sent: Monday, December 17, 2007 11:52 AM To: Morrison, Jennifer B. Subject: RE: Open items (e·maill of 2) Hi Jennifer, (b) (4) r neglected to ask you for the draft subcontract with Do you have a copy of this that you could send to me? Thanks, Brittley >>> "Morrison, Jennifer B." 12/17/2007 11:28 AM >>> Attached are the following documents (in 2 e-mails because of the size of the attachments): SoCo FOIA Response 001627 (i) the (b) (4) Letter of Intent, (ii) the(b) (4) (b) (4) (iii) the (b) (4) (iv) the (v) Appendix E of the(b) (b) (4) (4) (b) (4) Please let me know If you would like for me to explain the structure of the other materials. or if you need Thanks, Jennifer Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alnbama 35203 205-257-6730 (oftice) (cell) (b) (6) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain proprietary information of Southern Company and/or its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this email, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Brlttley Robbins [mailto:Brittley.Robblns@Nffi.DOE.GOV] Sent: Monday, December 17, 2007 9: 13AM To: Morrison, Jennifer B. Subject: RE: Open Items ,; HI Jennifer, Do you have a copy of the letter of intent with (b) (4) nd the most recent version of the Draft subcontract with (b) (4)that you could provide to us? We are having an Internal meeting today at 1:00 EST and it would be helpful to have these documents in order to analyze the claims. Thanks, Brittley >>> "Morrison, Jennifer B." 12/13/2007 11:06 AM >>> Thank you for the update, Britlley. I look forward to talking with you next week. 2 SoCo FOIA Response 001628 In the meantime, have a good weekend! Jennifer Jenniter B. Morrison Southem Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (cell) (b) (6) 205-257-6381 (fax) jcmnorri@southcrnco.com This e-mail and any or its attachments may contain proprietary information of Southern Company and/or ils affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is Intended solely for the use of the individual or entity for which it is Intended. If you are not the Intended recipient or this email, any dissemination. distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company andfor its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Brlttley Robbins [mailto:Brittley.Robblns@NETL.DOE.GOV] Sent: Thursday, December 13, 2007 9:53 AM To: Morrison, Jennifer B. Subject: Open items Hi Jennifer, (b) (4) I just wanted to give you a quick update on the status of the open I have been trying to schedule DOE people for an Internal meeting to discuss the open issues and have not been able to successfully get everyone together. We are scheduled to tentatively meet on Monday so hopefully I will be able to provide you with some additional DOE Input on Tuesday. Until then, I unfortunately don't have any new information. I'll continue to keep you posted. Brittley 3 SoCo FOIA Response 001629 SoCo FOIA Response 001630 31 SoCo FOIA Response 001632 SoCo FOIA Response 001633 SoCo FOIA Response 001634 SoCo FOIA Response 001635 SoCo FOIA Response 001636 SoCo FOIA Response 001637 SoCo FOIA Response 001638 SoCo FOIA Response 001639 SoCo FOIA Response 001640 SoCo FOIA Response 001641 SoCo FOIA Response 001642 SoCo FOIA Response 001643 SoCo FOIA Response 001644 SoCo FOIA Response 001645 SoCo FOIA Response 001646 SoCo FOIA Response 001647 48 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: ''Morrison, Jennifer B." Monday, January 14, 2008 4:43 PM Robbins, Brittley K. Henderson, Charles W.; Madden, Diane R.; Carter, Robert; Pinkston, Tim E. RE: Subcontractor Claims for Orlando JGCC Project Close-Out Subcontractor Cancellation Cost Estimate to DOE (1-14-0B).xls Brittley, As promised, attached is an estimate of the close-out costs that we anticipate submitting to DOE for the Orlando IGCC Project. You will note that this document is marked as a 11 draft. 11 This is because (consistent with some of the items discussed in last Friday's memorandum) a couple of subcontracts have not yet been fully resolved. We will be happy to discuss this document and the document that we sent you on Friday once you and your team have a chance to review and discuss these matters. In the meantime, if I can answer any questions for you, please let me know. Thank you, Jennifer <> Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (cell) (b) (6) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain proprietary information of Southern Company and/or its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 001649 From: Morrison, jennifer B. Sent: Friday, january 11, 2008 1:08 PM To: Brittley Robbins Cc: Diane Madden; Pinkston, Tim E.; Henderson, Charles W.; Carter, Robert Subject: Subcontractor Claims for Orlando IGCC Project Close-Out Brittley, As we discussed on Tuesday, I am sending you a memorandum that describes the efforts that SCS is undertaking to close out the subcontracts for the work that was being done on the Orlando IGCC Project. This document also includes an overview of the costs that the subcontractors claim as cancellation costs. We are preparing a table that identifies (by subcontractor) the amounts that we intend to invoice DOE as cancellation costs. That table is not quite finished because we have had some key personnel out of the office. I'll send that along on Monday. Please note that the attached document is in draft form because we are still working through issues with some of the subcontractors. Thanks very much. I look forward to talking with you soon about moving forward on this matter. Have a great weekend, jennifer <> Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-267-6730 (office) (cell) (b) (6) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain proprietary information of Southern Company and/or its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e -mail and any attachments. Thank you. 2 SoCo FOIA Response 001650 Privileged and Con?dential Southern Cumpany Services. Inc. SoCo FOIA Response 001651 Memo•·nndum to DOE l'•·h•lleged nut! Confitlentlnl A SOUTHERN COMPANY Euergy to Serve Your World~ TO: Certain DOE Representatives FROM: Southem Company S01vices, Inc. DATE: January II , 2008 RE: Subcontractors' Claims tor Costs for Work Performed on the Orlando IGCC Project DOE Cooperative Agreement Number DE-FC26-06NT42391 This memorandum provides an explanation of the cancellation costs associated with subcontracts tor work performed on the Orlando IGCC Project ("Project"). It describes two categories of subcontracts: (i) subcontracts for equipment and/or services that were shared between the gasification island portion and the combined-cycle portion of the Project, and (ii) subcontracts for equipment and/or services that were for only the gasification island portion of the Project. While the final disposition of some of the subcontracts below has been determined, others remain unresolved. As a result, at this time the document is being provided to DOE in a "DRAFT" format. As events transpire, Southern will be happy to update this document and resubmit it to DOE. Shared Subcontracts - Because of the "shared" status of these items, a certain percentage of the costs of these subcontracts was allocated to the combined-cycle, while the remaining percentage of the costs was allocated to the gasification island. (b) (4) Pnge I of9 SoCo FOIA Response 001652 Mcmomndum to DUE Prh-ilcged and Confidential Page 2 DFQ SoCo FOIA Response 001653 Memorandum tn DOE Privileged and Cnn?den?nl Page 3 of!) SoCo FOIA Response 001654 la DOE Privileged and Cnn?dcn?nl Page 4 of?) SoCo FOIA Response 001655 Memorandum to llOE P.-i\'ilcgcd nnd Confidcntinl (b) (4) l'nge 5 of9 SoCo FOIA Response 001656 Menmrnudum to DOE and Page 6 SoCo FOIA Response 001657 Memorandum in HIDE Privilegch Cnn?llential Fag: 7 of!) SoCo FOIA Response 001658 Memorandum In DOE Privileged and Cnn?llmtinl Page 8 at?) SoCo FOIA Response 001659 Memorandum In DOE Privlicgcd mu! Con?dential Page 9 or? SoCo FOIA Response 001660 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Robbins, Brittley K. Monday, January 14, 2008 4:46 PM Ferlic, Andrew J.; Wright, Frances M.; Stolzenberg, Merle P.; Destefano, Michael S.; Russia!, Thomas Madden, Diane R. Fwd: Subcontractor Claims for Orlando IGCC Project Close-Out RE: Subcontractor Claims for Orlando IGCC Project Close-Out; Memo on Orlando Subcontractor Claims for DOE (1·11-0B).doc >>>"Morrison, Jennifer B." 1/11/2008 2:07PM >>> Brlttley, As we discussed on Tuesday, I am sending you a memorandum that describes the efforts that SCS Is undertaking to close out the subcontracts for the work that was being done on the Orlando IGCC Project. This document also Includes an overview of the costs that the subcontractors claim as cancellation costs. We are preparing a table that ldentmes {by subcontractor) the amounts that we intend to Invoice DOE as cancellation costs. That table Is not quite finished because we have had some key personnel out of the office. I'll send that along on Monday. ' ' Please note that the attached document Is In draft form because we are still working through Issues with some of the subcontractors. Thanks very much. I look forward to talking with you soon about moving forward on this matter. Have a great weekend, Jennifer <> Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257·6730 (office) (cell) (b) (6) 205·257-6381 (fax) jenmorrl@southernco.com SoCo FOIA Response 001661 This e-mail and any of Its attachments may contain proprietary information of Southern Company and/or Its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail Is intended solely for the use of the Individual or entity for which It Is Intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and Is prohibited. If you are not the intended recipient of this e-mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 001662 Dunlap, Ann C. From: Sent: To: Cc: Subject: Madden, Diane R. Friday, February 01, 2008 9:55 AM Ferlic, Andrew J.; Wright, Frances M.; Russia(, Thomas Robbins, Brittley K. Fwd: Performance Contractors -- Orlando Cancellation Charge Tom, Fran, Andy I decided to go ahead and forward this message since Brittley is off today. This way if a conference call is needed we can have it early next week to resolve any questions/concerns. THANKS! Diane >>>"Morrison, jennifer B." 1/31/2008 6:52PM >>> >>> Brittley and Diane, We have very recently encountered another subcontractor cost associated with the cancellation of the Gasification Island ("GI") portion of the Orlando project. (b) (4) (b) (4) SoCo FOIA Response 001663 (b) (4) We hope to be able to have a conversation with you and get your input before we take action in this situation, but we are being pressed by (b) (4) to make a decision. Input and guidance from you and your team as to how to treat this charge would be greatly welcomed! We apologize that this situation was not presented in our previous materials and discussions, and we feel pretty confident that there are no other subcontractor charges for which we will seek DOE reimbursement. By working with our subcontractors, we have been able to avoid some costs that we had previously anticipated having to incur, but this situation turns out not to be one that we were successful in avoiding. Regard, Jennifer Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 206-257-6730 (office) (cell) (b) (6) 205-257-6381 (fax) jenmorri@southernco .com This e-mail and any of its attachments may contain proprietary information of Southern Company and/or its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. lf you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 2 SoCo FOIA Response 001664 From: Sent: To: Cc: Subject: "Warren, Daniel H." Monday, February 04, 2008 10:18 AM Madden, Diane; Hargis, Richard Toth, Brian D.; Pinkston, Tim E. FW: Mississippi Power Company Kemper County IGCC Project FYI, Dan ·····Original Message----From: Berry, Charles Rick (MPC) Sent: Monday, February 04, 2008 10:08 AM To: Osborne, Carolyn Cc: Hargis, Richard; Mollot, Darren; Cohen, Eric; Amerasinghe, Felix; Ahern, Richard; Le Due, Edward; Schmitzer, David; Tobin, Daniel; Toth, Brian D.; Warren, Daniel H.; McMillan, Scott; (b) (4), (b) (6) O'Neal, Dan L.; Pinkerton, Tommy T. Subject: RE: Mississippi Power Company Kemper County IGCC Project Thank you Carolyn. Our afternoon call will be at 2:00pm Eastern, 1:00pm Central with the following call in information: (b) (4), (b) (6) ----Original Message----From: Osborne, Carolyn [mailto:Carolyn.Osborne@eh.doe.gov) Sent: Monday, February 04, 2008 9:52AM To: Berry, Charles Rick (MPC) Cc: Hargis, Richard; Mollot, Darren; Cohen, Eric; Amerasinghe, Felix; Ahern, Richard; Le Due, Edward; Schmitzer, David; Tobin, Daniel Subject: RE: Mississippi Power Company Kemper County IGCC Project 2 pm this afternoon (Eastern) would work for us. Please let us know the call-in number. -----Original Message---·· From : Berry, Charles Rick (MPC) [mailto:CRBERRY@southernco.com) Sent: Monday, February 04, 2008 9:08AM To: Osborne, Carolyn Subject: RE: Mississippi Power Company Kemper County IGCC Project Carolyn, We are looking forward to the conference call this afternoon to further SoCo FOIA Response 001665 discuss EIS coordination. Please give me a time that works for you and your team and I'll forward a call in number. Thanks. -----Original Message----From: Osborne, Carolyn [mailto:Carolyn.Osborne@eh.doe.gov) Sent: Friday, January 25, 2008 4:20 PM To: Berry, Charles Rick (MPC) Cc: Toth, Brian D.; Warren, Daniel H.; McMillan, Scott;(b) (4), (b) (b) (4), (b) (6) O'Neal, Dan L.; Pinkerton, Tommy T. Subject: RE: Mississippi Power Company Kemper County IGCC Project (6) I will coordinate with people on Monday-- many were out today. -----Original Message----From: Berry, Charles Rick (MPC) [mailto:CRBERRY@southernco.com) Sent: Friday, January 25, 2008 8:54AM To: Osborne, Carolyn Cc: Toth, Brian D.; Warren, Daniel H.; McMillan, Scott; (b) (4), (b) (6) O'Neal, Dan L.; Pinkerton, Tommy T. Subject: FW: Mississippi Power Company Kemper County IGCC Project (b) (4), (b) (6) Sorry Carolyn, I had the wrong domain name by one letter. Thanks. > _______________________________________ >From: Berry, Charles Rick (MPC) >Sent: Thursday, January 24, 2008 7:13PM >To: Carolyn Osborne (carolyn.osborne@hg.doe.gov) (b) (4), (b) (6) > Cc: Toth, Brian D.; Warren, Daniel H.; McMillan, Scott (b) (4), (b) (6)O'Neal, Dan L.; Pinkerton, Tommy T. Mississippi Power Company Kemper County IGCC Project > >Thank you for meeting with me by phone today. I would like to confirm >that your suggested February 4th, in the afternoon, for our follow up >conference call would be fine for us. Once you have determined the >appropriate participants from your end, just let me know a good time >for you and we will provide a call in number. The participants from >this end will be myself and: > >Brian Toth, Dan Warren and Scott McMillan Southern Company >Services (b) (4), (b) (6) >Counsel >Dan O'Neal and Tommy Pinkerton >Power Mississippi > >To recap some of our call, MPC understands that an EIS will be >required for this project whether we pursue federal loan guarantees or 2 SoCo FOIA Response 001666 >participation in the clean coal funding such as that previously > proposed for the Orlando IGCC project. We are very likely to make >application to both programs. To that end, we thought a conversation >with you and other appropriate DOE officials would be the best place >to start. > >Several of the folks mentioned above were directly involved with the > EIS work for the Orlando project and had a very cooperative >relationship with DOE NETL which has already conducted a NEPA review >of the technology. Our project is the same technology but would be >built in Mississippi on the Kemper County site. > >Understanding that DOE has separate NEPA managers for these two >programs, we would like to find a way to coordinate this effort in the > most effective way possible. We look forward to discussing an >appropriate NEPA interface with DOE on our call. > >Thanks again and I look forward to hearing from you soon. > >Rick Berry >Manager, Environmental Quality > Mississippi Power Company > 228.897.6420 > > > > > 3 SoCo FOIA Response 001667 Dunlap, Ann C. From: Sent: To: Cc: SubJect: Attachments: (b) Robbins, Brittley K. Tuesday, February 12, 2008 9:41 AM Wright, Frances M.; Stolzenberg, Merle P.; Russial, Thomas Madden, Diane R. (b) (4) Fwd: SCS Orlando Project -- Scrap Value of Materials unde Subcontract (4) Materials Scrap Value Estimates (2-6-0S).pdf All, (b) (4) If you recall, the only remaining Item that DOE questioned as part of the subcontract termination costs was the (b) (4) that was offering for the(b) (4) In materials still at its shop. SOuthern has now provided us with credit o (b) (4) Independent estimates of the scrap material at(b) (4) See attached. If you have any objections to the estimates or to DOE concurring on the (b) (4) credit offered by(b) (4) please respond to this email no later than COB Wednesday, 2/13. I Intend to contact SOuthern on Thursday, 2/14, and let them know DOE's position with regards to the(b) (4)termination costs. (b) (4) If you need additional information regarding the laim, let me know and I can provide It to you. Thanks, Brlttley >> (b) (4), (b) (6) " 2/8/2008 3:43PM >>> Hi llrittley and Dione, (b) (4) With regard to ltem3 of your e-mail below, attached nrc the 3 scrap value estimates for th materials (in 1 . These values are based on scanned document). These estimates range from approximately (b) (4) today's scrap market. We have been informed that the mmket value of the materials at the time the project wus cancelled was(b) (4) Please recall that the subcontractor(b) (4) gave us (b) (4) for the materials. (b) (4) We are available to discuss this or other matters related to the associated with the Orlando close-out. harges or other subcontractor costs Thanks, Jennifer Jemtite1· B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (b) (6) (cell) 205-257-6381 (fax) jenmorri@southcmco.com This e-mail and any of its attachments may contain proprietary information of Southern Company and/or its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the Individual or entity for which it is intended. If you are not the intended recipient of this email, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and Is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 001668 From: Morrison, Jennifer B. Sent: Monday, January 28, 2008 4:06 PM To: Brittley Robbins; 'Diane Madden' Cc: Pinkston, Tim E.; Henderson, Charles W.; Carter, Robert Subject: RE: Recap of today's call Brlttley, '! We appreciate having had the chance to talk with you and your team about the subcontract matters that were the subject of the memorandum that we prepared for DOE. Here is where we are on the three matters raised in your summary email: (b) (4) 1. With regard to item 1 below (the concern with th subcontract), I have attached an excerpt from the Scope of Work document for the EPC agreement between SPCOG and(b) (4) This document (and Sections 1.07 and 2.03, in particular) should provide appropriate documentation to demonstrate that Southern (and not (b) (4) is responsible for the costs associated with the design changes to the HRSG that were necessary for the HRSG to operate using syngas. As a point of clarification, please note that (b) (4) of the costs for the (b) (4) subcontract were billed to the project before the termination - this was the amount that was paid pursuant to the subcontract with (b) (4) before the project was terminated. The termination payment was (b) (4) Also, unfortunately the (b) (4) termination payment was invoiced to DOE last week and has been approved by DOE. We very much apologize for this oversight, and will proceed as you direct us to. Hopefully, the attached documentation will help to address your concerns about the (b) (4) termination payment to (b) (4) 2. The (b) (4) charge from (b) (4) was incurred as a direct result of the need to modify the software to eliminate the gasifier features of the software. The charge would not have been incurred but for the termination of the gasification island portion of the project. Even so, we stated that this amount will not be charged to DOE, so we will not bill the gasirtcation island project for this amount. (b) (4) 3. We are working on obtaining estimates for the materials for the ubcontract. We do not yet have a good understanding as to how long it will take to wrap that up, but will keep you posted. Also, the termination costs associated (b) (4) with the subcontract will not be billed to DOE until this matter has been resolved. We will be in touch as we have more information. Thank you! Jennifer Jennifer B. Morrison Southem Company SctYices, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (cell) (b) (6) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain proprietary information of Southern Company andfor its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the Individual or entity for which it is intended. If you are not the intended recipient of this email, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail Is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 2 SoCo FOIA Response 001669 From: Brittley Robbins [mailto:Brittley.Robblns@Nffi.DOE.GOV] Sent: Tuesday, January 22, 2008 5:29 PM To: Morrison, Jennifer B. Cc: Diane Madden Subject: Recap of today's call HI Jennifer, Thank you so much for participating In the call today. I think we made progress since there are only a few open items left to resolve. To recap the open items... 1. Reference (b) (4) - HRSG Design Changes - Please provide DOE with assurance/confirmation that the (b) (4) In termination costs are not costs that will be absorbed b (b) (4)on the continuing project. Until this is resolved, SCS should not invoice DOE for these costs. 2. Reference (b) (4) - Distributed Control Systems ("DCS") - Per our phone call today, the (b) (4) charge for software changes to delete gasification functions will not be charged to the project. Please confirm this. 3. Reference (b) (4) - (b) (4) Components - DOE affirms that the proposed salvage value of equipment (b) (4) Is unsupported and scs must continue pursuing Independent estimates of the materials scrap value. SCS should not Invoice DOE for costs associated with this subcontract until scrap value has been appropriately justified. Thanks again for the call. Please feel free to contact me with any questions, Brittley Robbins Contract Specialist, DOE-NETL Acquisition and Assistance Division (412) 386-5430 ,. 3 SoCo FOIA Response 001670 SoCo FOIA Response 001671 72 SoCo FOIA Response 001673 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: "Rush, Randall E." Thursday, February 14, 2008 11:12 AM Bauer, Carl Russial, Thomas FW: Site Change Request for Cooperative Agreement DE-FC26·06NT42391 Kemper County Site Change Request.pdf Note that this was offically transmitted to Diane today. Randall E. Rush General Manager, Gasification Technology Southern Company Generation 42Inverness Center Parkway Birmingham, AL 35242 * Internal: 8-992-6319 * External: (205) 992-6319 (b) (6) * Cell: * Fax: (205) 992-6005 E-mail: rerush@southernco. com > ________________________________________ > From: Pinkston, Tim E. > Sent:Thursday, February 14,2008 9:50AM To:Diane Madden > (Diane.Madden@NETL.DOE.GOV); Brittley Robbins Cc:Rush, Randall E.; >Henderson, Charles W. > Subject:Site Change Request for Cooperative Agreement > DE-FC26-06NT42391 > > Brittley and Diane, > >Attached is our request to change the site for the project under Cooperative Agreement DEFC26-06NT42391 from Orlando, FL to Kemper County, MS. As requested, the document provides project cost information for the new site, a commitment letter from Mississippi Power, scope and objective information, a new schedule, an assessment of repayment impacts, host site information and a discussion of key project decision points. > >We look forward to continuing to work with you in demonstrating the TRIG technology. > > Let me know if you have questions or need more information. > > > Tim Pinkston > Project Manager > Gasification Technology > Southern Company Generation SoCo FOIA Response 001674 > Office 205-992-5042 >Cell (b) (6) > > > > <> . .. I 2 SoCo FOIA Response 001675 ltantlal! E. Hm:h (;nnarai l.l:nl:l!liJI · <)a:;ifiC~1lillll 'fr:du1oln:~y 1ioufhem C:nult>aiiY (;,!lwr.1li•>n •li! lnv;:rr.c:;;:: cn•.l.l~ 1-'.llk'.'.'ll)' fltn Bn!l llirttll!l;Jhillll, J\1. :J!i/•\2 ., ul ::o:;.~•92.1l:J HJ Fax ::ru5.Sf.II..GOW) February 12, 20011 National Energy Technology Laboratory AUn: Diane R. Madden, MIS 922-342C 626 Cochrans Mill Road P. 0. Box 10940 Pittsburgh, PA 15236-0940 Dear Ms. Madden: Subject: Site Change Request for DE-FC26-06NT42391 Southern Company Services, Inc. (SCS) is pleased to submit the attached documents in support of our request to change Cl1e site for the project under Cooperative Agreement DE-FC26-06NT42391 from Orlando, FL to Kemper County, MS. The relocated plant will be owned by Mississippi Power Company (MPC), a subsidiary of Southern Company. Originally l11e commercial operating date (COD) for the Mississippi facility was to follow t11e COD for the Orlando site by three years. With the tennination of the Orlando site, the Mississippi site will now host the first full-scale demonstration of the Transport Integrated Gnslflcation (I'RIGn.r) technology with COD scheduled for June, 2013. The technical configurntion of the Mississippi plant will be very similar to the configurntion that was planned for the Orlando site and, therefore, all of the original project demonstration objectives will be met with the new site at no cost increase to DOE. DUI'erences between the two siles that arc relevant to tbc TRIGn.c teclutology are as follows. 'I ... The Mississippi IGCC is based on a 2xl combined cycle with two gasification trains instead of a lxl combined cycle with a single gasification train. Each gasification train fuels a GE 7FA~ combustion turbine, the same turbine planned for Orlando, so the gasification trains are similar In size to the Orlando design. GE has completed combustion testing with the expected syngas and found that the same burner design can be utilized for the Ugnite and PRB derived syngas. The Mississippi IGCC will use Mississippi lignite Instead of PRB coal as Its primary fuel. Mississippi lignite coal has been tested at the Power Systems Development Facility with good results. Southern Company plans to conduct a test with PRB coal in the Mississippi facility during the DOE supported Demonstration Phase of the project, resulting In a wider range of fuel testing than the original Orlnndo site. The sulfur removal and recovery system is different due to the higher sulfur content of the lignite coal. In both cases, selection of the sulfur removal and recovery system was based on commercially available technology and the best economics for eaehcase. The coal drying system has been modified to Include a commercially available fluid bed d.cyer for efficient removal or the Wgl1er moisture content of the lignite coal. SoCo FOIA Response 001676 Ms. Diane Madden Fcbnwy 12, 2008 Page two Front End Engineering Design (FEED) for lhe Mississippi site began in early 2007 and the initial phase of FEED is scheduled for completion May 31,2008. One of the deliverables ofFEBD is an updated cost estimate based on scope lnfonnatioo generated during FEED and CWTent market pricing. MPC has conuniued to move forward with lhe project provided that DOE approves changing the site to Kemper County and it continues to be the best econom1c new generation option for the customers of MPC based on the updated cost estimate. CCPI Round 2 funding for the project is nccessruy to manage fust-of-a-kind risk, since the Mississippi facUlty will no longer realize the benefits lhat would have resulted from starting up three years after the Orlando facility. Letters from the CBO of Mississippi Power, the COO of Southern Company, aod Governor Barbour of Mississippi c,tcscriblng their commiunent to the project arc attached. Also attached is n document that describes the Mississippi site and provides lhc costs and other infonnation required by DOE for npprovnl to buiJd the CCPI project at tile site. Please do not ltesitatc to call me if you have questions or need additional infommt.ion. Sincerely, ~~~ Atlaclunents ce: Brittley K. Robbins ; SoCo FOIA Response 001677 ll:mnn:; A Fanning South cUI Compnuy Chief Opcrnling Olfir.o1 :10 IYan Al:r.n••lr. B:v1l., NW Oin SC1505 Allimla, Gil 30308 Tel 40•1~06.0600 FiiX40•i 505 039·1 f~~~tllJJ'TI'lHHF.lH!Ifll ~ .ti:t!.~~lll:fi\ [P'ti!NrtY t!lillU\in@P.Q\.IJ!lQ.!!l~,'i.Q.I,l} February 11, 2008 Mr. Carl Bauer Director, National Energy Technology Laboratory U.S. Department ofEnergy/NETI. 626 Cochrans Mill Road Pittsburgh, PeiUlSylvania 1523 6 Dear Mr. Bauer; Southern Company is prepared to demonstrate the advanced coal gasification technology, TRIGnr, previously proposed in Orlando, Florida, developed in partnership with the Department of Energy, in Kemper County, Mississippi. Southern believes that the continuation of this project in Mississippi will be a clear and dramatic response to the Department's goals of clean, secure, domestic energy for America. ·The relocated plant will be owned by Mississippi Power Company, a subsidiary of Southern Company. The Mississippi project has been under development for over a year and with its 2013 commercial operation date, will confront the first-of-a-kind risks that the Orlando project was going to bear and help resolve. The Mississippi Project now becomes the first commercial demonstration ofTRIGn', and requires the Department's approval of the site change from Orlando to Kemper County in order to proceed. All of the original project demonstration objectives will be met with the new site at no cost increase to the Department. In fact, the objectives will be exceeded with the new site, since it will allow not only PRB coal to be tested, but also lignite. Demonstrating the use of lignite will open up the opportunity to use this largely underutili.zed resource which runs from Texas to Alabama to meet our nation's energy requirements. Southern is strongly committed to moving the project forward and believes the Mississippi site provides the opportunity for achievement of the Department's goals for America. In addition, the Governor and State of Mississippi are committed to the project because of its economic impact in a depressed region of Mississippi, the use of the indigenous lignite and for the opportunity to participate in technology development. Southern Company looks forward to continuing to work with the Department in advancing the TRIGTM technology. Sincerely, SoCo FOIA Response 001678 Anthony J. Topaz! President and Chief Executive Officer 2992 West Beach Blvd Post Office Box 4079 Gulfport, Mississippi 39502-4079 Tel 228-865-5320 II SOIITIIflllN t:OMI'MlV February II, 2008 Mr. Carl Bauer Director, National Energy Technology Laboratory U.S. Department ofEnergy/NETL 626 Cochrans Mill Road Pittsburgh, Pennsylvania 15236 Dear Mr. Bauer: Mississippi Power Company (MPC) began working on a project in 2006 to build a lignitefueled 2x I integrated gasification combined cycle (IGCC) facility using the air-blown Transport Integrated Gasification (TR!Gn1) technology. In addition to utilizing lignite in 1111 affordable, efficient and environmentally friendly manner, MPC believes this project will help address key strategic objectives for MPC of increased fuel diversity, geographical diversity of generation and enhanced reliability while providing an economic and reliable resource to meet customer needs. · As President and CEO of Mississippi Power Company, I want to express our commitment to the execution of the proposed project. With the Department's approval for changing the site to Kemper County under Southern Company Services' CCPI Round 2 project, and the project continuing to be the best economic option for the customers of MPC, we will move forward with obtaining regulatory approval in the fonn of a certification of need and necessity, and upon regulatory npproval, full execution of the project. MPC is enthusiastic about the opportunity to furthe1· the commerciulization of the TRIGT:.I technology using Mississippi lignile coal nnd believes that this technology suppm1s the Department's goal to ensure that the United States has nnd maintains secure, clean, reliable nnd affordable electric power. MPC appreciates the consideration of this site change request and looks forw11rd to working with the Deparlment. Sincerely, SoCo FOIA Response 001679 STATE OF MISSISSIPPI OFFICE OF TilE GOVERNOR HALE\' BARBOUR (it}\ EH.NLI~ February 8, 2008 The Honorable Samuel Bodnwn United States Department of Energy 1000 Independence Avenue, S W Washington, DC 20585 Dear Secretary Bodman: l cnthusiosticnlly support ~·1ississippi Power's proposed lntcgmted Gasification Combined Cycle facility in Kemper County, Mississippi. The jobs nnd economic opportunity brought to East Mississippi by this generating plant can result in a much needed economic catalyst for this region's development and prosperity. In addition to serving its citizens, Mississippi will gain a new reputation as u leader in <~dvanced, efticicnt clcnn coal technology. Tht: realization of this fncility would place Mississippi nt the helm of America's ongoing effort to achieve energy independence through increased domestic product ion of alternntiw nnd trnditional energy sources. Mississippi is committed to lead the way in supporting the Administmtion's goal of pursing energy Sll)>ply options us purl of u notional energy strategy mix. In this endeavor, I believe clean coal technologies must play n major role. The proposed IGCC factlity nnd the very impact of this tcchnolog)' can be a tremendous positive force on the nation's energy policy. As you consider your support for the proposed facility, he mindful of the remarkable impact a state-of-the-nrt project of this magnitude will have not only in powt:r gent>rution, but in serving the country to achieve energy independence and dramaticnlly enhancing the qunlity of life for our state. I feel strongly this project is in the very best interest for the United States and the State of Mississippi and ask that you extend the necessary federal support to move this project boldly forwm·d. l 'l):iT OFFICI: Bl IX llV • ):\ Cf\SON. 1-.IISSl:i~lPPl W1~'i • TF.I.I'l'l lllNE· (h<11 i 15'). \ I~~' • l't\X: 1111'11 l i'J IH I • "'""·>=·"·,·rnoool•aol""' """ SoCo FOIA Response 001680 I>J~ I 'C:2f..CitiN S•JUthcrn C.:nmr.1nr Sn,lcct:,lnc $uc C:hanJ.."'C" Krquc;t- P~c I uft7 1'-*:U'JI l·cb"'''l" .lrUR DEMONSTRATION OF A COAL-BASED TRANSPORT GASIFIER PLANT SITE INFORMATION FOR KEMPER COUNTY MISSISSIPPI SUBMITTED BY SOUTHERN COMPANY SERVICES, INC. FEBRUARY 2008 . ., J I SoCo FOIA Response 001681 nn.ro~ oi(;Nl'"~l'JI S."nhrm <..utn;Urlf X f'\·,cu,ldc, S•tc lhH1t!C R<'luc" - P.ar.c l. o( l7 l'cbNU)':!I~Oll PLANT SITE INFORMATION FOR KEMPER COUNTY MISSISSIPPI This document contains a description of a plant site in Kemper County, Mississippi, information on Mississippi Power Company (MPC) and the impacts of executing the CCPI project under Cooperative Agreement DE-FC26-06NT42391 at that site. The plant at the Kemper County site will be owned by MPC, n subsidiary of Southern Company. Originally, the commercial opcmting date (COD) for the Mississippi facility wns to follow the COD lor the Orlando site by three years. With the termination of the Orlando site, the Mississippi site will now host the first full-scale demonstration of the Trnnsport Integrated Gasification (TRIGTM) technology with COD scheduled for June, 2013. TECHNICAL CONFIGURATION OF THE PLANT The technical configuration of the Mississippi plant will be very similar to the configuration that was planned for the Orlando site and, therefo1·e, all of the project demonstration objectives will be met with the new site. Differences between the two sites that are relevant to the TRIG1M technology are as follows. The Mississippi IGCC is based on a 2xl combined cycle with two gasification trains instead of a IxI combined cycle with a single gasification train. Each gasification train fuels aGE 7FA+e combustion turbine, the same turbine planned for Orlando, so the gasification trnins are similar in size to the Ol'lando design. GE has already completed combustion testing with the expected syngas and found that the same burner design con be utilized for the lignite and PRB derived syngas. The Mississippi IGCC will use lV!ississippi lignite instead of PRB coal as its primary fuel. Mississip1>i lignite has been tested at the Power Systems Development Facility with good results. Southern Company plans to conduct n test with PRB coal in the Mississippi facility during the DOE suppOI'ted Demonstration Phase of the project, resulting in a wider range of fuel testing than the original Ol'lando site. The sulfur removal and recovery system is different due to the higher sulfm content of the lignite coal. Jn both cases the sulfur removal nnd recovery system was based on commercially available technology and the most economical selection for each case. The coal drying system has been modified to include a commercially available fluid bed dryer for efficient removal of the higher moisture content of the lignite coal. STATUS, SCHEDULE AND PROJECT STRUCTURE FOR THE NEW HOST SITE The Mississippi IGCC is currently in the design phase and has deliverables consistent with those for the Orlando site. The project will continue be structured in 4 phases. To SoCo FOIA Response 001682 Southfn\ (:f)rllJUI\)'!'itn·•tt~,lnc­ S.tr(lu••~:t" Rt'IU('fl- r..a.~t l •• r 17 lJJ.!·J C!f,..tN'•NT"'2\'JI ftbru>')•:!IOIII segregate costs and activities between the two sites for Phases 2 & 3, activities associated with the Orlando site will utiliz.e a sub designation of"a" and the Mississippi activities will utilize a sub designation of"b". Phase 2b, Design, will include Environmental Information Volume (ElV) preparation and outside engineering other than KBR. Phase 3b, Construction, includes procurement, construction and startup activities. Phase 4, Demonstration, includes activities after the COD and is the same duration as that planned for the Orlando site. Figure I is a summary schedule for the Kemper County site. An updated cost estimate will be completed in April 2008 based on the scope information generated dul'ing FEED and current market pricing. Based on the updated cost estimate and the availability of the CCPI funds for the Kemper County site, Mississippi Power will make a decision on whether to proceed with the project. If n decision is made to proceed, MPC plans to file a Petition for Facilities Certificate with the Mississippi Public Service Commission (MPSC}, and MPSC approval would be expected by Octobe•· of 2008. The Facilities Certificate is required for MPC to consti'Uct the plant in Mississippi and include the costs of the generation resource in its rctailmtes. M PC believes that, as long as the proposed project continues to be the most cost-effective, long-term option for meeting the futtn·e generation needs of its customers, the appropriate approvals will be granted. Although the next part of the design engineering beyond the initial FEED phase will begin in June, SCS docs not plan to seck DOE funding for any Phase 2b activities except for preparation of the EIV and related activities. Phase 3b, Construction, would begin in Novembet· with the purchase of the steam turbine. DOE reimbursement of Phase 3b costs would be contingent upon NEPA approval. With the site change, SCS is proposing that the project deliverables remain unchanged, but is proposing chnnges to the scope for which DOE would cost share. These changes arc primarily driven by the different ownership structure of the project and have the added benefit of simplifying the management, execution, accounting and cost tracking for the project. Fo1·the Orlando site, the Orlando Utilities Commission (OUC) required that the combined cycle portion of the plant be 100% owned by OUC and, therefore, outside of the scope of the cooperative agreement. For the Mississippi site, SCS is proposing that the entire IGCC, including the combined cycle portion of the plant, be in the scope of the cooperative agreement. However, as shown in the nttuched cost estimate, SCS is not asking for DOE to cost share SCS & MPC labor, SCS & MPC travel and KBR design and procurement labor. Even with these changes Southern Company's proposed cost share will increase signilicantly. ..: SoCo FOIA Response 001683 ':... . . . . . 1 •• S...Uh<'m Comp>n, Scn;cn.Jnc. S•t~ C:tun~ Rccp..~l- f'~""C .f •lC t 7 _...., 10 Dl!·FCU... ur.~~!l'Jl Fcbnol.y:nlll ~.., II ;m'Zef' Early Flnlsh Slatt AcdvtlicrsOutsldo~~~·~-----FPS* FPS304 FPC31S - ·····"FPcl21 · -- 01F!807A lOMA'nlt l11o1AR.Or -or •· 31"0Ci0t DIMAVGr oi.NN"or ··· - ;-,iifc-oi ~; FPSSOO 02JANW FPOm 02JANW DctoQDnianPtvMD--...I'It-Z ~!!'0 •- 311JUN10 l1DEC10 o::-.:- O&JANIO' FP554G r - 17FDllt 10fE81D"' _FP20!0 • -- ' - FPseoo ~1o - 1 FI'$UO FPSQO FP20H .,.,,....,v 01-AJL~ 11MAR11 Ozoel!l!' . 0!_MAA11 o:ISI!J'Io _!!~D-= _ 01DCT111' 01DCT111' 01F!II11' 01JUL11 01JUL11 15AUG12 ·-::: . ~=:,.!.}:- "FnQiij' - - ·-· FP$&50 FP:rohllalo OUUl15 O.ta Dale c...,.;_.CycloEftol...nno~~-nt- i I NEPA~ R~at~~ 1 _ - - _ _ -·-·· ; = CCSit-Grang,Pilng&l/ndoiiJfOUI'Ch = = 1:::1 GasVIo<·PIIng 1 Qaslflt<-~ Gallor·- CC~COIUINCllon .. ":":~:: s:.c:~!:"'"tq,Ap 1 == = CCHRSG-Insulafton CCGasTurt>lno-lnstollollon Gulllo<-Piplng S..bsut!oriTr>,.mls>:Onlns..htlonr.,;.,~-bdl"' -~D5DEC17' OZFE~ C-Sntoms.lnc. llt~ LC.'f'l...·nt con."~ ,t,c m:uc~ = CC ~r1onnanc&t T.s.dno IQCC .SU~wp a. C:ommlulonl"ll-,.tion Tn•l:: ~Gasmor-Co~mWrclaiOporatlon -~UuN11 _ OIFEIIOI12:1S Gasifllor·Eqt,~i~Commlnlonklv <>saeamT.m>lno1:11Rolr I MJUNU . . , e.art BJ • . • •·- c.ur..... Sl1o w""' 1SJAN1l -... •• • · · - GHK•tP:srtic'LIIata:ConllatDevk:o-$'~~ I 1SOCTir- F • ClUiriOISyngasCoolo<·Fal>riQtlon • 1:1JA/11!2" 15JUL1Z' fi'S301 Run Dolo I Gulflor•DotiQEngl..-lnaa.P-nt ' 01:iiJNI2 : lSFEStz. - o . -.............. ,.,. _ fl'a311 .""""""·IS- I 15JUL12" FP4C15 FI"'II FPSG?'O FP4DU = • I DIJUNIZ 1 lOD£C11 FP4040 - ··-fP.cQii- - 1 1SJUL1i"' 01JUN11 D1JUL11' 01AUG11' iiAUG11' ~~sC:rrrJ:~ij'LI~~=:J I ·= PSCCcrVflc:a11on I ' FEEO()pllmlatlom ' """"iiiiAV11' - -iiJiiL12- FPSHa 1 GulllotFEEO ~KBABatoCostEsdmotoC........,. •uPC Go.We>Ga Doctslon f-~~ii l$Wiii11• - · -FP2iii4 ·- : "'lfu-:-rtrn~Wrrrrlrrr,. "''·' I T!lii£cot Of.i"ANoiA C--··-""riod2 - -- IF~ II II ! -~- FPC3U 2:~rnrhm,0r'" -. ~~l!l.ar CriUc:ol Acllvlty S-.t,.,,l MPa1 SoolthcmCompanyGonorollon MPC IGC:C. KEMPERC:OUNTY DOE $Ummary R~ F1.gure 1 c::===============::::::=:::l Flnal,..pon.&Cioscouto = · . , ,. . - """ j •--: -... . ·I --· ,. _J _""':'"" c ... I ~~=~-~~~~~~~~~~~~~-g~~§~~~~ - _ _ _ _ __ ... ~ Lrnuh...,t hCI'IO'Irt to c:.onu."' con&!...,hal bu~U'I..~'\ tnfnmuuon ....-h~ch •i tn b-: ..,thhdJ rrum d~\mun: f'IUtJ.dc- th..: ll.$.. C.ifn"\·nttncnr 10 ,,,~ C'.IL"nt p~o."mttnN br b.w SoCo FOIA Response 001684 S.1U1h~'" C'"..t,mfunr $cmcr~. lttc Stac- Chu1p- k''iuur --I•Jgr So' 17 Ill!.· I C.:2f,.Uf,NT.;2\1Jl f!'tbNtt)'~XUC OVERALL PROJECT COST ESTIMATE FOR THE NEW SITE Costs have been re-estimated for the overall project based on the Kemper County site and include the proposed structurnl ch11nges described in the previous section. Table I shows an overall summary of the estimated project costs with a breakdown by Phnse nnd Budget Period. (b) (4) (b) (4) , I The cost estimate was prepared in 2006 to supp011 a Section 48A Application for DOE Certification associated with investment tax credits and was updated in 2007. The estimate was based on a combination of the following parts. • Southern Company's combined cycle reference plant was used with site specific adjustments and updated major equipment costs by SCS Engineering and Construction Services o base reference plant costs were in 2006 dollars o major equipment in nominal dollars • Gasification balance of plant estimate prepared by SCS Engineering and Construction Services with base costs in 2006 dollars • Gasification Island cost estimate was derived from the original estimate for the Orlando Gasilication Project based on the following: o base costs in 2004 dollars o equipment list was modified for new equipment sparing and capacities based on n 2xl project with lignite instead ofPRB o equipment cost was scaled using cost capacity factors o some equipment cost derived from new vendor quotes o bulks scaled based on change from a IxI to a 2x I faci Iity. and cost capacity fncto1·s based on system capacity changes o indirect costs scaled to a 2x I project with improved economies of scale applied for the integrated project o escalation of2004 pricing to 2006 pricing as a line item bused on historical data • Projected escalation was applied to the base 2006 dollars to the projected point of expenditure and wns included as a line item • Startup costs based on Southern Company IGCC O&M model with sitespcei tic fuel pricing • In 2007, an additional(b) (4) applied as escalation as part of a genc1·al cost update • In 2007, an additional (b) (4) added to estimate due to changes in sulfur removal system design during FEED SoCo FOIA Response 001685 I -1- t... • ...J ~ I .. l)E·I=<:UI•II6NT.a2\1Jl Swlhcm C""'l""!' S.."n'OC<,_Inc Sit< Clw1J:< ltct - l':ti:< 6 of 17 Fcbtu.Sn.•311~ Table 1 -Overall Cost Summary Budget Period 1 Actual Budget Period 2A Budget Period 2B Budget Period 3 Projected Proposed Total Cooperative Agreement Amendment A003 Federal Cost Share % 50% 45% 18.3% 13.4% 18.1% 34.8% Non-Federal Cost Share % 50% 55% 81.7% 86.6% 81.9% 65.2% Federal Cost Share S 9,282.200 15,108,608 218,995,303 50.363,889 293 750,000 293,750,000 Non-Federal Cost Share $ 9,282,200 18,466,077 978,793,603 324,790,161 1,331,332,040 550,517,321 Total 18,564,400 33,574,685 1,197,788,906 375,154,050 1,625,082,040 844,267,321 I Phase 1 Breakdown by Phase 18,564.400 18 564,400 Phase2A 11,368,883 11,368,883 Phase3A 22,205,801 22 205 801 Phase 28 271 ,649 271 649 Phase38 1.197.517.256 1,197,517,256 Phase4 Total 375,154,050 18,564,400 33,574,685 .. 375,154,050 1,197,788,906 ·---=~z.s,154,o5Q . _j ,62?,0~2.~0 . ·•ne R4'<~r COtl,..de1, rht- rtWenal NmW\cd hrn:if'l to ccm:bm c-tml~t.al b,~n"" inrunmriort • ·hte:h '" m b.:- W1thhdd frnm ~lc:t"·I'<:ZG-C16NH~ \')I f(hf\luyl'UR 2013 2014 2015 2016 2017 Subcontracts/Outside Services Fuel and Related Costs Coal $ Natural Gas $ Ash Disposal $ Major Equipment Service Agreements s Total Subcontracts Materials (b) (4) (b) (4) Est maled Hours of Gaslner Operalion V. Expendable Process Materials and Subcontracts Operations Process Materials Sulfur Solvent Usagenoss $ Olf·road Diesel $ Sand (bed Molorial) s liquid Nilrogen $ lol.cils (b) (4) Maintenance Related Parts and Matelials Repair Parts CostS Preventive Maintenance Parts S Outage Parts and Contractor labOrS lubricants S Gas Analyzer Calibration Gases S Condenser Cleaning System Supplies $ S $ $ S $ s tolals $ Total materials Pro oct Totals J (b) (4) (b) (4) (b) (4) . .j SoCo FOIA Response 001690 ~ .... thcrn (.umrtn.r~nKr-•, Jn( . Slftt Oun,;r ltup("Jf - l' .af:r 11 uf 17 J)l~· H::·u,.tlf'oNT.l2 l'JI l:t:bf'UJ')" ~···· SITE DESCRIPTION, SUITABILITY AND OWNERSHIP The plant site will be located near the unincorporated community of Liberty in Kemper County, Mississippi on or about latitude 32° 38' Nand longitude 88° 46'W. The site, totaling approximately I ,650 acres, is currently controlled by MPC via ownership or option to purchase agreements with current landowners. The land where the plant will be located is relatively nat with slight rolling termin. Current land use of the site and surrounding area is agriculture and primarily timbcl"land. Of the 1,650-acre site, less than 300 acres will be used in development of the plant. The plant footprint is expected to occupy 80 acres including the gasitier and combined-cycle power block and the lignite-handling facilities. MPC is currently investigating plans to use the ash in the reclamation process of the lignite reserve. However, an area of the overall plant site has been reserved for ash stornge that is sufficient for the first 5 years of operation. The properly under option also includes space requil·cd for temporary activities such 11s constnrction lnydown. The major infrastructure available to the site includes tmnsmission, watet·, gas, and lignite. The proposed site is located 20 miles north of interstate 1-20/59 and adjacent to State Route 493. It is also 22 miles north of Meridian Regional Airport. AI! infrastructure requirements put forth in the EPAcl of2005 nrc available with some rightof-ways to construct. The availability of each infrastructure is outlined below. Transmission MPC currently owns and operates n)lproximately 2,090 miles of transmission circuit (46,000 volts and higher) including over 600 miles of230,000-volt (230 kV) transmission circuits. Transmission facilities owned by MPC nrc interconnected to the other operating companies within Southern Company as well as to Entergy and two electric power associations. As shown in Figure 2, the proposed site of the IGCC plant is located approximately 17.5 miles north of an existing MPC 230 kV transmission circuit. SoCo FOIA Response 001691 ~-ulhcm (•Jm(Uil)" ~C'fncrf, lnr Str,· C.:h•nr.t" R('i\ICJ.t- P11~ l2 n( 17 Df!.FC:lti ll(iNT-12]'.11 f.cbruuy ~kl8 \91 Kemper County Proposed IGCC Plant Site -17.5 Miles Lauderdale County Meridian Figure 2 Proximity_to Transmission Southern Company Operating Companies that intend to construct, own, and operate a new generating facility to meet the rcsomcc needs of its native load customers are required to designate the new facility as a Network Resource and evaluate and provide the capability to deliver energy to the load fi·omthe designated Network Resource. The Operating Company (in this case, MPC) may make a Native Load Reservation (NLR) on the Southem Company Open Access Same-time lnfonnntion System ("OASIS") in order to provide such capability for planning and designing the transmission system to allow for future load growth. On March 22, 2006, such n formal request was made fot· a NLR fot· 600 MW in Kemper County, Mississippi, for the purpose of serving MPC's current and future native load customers. Confirmation of this request can be found by viewing the Southern Company OASIS Website, specifically referencing OASIS #603928. For more information about the Southern Company OASIS, please refer to the web-link "www.weboasis.com/OA SIS/S OCO/." The preliminary proposal for interconnection of the facility includes construction of new transmission circuits on new corridors along with the associated substations required to tie to the nearest existing 230-kV circuits. MPC will acquire allnecessnry right-of-way in order to interconnect and integrate the new power plant into its existing transmission network. SoCo FOIA Response 001692 ~OUaJ\un f:umrln)' ~t.:n IC~t, rnc. :o;itc(Jun~:c KnturH - l 1 &~"'t' l.ltlfl7 llE·I'OI.t>GNHH~I Fcb:U2Cf 2111., Water Supply The pl'imary water source for the facility is available from deep aquifer systems underlying the site oflhe facility. The water supply will be accessed by deep wells drilled to approximately 3,000 feet into the lower Tuscaloosa formation in an area referred to as the Massive Sands. This water source is the same as is used for other power generation in the vicinity. The water quality is non-potable and will have to be treated to be acceptable for use as make-up water. Preliminary studies indicate the water source to be sufficient in quantity and quality for the facility. The total usage requirement will be approximately 6.0 Mgal/dny, although I .3 Mgnl/day is recovered from the waste water treatment plant. Gas Supply Proximity to a source of natural gas is necessary for start-up operation and during maintenance of the gasifier. The site offers two potential sources for natural gas supply. One alternative would require n substantial upgmde to Southern Natural Gas (SON AT) pipelines located on the site property. Additionally, Tennessee Gas piJ>elines are located approximately 6 miles east of the site property. Either alternative will be suitable for the proposed site; however, final selection of a supplier will be determined based on economics of each supplier. Lignite Supply The site is adjacent to a lignite reserve identified as the "Damascus Prospect" by North American Coal Corporation (NAC). NAC has an existing lignite mining operation in Choctaw County, Mississippi, called the Red Hills Project. NAC has seen a very receptive local community to the Red Hills Project. Issues that have arisen have been t·esolved in a positive rmmner. In addition, NAC has made every effort to be a "good corporate citizen." At Red Hills, NAC has had no significant issues relating to land, leasing, and/or permitting and has similar expectations for the Kemper· County project. Given such, NAC has a mine plan for the "Damascus Project" that delivers 3.6-4.3 million tons of lignite to the proposed facility per year for 30 years. .. I Proximity to a railroad is not a requirement of the facility. As a mine-mouth operation, primary fuel delivery will be by off road truck ot· overland conveyor. As consideration for possible future operations or equipment delivery, the Kansas City Southern Railroad has tracks 16 miles east of the site. Norfolk Southern is also available in the City of Meridian, approximately 20 miles south of the site. Proximity to rail is n·ot considered to be a measure of site suitability. SoCo FOIA Response 001693 Sou1hcm Cump.utr ~n·,rt.., Inc S11~ ( h.an~c R«tuUt l'J£t 1-4 nf 17 m;:. rc;u.ooc.NH1J~r r.r."'ur:zo~m Environmental The project site in Kemper County will fully meet all cnvimnmcntal requirements. MPC is an environmental lender with n proven trnck record of environmental compliance when operating nn electrical generation fleet. Preliminary discussions with state environmental officials were very productive with commitments to help secure the necessary site environmental permits in a timely manner. MPC has successfully secured these types of envimnmental permits as part of its nonnnl fleet operations and after consultation with State environmental officials, all of these permits are obtainable for the proposed facility. The air permit application was filed in December of2007 and the air permit is expected to be issued by November 2008. OTHER BENEFITS OF THE SITE IN KEMPER COUNTY Strategic bcnetits associated with the project include titel diversity for MPC, increased reliability due to geographical diversity, advancing gnsification technology, utilization of a natural resource of Mississippi, and the economic development of an economically depressed area. Increased Fuel Diversity With the addition of a lignite-fueled generating facility, this project would enable MPC to reduce dependency on natural gas-fired generntion and cnhnnce cnct·gy mix. Currently, MPC does not own any generating plant with lignite as the primary feedstock. Overall, this increased fuel diversity would lead to less sensitivity to natural gas price volatility resulting in lower costs for MPC customers. Figure 3 illustrates the fuel diversity the plant brings to MPC customers. U.efel'ence Cnsc IGCC Li~nitc Cnse Yei'U ' 2014 rO Gas a c oal o Oiher oGas o lignite mcoal D Other Figure 3 MPC 2014 Energy Mix SoCo FOIA Response 001694 l>!;·l"l:2Ml(oNH2\?I Fnurl· 2fk>ft St.ulhcrn Cumr1t1J" Scn'"'ltCII.Inc l•.a,~~ U v( J7 Sne C:h.tl'l~ Nt'{UCU - Geographical Diversity The JGCC facility will be interconnected to the northern portion of MPC's service territory nnd would be the f.1rthest MPC-owned generating plant from the Gulf Coast, thus easing the dependence on generating facilities close to the canst and their susceptibility to hurl'icanes. This would also increase the reliability in a region of the state where pumping stations are located that provide petroleum to the northcm United States. Economic Development ~ The State of Mississippi would also greatly benefit in the form of economic development activities related to the project, such as inerensed tax revenues and the addition ofjobs in a rural, economically-disadvantaged area. It is estimated that this generating f.1cility would employ approximately 90-100 directjobs and up to 152 combined (direct and indirect) jobs once construction is completed. During construction, thca·e would be an average of 525 jobs available for a period of approximately 37 months with a peak of approximately I 000 jobs for a period of9 months. In addition to the jobs created by the generating facility, it is estimated that an additional I00 to 180 jobs will be created by the mining opemtion. UTILIZATION OF PROJECT ELECTRICITY OUTPUT It is expected that MPC will have a need for new generation in the 2013 timeframe. This need is driven by increased load growth and the planned retirement of aging, gas-fired capacity. The capacity targeted for retirement consists of I0 units whose ages will range from 42 to 68 years by the time the pt·oject goes into conunercial operation in 2013. The output capacity of the plant will be predominately utilized by MPC to serve retail and wholesale customers. The plant, being part of the Southern Company's economic dispatch, will be available to make sales to both affiliates and non-affiliate companies. These sales will benefit MPC's regulated retail and wholesale customers. Energy Sales Agreement Although the current expectation of output utilization from the plant docs not require tlll energy sales agreement, MPC would consider and explore the possibility of entering into a Power Purchase Agreement (PPA) with another utility or third party should nn opportunity arise. Energy Price Markel Study At this time, no Energy Price Market Study is re Thursday, February 14, 2008 12:50 PM Madden, Diane Fwd: Southern Company Package to Secretary Bodman DOE FEB 25 Requests (SRev) (2)Monday.doc >>>"Rush, Randall E." 2114/2008 I 1:18AM>>> As part of preparation for the meeting on 2/25 (or 2/26 not sure which) between Secretary Bodman, Southern CEO David Ratcliffe, Mississippi Power CEO Anthony Topazi and Governor Barbour of Mississippi a package related to funding for the TRIG demo in Kemper County is being delivered to the Secretary's office today. Attached is the summary document. There is more material in the package, but l do not yet have it. When I do l will get you copies. I am happy to discuss. <> Randall E. Rush General Manager, Gasification Technology Southern Company Generation 42 Inverness Center Parkway Birmingham, AL 3SZ42 * Internal: 8-992-6319 * External: (206) 992-63I9 * Cell: ( (b) (6) * Fax: (206) 992-6005 E-mail: rerush@southernco.com SoCo FOIA Response 001698 Southern Company's Mississippi Project Answering the Department of Energy's Call For Action Southern Company is prepared to demonstrate the advanced coal gasification technology, TRIG™, in Kemper County Mississippi. This technology, developed in partnership with the Department, was previously proposed in Orlando, Florida. Southern believes this project will be a clear and dramatic response to the Department's goals of clean, secure, domestic energy for America. The Mississippi Project has been under development for over a year and was positioned with its 2013 commercial operation date to benefit from the first-of-a-kind risks and costs that the Orlando Project was to bear and help resolve. With the Orlando cancellation, the Mississippi Project, which is twice the size of Orlando, now becomes the commercial demonstration of TRIG rt.t, and requires the following assistance from the Department to proceed. (Appendices 1, 2) I. Southern requests the Department's approval of a site change from Orlando to Mississippi and use of remaining CCPI funds (-$270MM) by March 31, 2008. A. The Department has the authority to act based on: • Principle - Has the authority to change a project's characteristics (in this case location) as long as the public interest is at least as well served as originally planned, and the site change does not increase the overall cost to the Department or the percentage of the total project cost funded by the Department. (Appendix 3) • B. Precedence- Has dealt positively with such transfer requests previously, having approved 12 site change requests since 1989. Southern is unaware of a site change request that met the requirements being denied. (Appendix 4) The Mississippi Project satisfies the objectives of the original grant in demonstrating advanced gasification technology and creates greater opportunities for commercialization by demonstrating lignite as well as PRB. Objective Demonstrate New Technology Demonstrate Gasification of Low Rank Coals Demonstrate Commercial Scale Total Capital DOE % Contribution Orlando TRIGTM PRB 285MW -$700MM -35% Mississi~~i TRIG™ Lignite and PRB -580 MW >$1,300MM -18% SoCo FOIA Response 001699 C. The Mississippi Project site provides a greater chance of commercial success and achievement of the Department's goals for America. • The Governor and State are committed to the project because of its economic impact to a depressed region of Mississippi and for the opportunity to participate in technology development. This project is a significant step in achieving the Governor's Energy Strategy for Mississippi. • Mississippi is ideal for demonstrating Carbon Capture and Sequestration. Excellent geological formations. (Appendices s. s. 11 Naturally sequestered C02 is currently being pumped out of the Jackson Dome in Mississippi for enhanced oil recovery and provides a unique opportunity for CCS. (Appendices a. 9) - The right of eminent domain for C02 pipelines already exists in Mississippi. (Appendix 10) Potential to supply anthropogenic C02 to SECARB Phase Ill project. II. • Demonstrating the use of lignite (as well as PRB} will open up the opportunity to use this largely underutilized resource which runs from Texas to Alabama to meet our nation's energy requirements. (Appendix 111 • The Mississippi site increases service reliability to facilities of national interest, including Colonial and Plantation Pipeline Companies' critical pumping facilities near Collins, MS. (Appendices 12. 13) Southern Company requests the Department expedite the NEPA Review required for the Site Change Application and for the Loan Guarantee Program. A satisfactory Record of Decision is required not only for the site change, but also for the loan guarantee the Mississippi Project qualified for under EPA 2005. Project viability hinges on these funds. Southern is proceeding with developmental activities. The longer the two NEPA processes take, the more money will have been spent and at risk. Southern asks the Department to insure that these two parallel processes be coordinated and expedited. 2 SoCo FOIA Response 001700 Ill. Southern Company requests that the Department exercise its authority to waive the CCPJ repayment obligation. A. B. As stated in the agreement, the Department may terminate the repayment obligation if "repayment places an Obligor at a competitive disadvantage in domestic or international markets." Without this waiver, or other financial support, this project will likely not be the least cost alternative for State certification and a competitive resource in the wholesale market. (Appendix 14} • The Mississippi Project is twice the scale and cost of Orlando, thus doubling its exposure to first-of-a-kind risks and costs. • The Department's participation, designed to help make Orlando competitive, was 34.8%, but would only be 18.1% for Mississippi with the funds transferred. • Orlando Utilities Commission which was to own 35% of Orlando is a tax exempt entity. Southern Company is a fully taxable entity and under current plans will own 100% of the Mississippi Project, thus making the project's tax exposure significantly greater and worsening the project's economic viability. Southern is pursuing the opportunity to include carbon capture controls beginning in 2013. In light of the additional cost associated with carbon capture, the repayment obligation further disadvantages this project. • The repayment obligation is inconsistent with recent Congressional action eliminating such requirements for clean coal demonstration projects and the CCS goals of CCPI 3, and creates a competitive disadvantage for this project. • Southern is developing a strategy for carbon capture of one million tons of C02 per year at Mississippi with exp~nsion as technology advances. • FEED study for C02 capture is already underway. • The Mississippi Project could provide the necessary C02 for sequestration associated with the SECARB Phase 3b proposal. • The Mississippi project can become the commercial demonstration site for the carbon capture research the Department and Southern are performing at PSDF. • Beyond the waiver, additional funds will likely be needed to help offset the added cost and loss of capacity to receive State certification as the least cost option. Summary Southern Company and the Department have partnered for several years in pursuit of clean, secure, domestic energy for America through our research and development of the TRIG'M technology. Its introduction into the marketplace with CCS capability can be a reality in 2013 with the Department's continued support of Southern Company's Mississippi Project. 3 SoCo FOIA Response 001701 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Brad Tomer Thursday, February 14, 2008 12:52 PM Madden, Diane; Russia), Thomas Fwd: FW: Southern Company Package to Secretary Bodman TEXT.htm; DOE FEB 25 Requests (SRev) (2)Monday.doc Diane and Tom, FYI Brad -----Original Message----From: Rush, Randall E. [mailto:RERUSH@southernco.com) Sent: Thursday, February 14, 2008 11:19 AM To: Bauer, Carl; Der, Victor Cc: russial@netl.doe.gov Subject: Southern Company Package to Secretary Bodman As part of preparation for the meeting on 2/25 (or 2/26 not sure which) between Secretary Bodman, Southern CEO David Ratcliffe, Mississippi Power CEO Anthony Topazi and Governor Barbour of Mississippi a package related to funding for the TRIG demo In Kemper County Is being delivered to the Secretary's office today. Attached is the summary document. There is more material in the package, but I do not yet have it. When I do I will gel you copies. am happy to discuss. «DOE FEB 25 Requests (5Rev) (2)Monday.doc» . ~ I Randall E. Rush General Manager, Gasification Technology Southern Company Generation 42 Inverness Center Parkway Birmingham, Al 35242 * Internal: 8-992-6319 External: (205) 992-6319 (b) (6) Cell: (205) 992-6005 Fax: E-mail: rerush@southernco.com SoCo FOIA Response 001702 Southern Company's Mississippi Project Answcr·ing the Department of Energy's Call For Action Southern Company is prepared to demonstrate the advanced coal gasification technology, TRIGTM, in Kemper County Mississippi. This technology, developed in partnership with the Department, was previously proposed in Orlando, Florida. Southern believes this project will be a clear and dramatic response to the Department's goals of clean, secure, domestic energy for America. The Mississippi Project has been under development for over a year and was positioned with its 2013 commercial operation date to benefit from the first-of-a-kind risks and costs that the Orlando Project was to bear and help resolve. With the Orlando cancellation, the Mississippi Project, which is twice the size of Orlando, now becomes the commercial demonstration of TRIGTM, and requires the following assistance from the Department to proceed . (Appendices 1. 2) I. Southern requests the Department's approval of a site change from Orlando to Mississippi and use of remaining CCPI funds (-$270MM) by March 31, 2008. A. The Department has the authority to act based on: • Principle - Has the authority to change a project's characteristics (in this case location) as long as the public interest is at least as well served as originally planned, and the site change does not increase the overall cost to the Department or the percentage of the total project cost funded by the Department. (Appendix 3) • B. Precedence - Has dealt positively with such transfer requests previously, having approved 12 site change requests since 1989. Southern is unaware of a site change request that met the requirements being denied. (Appendix 4) The Mississippi Project satisfies the objectives of the original grant in demonstrating advanced gasification technology and creates greater opportunities for commercialization by demonstrating lignite as well as PRB. Objective ; I Demonstrate New Technology Demonstrate Gasification of Low Rank Coals Demonstrate Commercial Scale Total Capital DOE % Contribution Orlando TRIG™ PRB 285MW -$700MM -35% Mississteei TRIG™ Lignite and PRB -580 MW >$1,300MM -18% SoCo FOIA Response 001703 C. The Mississippi Project site provides a greater chance of commercial success and achievement of the Department's goals for America. • The Governor and State are committed to the project because of its economic impact to a depressed region of Mississippi and for the opportunity to participate in technology development. This project is a significant step in achieving the Governor's Energy Strategy for Mississippi. • Mississippi is ideal for demonstrating Carbon Capture and Sequestration. - Excellent geological formations. - Naturally sequestered C02 is currently being pumped out of the Jackson Dome in Mississippi for enhanced oil recovery and provides a unique Opportunity for CCS. (Appendices B, 9) - The right of eminent domain for C02 pipelines already exists' in Mississippi. (Appendices s. G. 71 (Appendfll 10) Potential to supply anthropogenic C02 to SECARB Phase Ill project. II. • Demonstrating the use of lignite (as well as PRB) will open up the opportunity to use this largely underutilized resource which runs from Texas to Alabama to meet our nation's energy requirements. (Appendbc 111 • The Mississippi site increases service reliability to facilities of national interest, including Colonial and Plantation Pipeline Companies' critical pumping facilities near Collins, MS. (Appendices 12, 13) Southern Company requests the Department expedite the NEPA Review required for the Site Change Application and for the Loan Guarantee Program. A satisfactory Record of Decision is required not only for the site change, but also for the Joan guarantee the Mississippi Project qualified for under EPA 2005. Project viability hinges on these funds. Southern is proceeding with developmental activities. The longer the two NEPA processes take, the more money will have been spent and at risk. Southern asks the Department to insure that these two parallel processes be coordinated and expedited. 2 SoCo FOIA Response 001704 Ill. Southern Company requests that the Department exercise its authority to waive the CCPI repayment obligation. A. B. As stated in the agreement, the Department may terminate the repayment obligation if "repayment places an Obligor at a competitive disadvantage in domestic or international markets." Without this waiver, or other financial support, this project will likely not be the least cost alternative for State certification and a competitive resource in the wholesale market. (Appendix 14) • The Mississippi Project is twice the scale and cost of Orlando, thus doubling its exposure to first-of-a-kind risks and costs. • The Department's participation, designed to help make Orlando competitive, was 34.8%, but would only be 18.1% for Mississippi with the funds transferred. • Orlando Utilities Commission which was to own 35% of Orlando is a tax exempt entity. Southern Company is a fully taxable entity and under current plans will own 100% of the Mississippi Project, thus making the project's tax exposure significantly greater and worsening the project's economic viability. Southern is pursuing the opportunity to include carbon capture controls beginning in 2013. In light of the additional cost associated with carbon capture, the repayment obligation further disadvantages this project. • The repayment obligation is inconsistent with recent Congressional action eliminating such requirements for clean coal demonstration projects and the CCS goals of CCPI 3, and creates a competitive disadvantage for this project. • Southern is developing a strategy for carbon capture of one million tons of C02 per year at Mississippi with expansion as technology advances. • FEED study for C02 capture is already underway. • The Mississippi Project could provide the necessary C02 for sequestration associated with the SECARB Phase 3b proposal. • The Mississippi project can become the commercial demonstration site for the carbon capture research the Department and Southern are performing at PSDF. • Beyond the waiver, additional funds will likely be needed to help offset the added cost and loss of capacity to receive State certification as the least cost option. Summary Southern Company and the Department have partnered for several years in pursuit of clean, secure, domestic energy for America through our research and development of the TRIG TM technology. Its introduction into the marketplace with CCS capability can be a reality in 2013 with the Department's continued support of Southern Company's Mississippi Project. 3 SoCo FOIA Response 001705 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: "Henderson, Charles W." Thursday, February 21, 2008 2:56 PM Robbins, Brittley Falletta, Donald C.; Ellison, David H.; Madden, Diane RE: FW: OGP File Retention ATT18802l.jpg Hello Brlttley, My confusion was centered around when the clock started due to the site change and the fact that the cooperative agreement was continuous from Orlando to Mississippi. Your explanation has been very helpful. Thanks, Charles Henderson Admin & l'rojcct Support Mnnngcr Gnsiricnlion Tcd1nology 8-824-5844- Wllson\'lllc (b) (6) 8·992-7313- 111\'CI"IICSS (205) 992-7313 From: Brittley Robbins [mallto:Brlttley.Robblns@NETLDOE.GOV] Sent: Wednesday, February 20, 2008 2:14PM To: Henderson, Charles W. Cc: Madden, Diane Subject: Re: FW: OGP Ale Retention Hi Charles, The retention requirements for this project are set forth In the clause entitled "Records Retention, Access, and Disclosure" In the cooperative agreement. I have excerpted that clause - see attached. Even though the Orlando portion of the work Is being terminated, It Is still considered to be a part of this cooperative agreement, which Is potentially ongoing {to the Mississippi site). Basically, all information associated with the Orlando work must be retained for the same amount of time as the Information associated with the Mississippi portion of the work {If authorization is provided by DOE to relocate the site). To get a little bit more specific, the clause states, "The period of required retention shall be from the date each such record Is created or received by the Recipient until three years after one of the following date~ whichever Is latest: the expiration date of this Cooperative Agreement; the date the Recipient's final expenditure report is submitted to DOE; or if this Cooperative Agreement Is terminated in its entirety, the effective date of the termination." Orlando records will need to be retained for the latest of the above dates. Keep In mind those dates apply to the cooperative agreement as a whole and not just the Orlando work. I hope that clarifies lt. It was a bit difficult to put In writing. If I have confused you, please let me know. Brlttley Robbins SoCo FOIA Response 001706 Contract Specialist, DOE-NETL Acqulslllon and Assistance Division (412) 386-5430 >>>"Henderson, Charles W." 2/15/2008 2:35PM>>> Brittley I meant to copy you on this Instead of Lisa Kuzniar. I apologize for this error. Thanks, Charles Henderson Ad111ln & l'rojcct Support Mnnngca· Gn.slflcntlon Technology (b) (6) 8-992-7313- Inverness (205) 992-7313 From: Henderson, Charles W. Sent: Friday, February 15, 2008 11:33 AM To: Diane Madden Cc: 'LISA.KUZNIAR@NETL.DOE.GOV' Subject: FW: OGP File Retention DianeWho do I need to talk with concerning DOE retention requirements for the Orlando Gasifier project records? It gets complicated with the potential extension of the cooperative agreement to Include the Mississippi Gasifier project. I think determining the lengths for different types of records (drawings, procurement documents, cost and schedule data, etc...) and when the clock starts are topics I want to discuss. Would this be Andy Ferllc? Let me know and we can set up a time to discuss. Thanks, Charles Henderson Admin & l'•·oject Support Mnnngcr Gnslficntion Technology 8-824-5844- Wilsonville (b) (6) 8-992-7313 • hn·ea·ncss (205) 992· 7313 From: Falletta, Donald C. Sent: Friday, February 15, 2008 10:40 AM To: Dollar, Stephanie C. Cc: Hornbuckle, Richard D.; Ellison, David H.; McDonald, Karen W.; Henderson, Charles W.; Pruitt, S. Jeff; Pinkston, Tim E. Subject: RE: OGP File Retention 2 SoCo FOIA Response 001707 I will have to get back to you. This was a DOE funded project, and DOE may have other retention requirements. To complicate things further, we are working to extend the DOE contract for funding another project, Kemper County Mississippi Gasification Project (MGP). MGP is in its infancy, and may be ongoing for many years. I will get back to you ASAP. Sorry. Don Falletta Southern COOIP'RY Generation, E&CS Gasification Technology Electncal 8o Controls • Senior Englnecr lntemet Address •• m~o:dcfallel@southcrnc~ Intercompany .. 8-992-7674 ~~~Phone .. Cell . 205 992-7674 (b) (6) -----Original Message----From: Dollar, Stephanie C. Sent: Friday, February I 5, 2008 I0:18 AM To: Falletta, Donald C. Subject: RE: OGP File Retention I have keyed in your box for offsite storage. I want to be sure that I have the retention correct for this box. I have the "event date" as 12/31/07 (we generally push to the end of the year), giving us a destruction date of 12/31/2013. This is a retention period of 6 years. It wns my understnnding that this is the conect period, but I wanted to check with you one more time before I send this box offsite. Stephanie ··---Original Message----From: Falletta, Donald C. Sent: Friday, Febntary IS, 2008 9:56AM To: Dollar, Stephanie C. Subject: Rc: OGP File Retention The Orlando Gasification Project (OGP) started around January 2006. •sent from my Blackberry* Don Falletta 3 SoCo FOIA Response 001708 Southern Company Generation, E&CS Gasification Technology Electrical & Controls - Senior Engineer Email: dcfallct@southernco.com Desk: 205.992.7674 Cell: (b) (6) -----Original Message----From: Dollar, Stephanie C. To: Falletta, Donald C. Sent: Fri Feb I 5 09:50:08 2008 Subject: FW: OGP File Retention Don--Can you give me a rough start-time for this project? I sec the end date below, but not a starting date. Thanks!! Stephanie L. Dollar Southern Company Generation Project Support Analyst--Document Services Phone: 205-992-6627 From: McDonald, Karen W. Sent: Thursday, February 14, 2008 I 1:34 AM To: Dollar, Stephanie C. Subject: FW: OGP File Retention Information for the box I'm about to put in your office is below. Thanks! From: Falletta, Donald C. Sent: Thursday, February 14, 2008 II: 17 AM To: McDonald, Karen W. Cc: Pruitt, S. Jeff; Hombuckle, Richard D.; Johnstone, John P.; Wingo, Brett; Pinkston, Tim E. Subject: FW: OGP File Retention Instructions for Document Services on OGP File Retention Effort • Charge Number: 9091 LS. (b) (4) SoCo FOIA Response 001709 (b) (4) Please call if you have any questions. Thank You, Don Falletta <> Southern Company Gcnemtion, E&CS Gasification Technology Electrical & Controls - Senior Engineer Internet Address -- mailto:dcfallct(a>.southcrnco.com Intercompany-- 8-992-7674 Bell Phone-- 205-992-7674 Cell -- (b) (6) From: Hornbuckle, Richard D. Sent: Wednesday, February 13,2008 12:15 PM To: Falletta, Donald C. Subject: FW: OGP File Retention 5 SoCo FOIA Response 001710 Don, please answer Karen. You may want to go down and talk to them directly. Let me know when they plan to get started. The only hard copy box I know about at the moment is the (b) (4)documents in the supply area next to your office. I want to review my stuff and see if there is anything I want to archive hardcopy, but offhand can't think of anything. The box(es) (in my mind) should be identified by the origination source only. We do not want to expend time listing or inventorying each box contents. The(b) (4) ox, for instance should only be identified as (b) (4) Richard Hornbuckle SCS Gasification Technology office (205) 992-6369 cell (b) (6) From: McDonald, Karen W. Sent: Wednesday, Fcbmary 13,2008 12:04 PM To: Hornbuckle, Richard D.; Pruitt, S. Jeff Cc: Falletta, Donald C.; Wingo, Brett; Pinkston, Tim E.; Miller, Paul H. Subject: RE: OGP File Retention Thanks, Richard. Is the s: drive set up and ready for us to begin? receive the boxes? Also, when do you think we will Look forward to completing this project for you. Karen From: Hornbuckle, Richard D. Sent: Wednesday, February 13,2008 12:02 PM To: McDonald, Karen W.; Pruitt, S. Jeff Cc: Falletta, Donald C.; Wingo, Brett; Pinkston, Tim E.; Miller, Paul H. Subject: OGP File Retention Based on a maximum cost estimate of 80 hours total for both groups, please proceed to migrate the OGP files to document control archive (documentum) and pmcess hard copy boxes. Your contact at Inverness will be Don Falletta so please keep him informed on progress and completion. I would also like to know the number of hours charged once both groups are complete. If it looks like it will take close to or over 80 hours, please advise Don before going over this budget. Brett Wingo and I are temporarily assigned to the PSDF. Richard Hornbuckle 6 SoCo FOIA Response 001711 SCS Gasification Technology office (205) 992-6396 cell (b) (6) This document contains proprietary, confidential, and/or trade secret information of the subsidiaries of Southern Company m· of third parties. It is intended for use only by employees ot: or authorized contractors of, subsidiaries of Southern Company. Unauthorized possession, use, distl'ibution, copying, dissemination, or disclosure of any portion is prohibited. 7 SoCo FOIA Response 001712 From: Sent: To: Cc: Subject: Attachments: "Pinkston, Tim E." Friday, March 14, 2008 3:07 PM Robbins, Brittley; Madden, Diane Henderson, Charles W.; Rush, Randall E. RE: Site Change Request for Cooperative Agreement DE-FC26-06NT42391 TEXT.htm; Financial Models.zip The file containing the financial models Is attached. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) From: Pinkston, Tim E. Sent: Friday, March 14, 2008 3:01PM To: 'Brittley Robbins'; Diane Madden Cc: Henderson, Charles W.; Rush, Randall E. Subject: RE: Site Change Request for Cooperative Agreement DE-FC26-06NT42391 The additional information that you requested concerning the Site Change Request for Cooperative Agreement DE-FC26-06NT42391 is attached. Financial Model The tile named "Financial Summary Table.ppt" contains a summary of the results from the project financial model for several cases used in evaluating the overall project economics and risks associated with first-of-a-kind technology and C02 regulation. We are currently modeling additional cases for inclusion in the table. I will forward an updated version of the summary next week with of all of the additional cases. The table groups the cases into three categories of risks associated with C02 regulation: C02 Tax of $Olton, C02 Tax of $1 Olton and C02 Tax of $201ton. The $Olton case was the expected case prior to the cancellation of the gasification island at the Orlando site. The $1 Olton and $201ton cases provide an overall perspective on the project economics when the risks associated with C02 regulation are considered. The base case in the table shows the net present value of the revenue requirements for a natural gas combined cycle plant. The net present value for each IGCC case is the difference between the IGCC revenue requirement and the revenue requirement for the natural gas combined cycle case. IGCC is preferred when the difference in revenue requirements is negative. Based on the cases in the table, approval of the Kemper County Site Change by DOE is required for the project to be the most economic choice. SoCo FOIA Response 001713 A file named "Financial Models.zip" contains the base case financial models for the natural gas combined cycle case with a C02 tax of$10/ton and the base IGCC case with a C02 tax of $1 Olton. This file will be sent in a separate email so that this email will not exceed size limitations. Funding Commitment Letter A letter from Mississippi Power Company (MPC) confirming that MPC will provide the non-federal cost sharing for the project is attached in the file named "MPC Letter.pdf'. The letter also states a commitment to the same site access requirements that were made for the Orlando site by the hosting entity. Agreement between Southern Company Services (SCS) and MPC The facility will be designed, procured and constructed by SCS under a Services Agreement dated January I, 1984 between MPC and SCS. The Services Agreement sets forth the terms and conditions pursuant to which SCS will render services to MPC in connection with the project. Pursuant to that agreement, SCS is authorized to (among other things) provide a wide range of financial, corporate, technical, and administrative services for MPC, and MPC agrees to reimburse SCS for all direct and indirect costs incurred by SCS in its activities on behalf of MPC. The agreement between SCS and MPC is attached in a file named "SCS- MPC Services Agreement.pdf'. A similar agreement was utilized between SCS and Southern Power Company for the previous Orlando site. (b) (4) Statement of Project Objectives (SOPO) A separate SOPO was prepared for each site and changes to the original SOPO are tracked. Documents for the Orlando and Kemper County sites are attached in files named "Statement of Project Objectives- Orlando.doc" and "Statement of Project Objectives- Kemper County.doc". The Orlando document has all the scope that will not be completed removed. In order to meet DOE's requirement that all the original objectives be met with the Kemper County site, the changes to the SOPO for Kemper County fall into the following general categories: • • • • • changing the scope to a 2x I system instead of I xI changing the scope to the entire IGCC and not just the gasification island changing the description of the project participants changing the description of the plant site and deleting the Phase I activities that were completed as part of the Orlando site. Please let me know if you have questions. Tim Pinkston Pr oject Ma nager Gasification Technology Southe rn Compa ny Generation Offi ce 205- 992- 50 42 Cell (b) (6) 2 SoCo FOIA Response 001714 From: Brittley Robbins [mailto:Brittley.Robbins@NETL.DOE.GOV] Sent: Wednesday, February 20, 2008 5:22 PM To: Rush, Randall E.; Pinkston, Tim E. Cc: Diane Madden; Henderson, Charles w. Subject: Re: Site Change Request for Cooperative Agreement DE-FC26-06NT42391 Dear Mr. Rush and Mr. Pinkston, DOE is currently reviewing the Information submitted by Southern Company on 2/14/2008 with regards to the proposed site relocation from Orlando, FL to Kemper County, MS. To further DOE's review of the proposed relocation, the following Is requested: 1. Additional information concerning the financing of the project (i.e., the finandal model) 2. Funding commitment letters for the private share 3. The agreement between Southern Company and Mississippi Power as well as the agreement between Southern Company and KBR. This information Is needed so that DOE can verify that Southern Company Is In a position to proceed with the project. Please submit this information as soon as possible but no later than March 14th. DOE also requires a revised Statement of Project Objectives (SOPO), the delivery of which Is not as critical as the three items listed above. Feel free to contact me with any questions and/or for darification, Brittley Robbins Contract Specialist, DOE-NETL Acquisition and Assistance Division ( 412) 386-5430 >>>"Pinkston, Tim E." 2/14/2008 10:50 AM>>> Brittley and Diane, Attached Is our request to change the site for the project under Cooperative Agreement DE-FC26-06NT42391 from Orlando, FL to Kemper County, MS. As requested, the document provides project cost information for the new site, a commitment letter from Mississippi Power, scope and objective information, a new schedule, an assessment of repayment Impacts, host site Information and a discussion of key project decision points. We look forward to continuing to work with you in demonstrating the TRIG technology. Let me know if you have questions or need more information. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) «Kemper County Site Change Request.pdf>> 3 SoCo FOIA Response 001715 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: "Pinkston, Tim E." Friday, March 14, 2008 4:07 PM Robbins, Brittley; Madden, Diane Henderson, Charles W.; Rush, Randall E. RE: Site Change Request for Cooperative Agreement DE· FC26-06NT42391 TEXT.htm; Financial Models.zip The file containing the financial models is attached. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205v992 · 5042 Cell (b) (6) From: Pinkston, Tim E. sent: Friday, March 14, 2008 3:01PM To: 'Brittley Robbins'; Diane Madden Cc: Henderson, Charles W.; Rush, Randall E. Subject: RE: Site Change Request for Cooperative Agreement DE-FC26-06NT42391 The additional information that you requested concerning the Site Change Request for Cooperative Agreement DE-FC26-06NT42391 is attached. Financial Model The file named "Financial Summary Table.ppt" contains a summary of the results from the project financial model for several cases used in evaluating the overall project economics and risks associated with first-of-a·kind technology and C02 regulation. We are cmrcntly modeling additional cases fo1· inclusion in the table. I wi II forward an updated version of the summary next week with of all of the additional cases. The table groups the cases into three categories of risks associated with C02 regulation: C02 Tax of $0/ton, C02 Tax of$1 Olton and C02 Tax of $20/ton. The $0/ton case was the expected case prior to the cancellation of the gasification island at the Orlando site. The $10/ton and $20/ton cases provide an overall perspective on the project economics when the risks associated with C02 regulation are considered. The base case in the table shows the net present value of the revenue requirements for a natural gas combined cycle plant. The net present value for each IGCC case is the difference between the JGCC revenue requirement and the revenue requirement for the natural gus combined cycle case. IGCC is preferred when the difference in revenue requirements is negative. Based on the cases in the table, approval of the Kemper County Site Change by DOE is required for the project to be the most economic choice. SoCo FOIA Response 001716 A file named "Financial Models.zip" contains the base case financial models for the natmal gas combined cycle case wilh a C02 tax of$10/ton and the base IGCC case with a C02 tax of $1 0/ton. This file will be sent in a separate email so that this email will not exceed size limitations. Funding Commitment Letter A letter from Mississippi Power Company (MPC) conlirming that MPC will provide the non-federal cost sharing for the project is attached in the file named "MPC Lettcr.pdf'. The letter also states a commitment to the same site access requirements that were made for the Orlando site by the hosting entity. Agreement between Southern Company Scn•iccs (SCS) nnd MPC The facility will be designed, procured and constructed by SCS under a Services Agreement dated January 1, 1984 between MPC and SCS. The Services Agreement sets forth the terms and conditions pursuant to which SCS will render services to MPC in connection with the project. Pursuant to that agreement, SCS is authot·ized to (among other things) provide a wide range of financial, corporate, technical, and administrative services for MPC, and MPC agrees to reimburse SCS for all direct and indirect costs incurred by SCS in its activities on behalf of MPC. The agreement between SCS and MPC is attached in a file named "SCS- MPC Services Agrecment.pdf'. A similar agreement was utilized between SCS and Southem Power Company for the previous Orlando site. (b) (4) Statement of Project Objectives (SOJ>O) A separate SOPO was prepurcd for each site and changes to the original SOPO arc tracked. Documents for the Orlando and Kemper County sites are attached in files named "Statement of Project Objectives- Orlando.doc" and "Statement of Project Objectives- Kemper County.doc". The Orlando document has all the scope that will not be completed removed. In order to meet DOE's requirement that all the original objectives be met with the Kemper County site, the changes to the SOPO for Kemper County fall into the following general categories: • • • • • changing the sco1>e to a 2x1 system instead of lxl changing the scope to the entire IGCC and not just the gasification island changing the description of the project participants changing the description of the plant site and deleting the Phase I activities that were completed as part of the Orlando site. Please let me know if you have questions. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) 2 SoCo FOIA Response 001717 From: Brittley Robbins [mailto:Brittley.Robbins@NETL.DOE.GOVJ Sent: Wednesday; February 20, 2008 5:22 PM To: Rush, Randall E.; Pinkston, Tim E. Cc: Diane Madden; Henderson, Charles W. Subject: Re: Site Change Request for Cooperative Agreement DE·FC26·06NT42391 Dear Mr. Rush and Mr. Pinkston, DOE is currently reviewing the Information submitted by Soulhern Company on 2/14/2008 with regards to the proposed site relocation from Orlando, FL to Kemper County, MS. To further DOE's review of the proposed relocation, the following is requested: 1. Additional information concerning the financing of the project (i.e., the financial model) 2. Funding commitment letters for the private share 3. The agreement between Southern Company and Mississippi Power as well as the agreement between Southern Company and KBR. This Information Is needed so that DOE can verify that Southern Company is In a position to proceed with the project. Please submit this Information as soon as possible but no later than March 14th. DOE also requires a revised Statement of Project Objectives (SOPO), the delivery of which is not as critical as the three Items listed above. Feel free to contact me with any questions and/or for clarification, Brittley Robbins Contract Specialist, DOE-NETL Acquisition and Assistance Division (412) 386-5430 >>>"Pinkston, Tim E." 2/14/2008 10:50 AM>>> Brlttley and Diane, Attached Is our request to change the site for the project under Cooperative Agreement DE·FC26-06NT42391 from Orlando, FL to Kemper County, MS. As requested, the document provides project cost Information for the new site, a commitment letter from Mississippi Power, scope and objective information, a new schedule, an assessment of repayment impacts, host site information and a discussion of key project decision points. We look forward to continuing to work with you In demonstrating the TRIG technology. let me know If you have questions or need more Information. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205·992-5042 Cell (b) (6) < > 3 SoCo FOIA Response 001718 From: Sent: To: Cc: Subject: Attachments: "Pinkston, Tim E." Tuesday, March 25, 2008 10:54 AM Madden, Diane RERUSH@southernco.com FW: Material sent to Tom Shope Re: Mississippi Power Kemper County TRIG Project Docl.doc; Kemper Case Assumptions and Methodology 3-13-0S.ppt Diane, The answers to your questions concerning slides 1 and 2 in the attachment follow. The purpose of slides 1 and 2 is to show the overall investment required by Mississippi Power Company (MPC). These slides include both the scope under the CCPI Cooperative Agreement and other scope not included as part of the Cooperative Agreement. Slide 1: The (b) (4) million labeled "Non-EPC Capital" includes transmission interconnection, land, permitting, internal listed as "EPC Capital" includes all of the EPC costs labor and project development costs. The (b) (4) shown in the Site Change Request plus items that we did not propose for DOE cost sharing and less the fuel used for commissioning. To calculate this number, start with the (b) (4) for Budget Period 2b, add the (b) (4) (b) (4) shown in slide 2 and subtract for fuel. (b) (4) Slide 2: of "EPC Capital" listed under "CCPI Basis Adjustments" is EPC costs that we did not propose for The (b) (4) DOE cost sharing in our Site Change Request. The(b) (4) includes SCS and MPC labor, SCS and MPC travel, capital spare parts, contingency and KBR engineering and procurement support. The (b) (4) listed as "Non-EPC Capital (less Test Fuel)" is the described above less the fuel (b) (4) that was included in the Site Change Request. (b) (4) Please call me if you have questions. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cel (b) (6) > _______________________________________ >From: Rush, Randall E. > Sent: Monday, March 17, 20081:28 PM >To: 'Diane Madden (Diane.Madden@NETL.DOE.GOV)' > Cc: Pinkston, Tim E. FW: Material sent to Tom Shope Re : Mississippi Power Kemper County TRIG Project >Subject: > SoCo FOIA Response 001719 >Diane, FYI > > Randall E. Rush > General Manager, Gasification Technology >Southern Company Generation > 42 Inverness Center Parkway > Birmingham, AL 35242 Internal: 8-992-6319 >* >* External: (205) 992-6319 >* Cell : (b) (6) >* Fax: {205) 992-6005 > E-mail: rerush@southernco.com > > > > _______________________________________ > From: Rush, Randall E. >Sent: Monday, March 17, 2008 1:26PM >To: 'carl.bauer@netl.doe.gov'; 'Der, Victor'; 'russial@netl.doe.gov' >Subject: Material sent to Tom Shope Re: Mississippi Power Kemper County TRIG Project > >The attached material was hand delivered to Tom Shope (I believe today). It is indended as a followup to the earlier meeting with the Secretary. Note that the last slide is the same as the single slide I sent you earlier. > > > «Docl.doc» > > «Kemper Case Assumptions and Methodology 3-13-0S.ppt» > > Randall E. Rush > General Manager, Gasification Technology >Southern Company Generation > 42 Inverness Center Parkway >Birmingham, AL 35242 Internal: 8-992-6319 >* >* External: (205) 992-6319 >* Cell: ( (b) (6) >* Fax: (205) 992-6005 > E-mail: rerush@southernco.com > > 2 SoCo FOIA Response 001720 AA1'-y J, TopoJI Prnlllonllllll 2992 WHIIIud1 CIHI E a - Qolcor ~- MS 39502..079 Post Ofla Boa C07i MISSISSIPPI , \ POWER SGUtHU:N (OMrAINY MaR.h 11, 2CKIH The llomorJblc Smnucl W. Bodnt:on Srcrer>~ry or IOnerBf Unncll Sl~lc~ Dcpanmc:rn of liner:y Room 1A·l51 1000 lndcpcndcn..'C A•cnuc, SW Washinston, DC 20~8~ !>ear Sccrelary Bodm.rn• Thanks fur rhe opportunny lo nx:el "'nh you on Fcbruruy 261o dl\tU" our Mi'""'PPi coal sa•ificalion pruj~ct. I am cndo•inl! foor e~hihil> !hal nrc dc>iJntdln fun her Llanfy rhc need fnr our rerltl"'" of the !Xp;onn.,nl u. wdl ns 10 aru.w~r I he quc•unn> o.t~d on lhc 16*. Our anaclw:d informal ion illu>lrJic• lhc polcnual "" ha\C lo '""~" rhisthc '1lc:>1 allemall\c" for our tU>IOtnr:l'!l whik mdv~ncing TRIG'" und carbon cmpturins. Thc anachmcnr. hi&hli~lnlhc cupilal intcr"IIY uflhi• pruj«t,lhc rhk inhcrcnl in advancing ne" ~oal gaMficaroonrc,hnolon and carbon cap~un: lcclmnlng) und lhc ,;gnifiranr financial commnmc:nl Sourhem Company;, on:okrns 10 thi> importanr cndca•·or The four cxhrhrh we h..\c cnclo.col :u-c: labckd. c,.,, Panrcopalinn (~li"i"ippi Puwcr Comp;ony Vrcw) Exhrbit Two • Co•l l'w1ocip;o11un (DOll View) Exhrhir Tin-cc • Kemper Cu"' As.umptron> und Mclhnllulo~y E~hihu Four ~ Ktlll("'r Comp;>rali,·c r\naly•i' Ednbu One · nrc'late ccnific:uion Ill build th1> fiN a kind TRIG'" plonr wirh rorbon coplurc ll-chnology and do 11 by 2013 "r We -..·clcon>C 1hc upponunit) to di-..:u" rh" infOJmalion ond ""'"crony oddilional quc•uons you may ha\'1! rn I''""'" or by phone, SoCo FOIA Response 001721 Exhibit 1: SOUTHERN . \ Cost Participation (MPC View) COMPANY Energy to Serve Your World~ Direct Costs (M$) IGCC EPC Capital Non-EPC Capital MW Loss (40MWs) Demonstration Period Costs Total Capital and Demo Period Cost 1,336 j IGCC+ Capture %1 Capture (b) (4)t--- -+-- 11 ~ --+------3751 1,824 J_ (b) (4) 219~ 1 -~~--~ CCP12 remaining from $294* (Construction) Taxes on Transferred CCP12 Capital Funds -----~ CCPI2 Transfer (Demonstration Period) Taxes on Transferred CCPI2 Demo Funds Tax Sa~ngs from DOE Waiwr Total Benefits from Transfer and Waiver State ofMPC Federal lTC ----- -- -- 219 ~---t-i,----t - -81[ 50 -191 ~_ -19r ~=-103 (b) (4) 103 , - -: (b) (4) 9% + ! Net MPC Capital and Demo Period Costs % 63 133 1,462 103 (b) (4) (b) (4) -_ 269 - r - (b) -t----63 ~ - 133 (4) - • 25M$ of 294M$ spent at Orlando. Remaining $269 consists of 219M$ construction period and SOM$ demonstration period. Note: Loan Guarantee benefits are reflected In NPV calculations shown on Exhibit 4. PRELIMINARY ·n1e Recipient considers the material furnished herein to contain conlidential business information '' hich is to be withheld from disclosure outside the U.S. Department of Energy to the extent permitted by law. SoCo FOIA Response 001722 Exhibit 2: SOUTHERN • \ COMPANY Cost Participation (DOE View) Energy to Serve Your Worlde IGCC + Direct Costs (M$) IGccl %1 Capture (b) (4) EPC Capital Non-EPC Capital MW loss (40MWs) -Demonstration Period Costs Total Capital and Demo Period Cost -~ 1,824 I CCPI Basis Adjustments EPC Capital ':-=-c----cNon-EPC Capital (Jess Test Fuel) Spent at Orlando Total Adjustments CCPIBasis CCPI2 Transfer (Construction Period) CCPI2 Transfer (Demonstration Period) Orlando Portion Total DOE %, Capture * --190f 1 - ~~ -2001 _ 1,6241 (b) (4) - ----+ I - --Ol I ~ -~~t--2001 (b) (4) =_:~~--=_ 2~t--!-__ I O%~-~ (b) (4) State of MPC Federal lTC Net MPC Capital and Demo Period Costs 294j 18%" .. _ 1,1341 0 0%1 - 294 (b) (4) •DOE Cost Share at Orlando was 38.4"/o •Note: Loan Guarantee benefits are reflected In NPV calculations shown on Exhibit 4. PRELIMINARY The Recipient considers the material furnished herein to contain confidential business infonnation which is to be withheld from disclosure outside the U.S. Dcpanmcnt of Energy to the extent permitted by Ia\\ , SoCo FOIA Response 001723 Exhibit 3: SOUTHERN ' \ Kemper Case Assumptions and Methodology • • • • COMPANY Energy to Serve Your World& Competitive Measure: NPV of 40 year revenue requirements (customer viewpoint) Competitive Alternative: 2-on-1 "G" class natural gas combined cycle (NGCC) In-service date: June 1, 2013 Climate change: 10 $/Ton C02 penalty beginning 2017 escalating at 5% for 20 years and 2°/o for remaining study period. Cost Component IGCC NGCC Capital O&M Fuel Average cf 843 Peak Capability 581 (b) (4) Incentives (b) (4) (b) (4) EFOR (Mature) (b) (4) (b) (4) yr initial EFOR N/A FOAK maturation;(b) (4) PDA N/A By-products NH3, H2S04 (b) (4) (b) (4) C02 Rate (b) (4) PRELIMINARY (b) (4) Comments $/Kw (Direct$ excl. AFUDC) K$N r (average) $/mmbtu (levelized) IGCC subject to maturation period MW (Summer Peak) I Average (b) (4) of (b) (4) market price Lbs/mmbtu ·ntc Recipient considers the material furnished herein to contain confidential business information which is to be withheld rrom disclosure outside the U.S. Department or Energy to the extent pcnnitted by law. SoCo FOIA Response 001724 Exhibit4: SOUTHERN Kemper Comparative Analysis COMPANY EPC Costs= 1,336M All Values are 2013 Net Present Value of Costs in Millions of Dollars Energy to Serve Your Worlde C02 Legislation/Regulation (O$fTon) (20$/ton) Esc@ 5% (10$/ton) Esc@5% (b) (4) (Values from here down reflect delta from NGCC Case. Negative values reflect savings.) Kemper IGCC1 (184) 91 497 I I Transfer of Orlando CCPI Funds2 (481) (207) 200 25% Capture - No EOR Revenue 3 51 190 422 (58) 82 313 Repayment Waiver5 (179) (40) 192 EOR Revenues6 (270) (131) 101 Loan Guarantee4 (b) (4) PRELIMINARY The Recipient considers the material furnished herein to contain confidential business inf Friday, April 04, 2008 10.00 AM Russia!, Thomas I will call to discuss this final draft (b) (4) (b) (4) (b) (4) Randall E. Rush General Manager, Gasification Technology Southern Company Generation 42 Inverness Center Parkway Birmingham, AL 35242 * Internal: 8-992-6319 * External: (205) 992-6319 * Cell: (b) (6) * Fax: (205) 992-6005 E-mail: rerush@southernco.com SoCo FOIA Response 001726 SoCo FOIA Response 001727 SoCo FOIA Response 001728 SoCo FOIA Response 001729 3o 31 Dunlap. Ann C. From: Sent: To: Subject: "Rush, Randall E." Wednesday, April 16, 2008 4:55 PM Russia!, Thomas RE: FW: Draft Waiver Conditions.doc (b) (4) Randall E. Rush General Manager, Gasification Technology Southern Company Generation 42 Inverness Center Parkway Birmingham, AL 35242 * Internal: 8-992-6319 * External: (206) 992-6319 * Cell: (b) (6) * Fax: (205) 992-6005 E-mail: rerush@southernco.com -----Original Message----From: Thomas Russial [mailto:Thomas.Russial@NETL.DOE.GOV] Sent: Wednesday, Aprill6, 2008 3:49PM To: Rush, Randall E. Subject: Re: FW: Draft Waiver Conditions.doc bS >>>"Rush, Randall E." (b) (4) PM>>> Randall E. Rush General Manager, Gasification Technology Southern Company Generation 42 Inverness Center Parkway Birmingham, AL 35242 * Internal: 8-992-6319 * External: (205) 992-6319 * Cell: (b) (6) * Fax: (206) 992-6005 E-mail: rerush@southernco.com > ___________________________________________________________ > From: Rush, Randall E. SoCo FOIA Response 001732 > Sent:Wednesday, Aprill6, 2008 2:48PM To:'russial@netl.doe.gov' > Subject:Draft Waiver Conditions.doc > > > <> 2 SoCo FOIA Response 001733 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Robbins, Brittley K. Thursday, June 05, 2008 8:05 AM Madden, Diane R.; Russia!, Thomas Re: Southern Repayment Agreement Amendment DOE-SCS-KBR Repayment Agreement -· Amended and Restated 02May2007.doc It looks like you rorgot to use the "Amended and Restated Repayment Agreement" for the second part so I have attached it. >>>Thomas Russlal6/3/2008 2:56PM>>> A draft amendment Is attached. I had to take a few minor liberties with the Secretary's determination to make It flt. I also got a little whereas-happy. The last line of the amendment is a placeholder. We need to figure out what Southern and Mississippi need to do to satisfy the 3rd condition. Randall suggested designing the plant such that additional equipment could be added to Increase the C02 removal to(b) (4) hat makes some sense • but do we need more? SoCo FOIA Response 001734 ATIACHMENTD AMENDED AND RESTATED REPAYMENT AGREEMENT DE-FR26-06NT42392 . This Amended and Restated Repayment Agreement by and between the United States Department of Energy (DOE), Southern Company Services, Inc. (SCS), and Kellogg Brown & Root LLC (successor to the rights and obligations of Kellogg Brown & Root, Inc.) is made and entered Into as of May __, 2007. This Amended and Restated Repayment Agreement supersedes and replaces the Repayment Agreement entered into on February 22, 2006. This Amended and Restated Repayment Agreement ratifies and confirms the rights and obligations of the parties - as amended herein - which became effective on February 22, 2006. In consideration of the United States Department of Energy (DOE) support for a clean coal technology Demonstration Project under the DOE's Clean Coal Power Initiative, for which SCS and KBR, both being defined herein as an "Obligor," acknowledge that they will receive substantial benefit, the Obligors hereby agree to repay the Department of Energy in accordance with the terms and conditions set forth below. Article I. General Objective The purpose of this Repayment Agreement is to set forth the conditions under which the Obligors shall repay to DOE an amount up to, but not to exceed, the DOE share paid under Cooperative Agreement Number DE-FC26-06NT42391, such obligation being the direct responsibility of each Obligor and being for the direct benefit of DOE, as accomplished via (b) (4) (b) (4) and upon the terms set forth herein. Article II. Definitions "Cooperative Agreement" means the financial assistance award made by the United States Department of Energy (DOE) to SCS, Instrument Number DE-FC26-06NT42391 on January 30, 2006, and subsequent amendments. "DOE ShareQ means the portion of the total project costs paid by DOE under the Cooperative Agreement "Obligor" means the organizations that are responsible for repayment under this Repayment Agreement, SCS and KBR, as stated above. "Obligor" includes these organizations' successors and assigns. "Repayment Period" means the period of time during which a transaction becomes subject to repayment under this Repayment Agreement "Total Project Costs" means the total amount of allowable direct and Indirect costs incurred and paid, in part, by DOE under Cooperative Agreement. "Demonstration Technology" shall mean the transport reactor-based gasilication/IGCC technology which is proposed for demonstration under the Cooperative Agreement, including all past, current, and future information and intellectual property developed by, on behalf of, or together by, SCS or KBR, as Obligors, and their respective affiliates, present and future, that enhances or improves the performance of the transport reactor in its application as a coal gasifier for the production of raw synthesis gas which subsequently may be further processed to produce electricity (and/or steam), chemicals, or fuels. "Demonstration Project" shall mean the Integrated Gasification Combined Cycle (IGCC) power plant project being undertaken by SCS and DOE under the Cooperative Agreement Number DE-FC260BNT42391. SoCo FOIA Response 001735 "Southern Company Services Affiliates" shall mean any subsidiary of, and under common control of, their single parent, The Southern Company, whether a first tier subsidiary of The Southern Company or any lower tier subsidiary of the first tier subsidiary. 2 SoCo FOIA Response 001736 Article Ill. Repayment Period The Repayment Period shall begin on the date of the first sale of the Demonstration Technology or on the date specified In the Cooperative Agreement for the end of the Demonstration Period, whichever occurs first. However, if SCS withdraws or terminates its participation under the Cooperative Agreement, or if lhe project is terminated In accordance with Paragraph 2.34 (Termination) of the Cooperative Agreement or terminated due to DOE's disapproval of a continuation application in accordance with Paragraph 2.11 (Continuation Application) of the Cooperative Agreement, this Repayment Period shall begin on the dale the Cooperative Agreement is terminated. The Repayment Period shall expire 20 years after the date the Repayment Period begins. Obligors' obligation to repay DOE expires on the date the entire DOE share has been repaid, or the date on which repayments for all transactions entered into during the Repayment Period have been made, whichever occurs first. This Repayment Agreement may be terminated upon a determination by the Secretary of Energy, or designee, that repayment places an Obligor at a competitive disadvantage in domestic or international markets. Article IV. Basis for Repayment Though collection of payment to DOE by the Obligors shall be cumulative and consolidated into single payments submitted by SCS to DOE, each Obligor is individually responsible to DOE for amounts due to DOE from the Obligor. DOE shall have a direct claim against an Obligor for breach of the terms of this Repayment Agreement by the Obligor. The obligations of either Obligor under this Repayment Agreement shall survive the expiration, termination, transfer, assignment, novation, sale, merger, consolidation, or other change In control of, an Obligor until the expiration of the repayment obligation to DOE. The annual amount of repayment to DOE by the Obligors Is to be comprised of the cumulative effect of the provisions In Article IV (I), (II), and (iii): (b) (4) (i) KBR shall pay to SCS, for transfer by SCS to DOE, an amount equal to of the license fees and/or royalties actually retained by KBR from licensing of the Demonstration Technology to third-party users for the production of electricity (and/or steam), chemicals, or fuels, after satisfying guaranty or warranty responsibilities. Distributions made by KBR to SCS are considered to be included In the amount actually retained by KBR. In the event that KBR does not charge a license fee to a third party for any installation of the Demonstration Technology, KBR will be deemed to have incurred a license fee In an amount equivalent to the license fee on the most recent prior project of substantially similar scope utilizing the Demonstration Technology and in the pro rata amount of the size of such installation. If no prior license has been granted, the amount due to DOE shall be calculated at (b) (4) (or equivalent) of installed capacity. KBR shall not be responsible for such fee if SCS and KBR have mutually determined and explicitly documented that the market for that project will not bear this license fee. SCS agrees that it shall not accept any compensation in lieu of royalties due from KBR under the (b) (4) (b) (4) In the event that SCS sells directly to third parties, SCS shall pay directly to DOE(b) (4) of the license fees and/or royalties actually retained by SCS from licensing of the Demonstration Technology to thirdparty users for the production of electricity (and/or steam), chemicals, or fuels, after satisfying guarantee or warranty responsibilities. In the event that SCS does not charge a license fee to a third party for any installation of the Demonstration Technology, SCS will be deemed to have incurred a license fee in the amount equivalent to the license fee on the most recent prior project of substantially similar scope and in the pro rata amount of the size of the installation. If no prior license has been granted, the amount due to (or equivalent) of installed capacity. DOE shall be calculated at(b) (4) A transaction shall be subject to repayment under this provision if an Obligor enters into a license or contract for sale during the Repayment Period notwithstanding that repayment may occur after the Repayment Period. Repayment shall accrue after satisfying guaranty or warranty responsibilities. (ii) For any commercial application of the Demonstration Technology by SCS, or SCS affiliates, for the production of electricity (and/or steam), excluding this Demonstration Project, SCS agrees to pay to DOE a one time fee of(b) (4) of Initial, actual tested performance for each commercial application. 3 SoCo FOIA Response 001737 Such payment to DOE shall be prorated by SCS', or SCS affiliates', initial percentage of ownership of such facility. An installation shall be subject to repayment under this provision if SCS, or SCS affiliates, breaks ground for the installation during the Repayment Period, notwithstanding that repayment may occur after the Repayment Period. Repayment shall accrue upon the declaration of commercial operation. (iii) For any commercial application of the Demonstration Technology by SCS, or SCS affiliates, for the production of chemicals and fuels, excluding this Demonstration Project, SCS agrees to pay DOE a one time fee of (b) (4) (b) (4) Such payment to DOE shall be prorated by SCS, or SCS affiliates, initial percentage ownership of such facility. An installation shall be subject to repayment under this provision if SCS, or SCS affiliates, breaks ground for the Installation during the Repayment Period, notwithstanding that repayment may occur after the Repayment Period. Repayment shall accrue upon the de.claration of commercial operation. Article V. Schedule for Repayment Payments to DOE by SCS of the cumulative amounts required for the period shall be due within 60 days after each one-year period following the start of the Repayment Period for Repayment Agreement DEFR26-06NT42392. Checks shall be made out to the US Department of Energy and be mailed to the Financial Management Division, USDOE, NETL, Post Office Box 10940, 626 Cochrans Mill Road, Pittsburgh, Pennsylvania 15236-0940. Article VI. Reporting and Record Retention Requirements (A) Annual Report to DOE Within 60 days after the end of each one year period, the Obligors shall prepare a consolidated report and SCS shall submit such report to DOE which, for the one year period just elapsed, provides the applicable data described below: (1) The total dollar amount of repayment accruing to DOE. (2) A description of each transaction from which the repayment obligation accrued. (3)The total amount paid to DOE for all years and the amount of the DOE share remaining to be paid in succeeding years under this Repayment Agreement. Notwithstanding that SCS will submit the Annual Report to DOE, the responsibility for submittal of information to prepare the report, and the responsibility of preparation of the report, falls equally on the Obligors. DOE shall have a direct claim against either Obligor for failure to comply with the requirements of this clause. (B) Commercialization Report For a period of five (5) years after completion of the Demonstration Project, the Obligors shall be equally responsible for submlttfng a Commercialization Report describing the Obligors' progress and success in commercializing the technology used during the project as well as technology derived from that used during the project. The purpose of the Commercialization Report is to assist DOE to determine the benefits obtained from Government support of technology development. The CommerciaNzation Report is independent from the Annual Report required by the Repayment Agreement and Is not limited to the sale or ltcensing of "Demonstration Technology" as that term is defined in this Repayment Agreement. The Commercialization Report shall Include a discussion of the Obligors' efforts to commercialize the technology. The Commercialization Report shall also include descriptions and locations (or proposed locations) of all significant technology embodied In the Demonstration Project, or derived from technology embodied In the Demonstration Project, that was sold or licensed during the preceding year (whether or not such transactions were subject to repayment under the terms of the Repayment Agreement). The Commercialization Report shall also include a discussion of any impediments to the commercialization of the technology. It Is understood and agreed by DOE that the Commercialization Report shall be in a level 4 SoCo FOIA Response 001738 of detail that Is not required to contain Limited Rights Data or Protected Data as defined in the Cooperative Agreement, recognizing that the commercialization efforts involve proprietary and confidential business information which will necessarily be accorded secrecy treatment. The Commercialization Report shall be due on December 31 of each year. DOE shall look to each Obligor for compliance with its applicable portion of the requirements of this clause and obtain performance directly from the responsible Obligor. (C) Period of Retention With respect to each annual report to DOE, the Obligors shall retain, for the period of time prescribed in this paragraph, all related financial records, supporting documents, statistical records, and any other records the Obligors reasonably consider to be pertinent to this Repayment Agreement. The period of required retention shall be from the dale each such record is created or received by an Obligor until three years after one of the following dates, whichever is earlier: the date the related annual report is received by DOE, the date this Repayment Agreement expires, or the date final payment to DOE is received. If any claim. litigation, negotiation, investigation, audit, or other action involving the records starts before the expiration of the three-year retention period, the Obligors shall retain the records until such action is completed and all related issues are resolved, or until the end of the three-year retention period, whichever is later. The Obligors shall not be required to retain any records, which have been transmitted to DOE by an Obligor. (D) Authorized Copies Copies made by microfilm, photocopying, or similar methods may be substituted for original records. Records originally created by computer may be retained on an electronic medium, provided such medium is "read only" or is protected in such a manner that the electronic record can be authenticated as an original record. (E) Access to Records DOE and the Comptroller General of the United States, or any of their authorized representatives, shall have the right of access to any books, documents, papers, or other records (Including those on electronic media) which are pertinent to this Repayment Agreement. The purpose of such access is limited to the making of audits, examinations, excerpts, and transcripts. The right of access described in this paragraph shall last as long as an Obligor retains records, which are pertinent to this Repayment Agreement. (F) Restrictions on Public Disclosure The Federal Freedom of Information Act (5 U.S.C. Section 552) does not apply to records an Obligor is required to retain by the terms of this Repayment Agreement. Unless otherwise required by law or a court of competent jurisdiction, an Obligor shall not be required to disclose such records to the public. (G) Flow Down of Records, Retention. and Access Requirements Obligors shall include clauses substantially similar to the record retention and access requirements set forth in sections (C) and (E) of this Article in all agreements when necessary to fulfill the Obligors' obligations under this Repayment Agreement Article VII. Default If either Obligor is responsible for the failure of SCS to make payment within the lime specified in Article V, or is responsible for SCS' failure to submit the annual report within the time specified In Article VI, the Obligor which Is in default of its own obligations under this Repayment Agreement and fails to cure the 5 SoCo FOIA Response 001739 default within 30 days after receipt of written notice of the default from DOE, notwithstanding any provision of the Cooperative Agreement, its flow down provisions, or this Repayment Agreement to the contrary, that Obligor shall pay to DOE the amount of $100.00 per day for every business day that the payment or report is delayed due to the fault of that Obligor. Obligors and DOE agree that such amount represents DOE's reasonable costs and acknowledge that the liquidated damages set forth herein are an adequate remedy for default and shall not be considered a penalty. Nothing contained herein shall preclude DOE from pursuing any other remedy against an obligor which may be available for the payment of moneys due including interest thereon in accordance with applicable statutes and regulations. Article VIII. Disputes Disputes arising under this Repayment Agreement shall be subject to the procedures set forth in 10 CFR 600.22 Disputes and Appeals. OBLIGOR (Kellogg Brown & Root LLC (as successor to tho rights and obligations of Kellogg Brown & Root, Inc.)) UNITED STATES DEPARTMENT OF ENERGY Signature: Name: Title: Contracting Orficer: Signature: Date: Name: Tille: Date: OBLIGOR (Southern Company Services, Inc.) Signature: - - - - - - - - - - - = - : - - - Name: Date: Title: 6 SoCo FOIA Response 001740 Dunlap, Ann C. From: Sent: To: Subject: Thomas Russial Wednesday, June 25, 2008 4:16 PM Madden, Diane Re: Fwd: MPC - North American Coal Contract under Cooperative AgreementDEFC26-06NT42391 >>>Diane Madden 6/25/2008 4:01PM>>> Diane >>>"Pinkston, Tim E." 6/20/2008 3:43PM>>> Brittley and Diane, For over a year, Mississippi Power Company ("MPC") has been in negotiations with North American Coal Corporation ("NAC") to enter into a contract for the purchase of lignite for the Kemper County Project. Negotiations began and the structure of the contract was developed prior to MPC knowing that DOE would participate in the project under the CCPI. Under the contract, NAC will sell lignite from a mine to be developed near the Kemper County Project. After extensive negotiations between MPC and NAC, the contract is near the execution stage. Lignite will be one of the major costs incurred during the Demonstration Phase of the Kemper County Project- it's expected to be about (b) (4) per year. Under the draft Cooperative Agreement, coal is planned to be a reimbursable cost. We have taken a look at the pricing provisions of the MPC - NAC contract to determine whether the pricing will be readily auditable by DOE and DCAA and wanted to discuss this issue with you. (b) (4) SoCo FOIA Response 001741 (b) (4) Are you available next week for a conference call to discuss this matter with Jennifer and me? Tim The Recipient (Cooperative Agreement DE-FC26-06NT42391) considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. <> 2 SoCo FOIA Response 001742 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Richard Hargis < Richard.Hargis@NETLDOE.GOV> Thursday, July 03, 2008 2:47PM Tobin, Daniel; Madden, Diane; Matarrese, Mark; Borgstrom, Carol; Cohen, Eric; Freeman, Denise; leDuc, Edward; Osborne, Carolyn; Ganz, John; Russia!, Thomas Tomer, Brad; Rockey, John information on site selection for Kemper County IGCC Project TEXT.htm; KCIP Site Selec 070208.doc; Attachment A lignite map.ppt; Attachment B Kemper Prospect Map 032106.ppt All, Attached are files containing Information on the site selection process by Southern Company and Mississippi Power Company. Both companies believe that this site Is the only site reasonably available for the project. Please let me know If you would like to arrange a conference call to discuss. Thanks. Rich SoCo FOIA Response 001743 SoCo FOIA Response 001744 DRAFT Siting Process for Kemper County IGCC Project This memo provides n summary of the site selection process for Mississippi Power's proposed Kemper County JGCC Project. Because, as discussed below, the identified site was the only reasonable alternative available for the project, we anticipate that this analysis would likely not become part of the Department's Environmental Impact Statement with respect to the decision to provide cost-shared funding oa· loan guarantees. However, we are providing this information to support DOE's scoping process In most respects, the decision to locale the proposed plant at the proposed site was governed by the factors one would expect: proximity to resources and infrastructure, and availability of open space. In this case, an additional factor was also paramount: vulnerability to hurricanes. The damage to Mississippi Power generating assets caused by llurricane Katrina in 2005 highlighted to the Company the need to pursue generating capacity away from the coast. As a result, Mississippi Power began an initial planninglevel review for possible future generating sites in central Mississippi. At the same time, such resources would have to be located ncar Mississippi Power's se1vice teaTitory and its existing transmission infrastructure. Mississippi Power focused on a corridor of possible locations generally along the I-59 corridor from Hattiesburg to Meridian. Mississippi Power initially considered a range of generating resources, including natural gas-fired combined cycle units, conventional coal-fired boilers and IGCC using bituminous or sub-bituminous coals, or lignite. As Hn abundant, economic, local resource, lignite was the only fuel choice that provided an option for consistent long-term fuel pricing. This was very important to Mississippi Power. Moreover, it would diversify Mississippi Power's fuel stock, which already relies on natural gas and bituminous and sub-bituminous coals. It soon became apparent that, due to the relatively high moisture and lower heating values of lignite, only a mine-mouth location would be viable for a lignite unit. Accordingly, Mississippi Power quickly focused its review of possible sites on the location of economically accessible and sufficiently available lignite reserves. See Attachment A. Using more refined data from USGS and from the mining industry, Mississippi Power studied the most promising lignite resources in the area of its service territory, and, Mississippi Power approached Not1h American Coal Corporation (NACC) for its advice regarding the location of a lignite mine and plant site. These discussions identified three general areas in Kemper County that might be suitable. See Attachment B. Mississippi Power preferred the most southern of the three sites, as that site was closest to existing infrastructure and would require the shortest linear suppo11 facilities. All three sites covered generally similar lnndfon11S and topogra1>hies, and Mississippi Power had no SoCo FOIA Response 001745 expectation that any of the sites would involve materially different impacts to, tor example, wetlands or floodplains. However, selecting the site which minimized the nominal lengths of the linear support facilities would reduce the environmental impact of those facilities proportionately. NACC hnd also independently identified the southern site as a potential mine location and had already gathered specific developmental information on the site. llnving determined after discussions with NACC that the selected site for the mine was the only reasonable location, based on the availability of economic lignite and the relative proximity to existing infrnstrueture, Mississippi Power identified two possible options lor the location of an immediately adjacent power plant, one on the western side and one on the eastern side of the lignite seam. In assessing these sites, Mississippi Power considered available open space, topography, including floodplains and apparent wetlands, and proximity to infrastructure. In light of these factors, the Company rejected the west side of the mine as a possible site and preferred the selected site on the east side as the only viable alternative. Mississippi selected IGCC technology for the plant based on an economic analysis of lignite-tired technologies. Signilicantly, all these siting efforts and the decision to locate an IGCC in Kemper County were all resolved approximately two years prior to Southern Company's request to DOE to re-site the demonstration project under the CCPI program. When the Orlando site for Southern Company's demonstration project was tenninated due to u·ncertainty over possible state and federal regulation of carbon emissions, Southern Company identified Kemper County as the single reasonable and available option for resiling that effort in a timely manner. No other JGCC facility had been proposed, and no new facility would have been considered in time to seek re-siling of the demonstration project. In summary, once lignite was identified as the fuel/feedstock for the facility, the location of accessible lignite reserves ncar Mississippi Power's service territory, as previously identified and evaluated by NACC, governed the location of the mine. The actual plant site was then selected based on proximity to inli·astructure, topology, including avoidance of floodplains and wetlands, and available open space. Because Mississippi Power had already identified IGCC teclmology as the economic choice for the plant, it represented the only feasible option for Southern Company's effort to rc-site the demonstration under the CCPI program. We nrc pleased to help support the Depattment's preliminary scoping effott and look forward to working with you on the project. Attachment A Attachment B Lignite map.ppt ( ...:emper Prospect M.. SoCo FOIA Response 001746 tJ':O"'"'• X . x..\ I .,CI(.''\I'O .;II.,C: ·ii"l I \ . . ~c·,.;:)W.' Spot~~ ' ' ·...,"""' '' .~ <; .!a.ng. ' Cu:.... Slt:>tl.,., 00~n Gro-.-._ I . •To.<:.: I ::; rr.i I Pr~m.lle ;: . I Cu"'lt\:rHi'~ ~"'•.a Col.l.-.!'lt'ilr-:, •• :;.J~O: o• • c • • .., • '# ,. , Sl!·•;un~r~· 'c . :.~::~ ~ ~ ... :...::ct·.;, - A I ...c I ~ • E ...... -... • 0 .• •• • (;;'· - •· .tit:' J1r-.~~ 6 .•• .• ~ ./ ~--• coen:.u:..t I. ~. ,.-<.:,~;.. t .::.> ___...~, ~ _.., ..-,;.:t'·r"": ~ !'""~ -..'loUD-"' •• ....., . • u--'•l ...-~· . . "'": • /! •Pop:a• 'Q1 ..,;.:~ud~ol-e ....-'~~;::..~: ....._..... • ,.::s:IW..1•t To~-·· I ........ ,o~:~:r· '\ I I "'•,_.~~or ..•••• : . ::· ··••••• . :.. :l .forou A U ..... Oo;odo:m I, ?i~· .s':)r. ~ l . \ J c~:~!oH­ c · • AvoerloA.:: I • \ . • I ,;_..;~•fin Abandoned Railroad •• L A u· 0 5 R 0 A ;. E I Tennessee NG Line ••• •• Railroad 1 .-.:·~.c""' ·~3~~vt1~ I • ~u:;.<~:lown !»cfi!UO .• .••.• .• Sonat NG Line o.,.:J:k. : v~r.onc Sl.JC~N~lef~ I Potential Mine Sites -MPC230 kV ·~Fo-:.t:-1 I ..,.C. X • ::IJi t.. n'\ I Ota~:»:>Oft:l:o • . E..lSIY~O I I • . .~"1 L~O'r.g< ~u-u:;lc;:~ • I 0 C•c-J~O.!C~it ·---... I l!l.>om:... .d • ~f. "u:::o • T · :z t: " ~. :" 0 A - • c -.; SoCo FOIA Response 001747 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Richard Hargis Tuesday, August 05, 2008 3:36 PM Madden, Diane Fwd: RE: revised draft of NO! - Kemper County JGCC TEXT.htm; Kemper --revised noi 072908--prelim GC-20 comments.doc Diane, We received comments from GC-20 but not GC-51. One comment asked what funding DOE has already provided. Can you send me that number? Thanks. Rich >>>Richard Hargis 8/4/2008 4:54PM>>> fyi comments from GC-20 I think I can handle most, if not all, of them But, we still need GC-51 to provide review comments >>>"Cohen, Eric" 8/4/2008 4:47PM>>> Rich -- per your request here are some preliminary GC-20 comments on the NOI. I'm not sure everyone Is yet comfortable but I hope these are helpful. From: Richard Hargis [mailto:Richard.Hargis@NETLDOE.GOV] Sent: Tuesday, July 29, 2008 11:17 AM To: Borgstrom, carol; Osborne, Carolyn; Freeman, Denise; Cohen, Eric; Tobin, Daniel; le Due, Edward; Matarrese, Mark; Ganz, John Cc: Tomer, Brad; Madden, Diane; Rockey, John; Russial, Thomas Subject: revised draft of NOI - Kemper County IGCC .,·t ~ AU, Attached Is a revised draft of the NOI for the Kemper County IGCC project. This version Includes changes based on FE· 7 review and revisions suggested by Eric Cohen. There Is an aggressive schedule for completing the EIS process; Southern company needs a ROD by November 2009 to allow DOE cost-sharing in the purchase of the combustion turbines. Delays In issuing the NOI will make It increasingly difficult to meet this schedule. NETL would like to formally transmit the NOI to HQ by August 8th. Therefore, I would appreciate receiving any comments by August 5th. Please let me know If you need any additional information. Thanks. SoCo FOIA Response 001748 REch SoCo FOIA Response 001749 REVISED DRAtT JULY 29, 2008 IG450-Gl-rJ I · htouhlr JllUtf, rhrrk othrr Fit tort11nl runrrntjon\l DF.I'AilTMENT OF ENERG\' No lire of lnlcnt lo l'rcpnrc on F.n\'iron mcntnllmpnct Statement nnd Notice of Proposed FloodJllnln nnd Wcrhmds lrl\'oh·ctntnl for Ihe Kemper· County IGCC Projcrl, l{empcr County, i\IS A(lENC:\': Department of Energy ACTION: Notice of Intent nnd Notice of l'roposed Floodplain nnd w~uunds lnvol\'cmcnt Slli\li\1,\R\': The U.S. Department of Energy (DOE) announces its inlentto prepare nn Etll'i• ronmentnllmpncl Statement (EIS) pursuant to the Nntionnl En\'inmmcntnll'olicy Acl (NEPA) of 1969, ns nmendcd (42 U.S.C. •1321 e/ seq.),the <.:onneil on En\'ironmcnlnl Qunlily NEI'A regula· tions (40 CFR Ports 1.500-ISOS), nnd the DOE NIWA regnlntions (10 CFR Pnrt 102l),to nsscss the potential cnl'ironmcntnl impacts associated with the construction and OIICrotion of n project proposed by Southern Company, through its nnilinte Mississippi !•ower Company, which hns been sclcclcd by DOE liu ~'llltsidcmtiun t'or cu•J-~hilrcd li!rdinu under the Clcnn Conll'owcr lni· tintivc (CCI' I) Jll'ogram. In ndditiou, IIIC U.S. 1\rrtl)' Corps of engineers has c:otprcsscd nn interest in participating in the preparation of the ciS ns II coopcrnting ngcncy. 11re ~P.!.!'.i~J:.l~lf­ pt\S~ot:tho-pruposc•IJlrO.}·r\.t'"ll-XIW,J.).toGI~Ull.!()g8~~flnckgrcmnd Ag~nt\' 'llte CCJ"J program WIIS established in 2002 ns n government/industry partnership to implement the !'resident's National Energy Policy recommendation to increase invcs1mcnt in clean con! technology. llte goal of the CCI'! program is to accelerate commercial deployment of ad\·nnccd coni technologies thnt provide the United States with clcnn, reliable, ru1tf aOordnble energy. 'lluough coopcrati\'c agreements established with industry, the CCI'I prograru plans to advance selected coal technologies to comrncrcinlizntion. SoCo FOIA Response 001751 R~VlSCD DRAFT JULY 29, 2008 The Energy Policy Act of2005 (EI'ACT 2005) established n Fcdernl loan gunrnntee program (LGI') lor eligible cnerg)' projects that employed innovlllil'c technologies. Title XVI! or EPt\CT 2005 nnthori1.cs the Secretary ofEnetg)' (Secretory) to mnkc loan guarantees for pr~jects that "nvoid, reduce, or sequester nir pollutnnts or anthropogenic emissions of greenhouse gases; nnd employ$ new or signiticomly improved technologies os compared to commercial technologies in sen•ice in the United States nt the time the gunmntce is issued." Mississippi ['ower Company has submitted n pre-nppliention nml was invited to submit a formal application for a loan gnnmntce. ttlUll!(.)!oiEI> ,\(.;:R(.);I;I'rupuscll A<'thon: The proposed netion for DOE is to provide n total of S294 million in cost-shared funding lor the proposed project. _In addition, !)0" mny nlso provide n loan guarantee: pursuant to the Energy l'olicy Act of 2005 to guarnnto:c n portion ofthe private sector financing for the pmject.· The-tm\iccl initiallrJ>rOf'OSctl·b~nuth~rn·Gumpnny, 11 2&5,\tW IGGG-~•Iiml-iR-Gfluflll>r.-R(>fitla.-\Ym;-sel~l-itt·Gete~fl.Hittd-n-<'OOpo1nlliw--tlgM!ltlo111!-WIIS IIWIIrtl~d·itt-lf!ltltii~OOlt;-\ttttl~llotl~~~~-Jie~liliativHaliliittltiotl-fQI>-JlSUJ­ ij~061·~tl~r,in-Nowntbe~l)+....th<•ltl)51-5ile-tltilit)'-tl11nollfl"r-COz capture systems and COz pipeline, and a natural gas pipeline, ns f<'latffl.~Q!!!lO:ct~!l .actions. ·ncc mine would he operated by North Americnu Coal Corporation and would pro1•idc the 'prima-·-:-:::--------------, 1)1 ,so~rcc, !?f. fuel foU]tc p~j~~~--~H9i!IB.~Y~I!!~.r~~\1.1!.~•!J~Y~!>:P~~.Of.!~!'.~~~~!~.~J~!P.~~~!!~~ .I~i.t)!: ... -·· · ~ed [eSJ: la ehm • ooconduy oource? in ,the life of mine nrci{ .A..<:!•!!l.~ !!liE!~I.S.:.tJ!~.!I.•~~~Y-~~~~!&.'!~'-~-~~!~~I)y_nl..'?f.l.i.&'li~~.:Jl'P.\IJ!! 4!~mr.~ ........... c0 m.,onled [e&J: c•n ,.• proviolo •• ••lnn. Actual mining would disturb uplands, wetlands and require stream dii'Cr· sions. ·ncc lignile coal would be tmnsportcd by tmck nnd /or overland eom•eyor. following lig· nile removal, approximately 275 ncres per )'ear ofmincd lnnd would be restored to approximate ] .the pre-mine land contour and re·vcgetnted to n land usc consistent with on ppprovet{ mine rcc· . . . ... ·• ~kd [dlt .approv~d by vho:>? lnmntion plan. ____ The second type of lnndscapc disturbance is the nssocintcd mining disturbance thnt would rcsnlt from the instnllntion of facilities and stntctures supporting the nctunl mining operation. Facilities would include an cntmnce road, office, shop, fuel farm concplc;.;, drnglinc erection area, employee nnd equipment pnrking areas nnd electrical substations nnd tmnsmission line.~. Support stnlctures would also include the construction of temporary rcscr1•oirs, ponds and associated stream diversions to route surface water from undisturbed orcas nway from or around arcns where actual 4 SoCo FOIA Response 001753 REVISED CRAFT JULY 29, 2008 mining disturbance would occur nnd the constmction of storm wntcr sedimentation control ponds to rctnin and trent surface runotT from nrcas disturbed by the mining and reclamation opcrntions. As mining ndvanccs, those dil'crsions, ponds ond ronds tlmt would no longer be needed to support mining would also be restored to their npproximnte prc:-mine contour or be retoincd os per· mnnc:nt post·mi11e structures with npproprinte lnnd0\\1ler und regulatory agency approl'nl. The outer boundary of the mining oren would encompass approximately 31,000 acres princlpnll}' in Kemper Count}' nnd pnrtinlly in Lnuderdnle County. Within this nrcn, n tolnl of approximately lS,SOO ncrcs would be disturbed nnd reclaimed O\'Cr the life of the mine. These 15,500 acres \\'OIIId include npproximntely 11,000 acres for mining, opproximntcly 4,000 acres for temporary rcscr\'oirs, ponds nnd stream dh•ersions, and approximately SOO acres for mining support facili· tics. The mine would produce approximately 3.8 million tons of lignite per yenr to supply the IGCC project. The mine nren has similar topogrnjJhicnl chnractcristics ns described for the plnlll site Rro:a nbove. The proposed plnnl site is about X mjk~ north of the existing Mississippi !'ower transmission infrastmcturc •11 YY. MISS. New 11nnsmission fncilitics, including npproprinte lines and subsla· lions, would be constructed to interconnect the plantiO the cxistinnnrid and to provide: firm transmission service for tlJe plant's output. The new transmission lines would include construction ofnpj>roxinmtely 70 miles of230 kilol'olt (kV) transmission and RJ>proximntely six miles of II 5 kV lrnnsmissiou. Rights of way (ROW) up to 125 feel would be required for the:;c: new trnnsmission lines. 'l11c IGCC plnnt would nlso require npproximntcly 20 miles of existing trnns· mission lines to be upgraded. The new and upgraded transmission lines would be in Kemper, Lauderdale: nnd Clarke counties in Mississippi. An approximately S-mile r1nlurnl gns pipeline nnd nn npproximotely 60-mile C02 pipeline would also be built. The C02 pipeline would extend from the plnlll through Lnudertlnle nml Cl:trkc Counties nnd end In Jasper County. 'llu: ROW would be SO feet wide for~hesc undc:rground 'faeilities, ................... . ~;\ll~rnntln~: NJ::l'A requires thnt agencies evaluate the rensonnble nltcrna· th•cs to the proposed nction in 1111 ms. The purpose for ngcncy netion &:termines the range of reasonable nltemnth•cs. 1ltc CCPI progrnm \\'liS estnblishcd to help implement tltc President's Nutionnl Energy Policy rccommc:ndntionto increase ill\'estmenl in clean eoaltcchnology, thus ensuring the reliability and nfiordnbility of domestic c:ncrgy supplies while simultaneously pro· lecting the environment. 1l1e CCPI progrnm was structured to Rchie1•e National Energy Policy goois by promoting prh•nte sector initintil'es to irwest in demonstrations of ad\'nnccd conllcch· nologics thnl could be widely deployed commereinlly. The federnllonn gunrnntcc program ou· thorizes the Secretary to make lonn gunrnntcc:s for projects that "nl'oid, reduce, or sequester oir pollutants or anthropogenic emissions of greenhouse gnsc:s; and employs new or significmllly imprOI'cd technologies ns compared to connncrciol I~'Cimologies in scn•icc: in the United Stntes n1 the time the gunrantee is issued.'' .. Co-ltd (c9J: Wh.Jt h p.tpellneil undor~r..,n47 Tho Sequeatration fac;ilitie•? ~----:-~--------< COfNI't!Hted (elO]:Mh.ac Jurther deacrlpt1on ctln "8 provuse tor Ute COl •~queats·•uon oru.on•) H•v• ~• explored eaUne ~ifera? V'i l1 the ptpelln.e c.entloned here di8char1« to ,an eA~ lat int plpeUn~ deatinecl !or EOit? The range of rensonnble (•pti.ut:rul~lo be considered in the ~IS for the proposed Kemper County IGCC l'roject is determined in accordance with tm!fllll-i>ll:;llr\-itrnh!I,!Yih~ nnd<'rh jng purnu~..- nnsl need lor RJ!<'IIcv nctjnn. Tlccnusc of DOE's limited role jn d..ciding \I he1her tp pro· \·iJc t4tfrm-iditt!,!'COSI·shared funding -And possibly i!_lonn gunrnntce~_-for the project, DOl! s SoCo FOIA Response 001754 REVlSt:L> L>RJ\FT JtJI,Y 29, 2008 currently plnns to giw-tffimuf!i""iDUF.SSF.S"). lndi\'iduals who do not make advance arrangements to speak mny register ntthe meeting and will be given the opportunity to speak following prc\•iousl)' scheduled speakers. Speakers who need more thn11 live minutes should indicate the length of time desired in their request. Depending on the number of speakers, OO!lmny need to limit speakers to live-minute 11resentations ini· tinily, but will provide additional opportunities ns time permits. Speakers can also prm•idc writ· ten mntcrinl to supplement their presentations. Ornl and written eonunc:nts will be given equal weight. DOE will begin the formal meeting with an O\'cn·icw of the proposed Kemper County IGCC.: Project. DOE will designate n presiding officer to chnir the meeting. The meeting will not be conducted as an evidentiary hearing, and speakers will not be cross-examined. However, speak· ers mny be asked questions to ensure that DOE fully understands their comments or suggestions. The presiding oftlcer will establish the order of speakers nnd provide au1y additional procedures necessnry co conduct the meeting. 8 SoCo FOIA Response 001757 R&VlSCD DRAfT JUI,'f 29, :1006 ls~ucd in \\'nshington, D.C., this _th dny of_ . 2(1().8, 9 SoCo FOIA Response 001758 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Robbins, Brittley K. Wednesday, August 13, 2008 5:25 PM Madden, Diane R.; Destefano, Michael S.; Russial, Thomas Fwd: RE: Final Orlando Project Close Out Costs CFf Termination Charge Reimbursement Summary for DOE (DOE Comments 7-23-08 • SCS Comments 7-29-0B).doc All, We are coming to a close (hopefully) on the close-out costs for the Orlando site. Southern has submitted detail associated with certain subcontracts and requests DOE approval for the associated costs. All of the detail is provided In the email string below (and attachments). I have reviewed the detail and attempted to narrow down your review to key points that may require additional discussion between DOE and Southern. If you want to review all of the Information and documents below, feel free to do so. Otherwise, I have Identified points of discussion as follows: (b) (4) Background: There was previous discussion regarding the (b) (4) being applied to (b) (4) In material costs. (1) DOE questioned the reasonableness of the (b) (4) Southern provided backup documentation In the form of three picture quotes from vendors who all estimated a scrap value of less than the was (b) (4) that (b) (4) was willing to give Southern. Internal Southern estimates also concluded that the (b) (4) reasonable. Back in April, DOE requested that Southern seek vendor quotes on the materials scrap using a means other than a picture quote. Southern has stated that picture quotes were not obtained because "At the time we discussed DOE's preference for non-picture estimates, so much time had passed that such estimates would not have been complete - by that time, some of the materials were no longer at (b) (4) warehouse. Given all of the circumstances, we decided not to seek reimbmsement ti·om DOE for the portion of the termination payment based on picture quotes acceptable? that was attributable to the mate1ials." Is the (b) (4) Of note: Southern has calculated actual materials termination costs at (b) (4) Southern Is 1lQtrequestlng reimbursement for these costs (le: not counting them In the overall DOE project·cost) however, they are charging a . Is the (b) (4)overhead allowable considering: (1) the direct charge, (b) (4) materials overhead charge on the (b) (4) which is the base for the overhead, Is not counted as a project cost and (2) does DOE consider termination charges of to be acceptable? (b) (4) (b) (4) - Background: The total value of the steam pipe fittings for the GI Is approximately When the Gl was canceled, (b) (4) had already ordered the materials and fabrication had (b) (4) begun, so the work was beyond the point of cancellation without incurring the total cost of the contract. The steam piping for the Gl was specialized and used materials that were thicker than materials for typical piping. There Is little to no ability to re·market the piping. Consequently, (b) (4) s quoted cancellation charge of (b) (4) which Southern subsequently negotiated down to (b) (4) This cancellation charge Is based on supplier Invoices. Southern elected to pay the cancellation charge rather than accept the specialized materials and attempt to find a buyer for them. If Southern were to take possession of the material and attempt to dispose of them, they estimate that It would cost them more than (b) (4) . Is the (b) (4) ancellation charge reasonable? If you feel a meeting to discuss these costs would be helpful, let me know and I will schedule one. Thanks, Brlttley >>> "Morrison, Jennifer B." 7/30/2008 1:44 PM >>> Britt ley, Thanks very much for a quick follow-up - I know it was a lot of information to digest. I have provided responses to your questions on the subcontract and the (b) (4) (b) (4) subcontract below. (b) (4) With regard to the (b) (4) subcontract, the (b) (4) ancellation charge is based on (b) (4)suppliers' invoices. (b) (4)has sent us its supporting documentation, and most of it is in the form of suppliers' invoices. At this point, we are reviewing that documentation to be sure that we agree with all of it. SoCo FOIA Response 001759 I'll let you know when we have completed our review. Of course, if you want to see the documentation, please Jet me know. (b) (4) As for th provide re need additional information. contract, I decided it would be easiest and (hopefully) clearest to you did. Please let me know if my responses are unclear or if you We are happy to chat about this matter with you (or others if need be) at any time -just let us know what you need. Kind regards, Jennifer .Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (b) (6) (mobile) 205-257-6381 (fax) jemnorri@southcn1co.com This e-mail and any of its attachments may contain proprietary Information of Southern Company and/or Its affiliate that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which It is intended. If you are not the intended recipient of this email, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the Intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Brlttley Robbins [mailto:Brlttley.Robblns@NETL.OOE.GOV] Sent: Wednesday, July 23, 2008 4:04 PM To: Morrison, Jennifer B. Cc: Pinkston, Tim E. Subject: Re: Final Orlando Project Close Out Costs ;i HI Jennifer, r finally had the opportunity to take a look at the closeout costs for the Orlando project and have a few clarification questions. Regarding the (b) (4)costs, I have inserted my questions Into the attached document. For (b) (4) I have added my question in bold font, below. (b) (4) Those are the only questions I have for now. Based on your response to those questions, I may need to engage more people at DOE to determine allowability and reasonableness. I appreciate the thorough write-up (I know it couldn't have been easy). If you have need clarification on any of my questions, please feel free to contact me. Brlttley Robbins Contract Specialist, OOE·NETL 2 SoCo FOIA Response 001760 Acquisition and Assistance Division (412) 386-5430 >>>"Morrison, Jennifer B: 7/9/2008 8:26AM >>> Hello Brlttley, We believe we have reached the point of closing out all subcontracting matters for the Orlando Gasification Island ("GI") project and hope that this will be our final occasion to discuss the close out. As described below, we have just a few loose ends to tie up. I know It may take some time for you and your team to review these details, but we would like to have a conference call to discuss these matters whenever you guys are ready and available. If you need additional Information In advance of scheduling such a call, please Jet me know. My contact information Is at the very end of this e-mail. Thanks very much, Jennifer (1) Termination Costs for (b) (4) -As you will recall, (b) (4) is the supplier that was fabricating the (b) (4) for the GI portion of the Orlando project. Southern has not yet attempted to seek reimbursement from DOE for any portion of the (b) (4) termination cost that Southern incurred to cancel that subcontract. We were waiting to obtain estimates for the scrap value of the (b) (4) of materials that (b) (4) had procured to fabricate the (b) (4). In our settlement with (b) (4) we received a (b) (4) off-set against the material costs as that amount was deemed to be the salvage value of the materials at the time of termination. We were able to obtain estimates based on pictures of the materials, and those estimates were much lower than the (b) (4) off-set that was Included in the (b) (4) termination charge (see attached e-mail). The estimates did not cover all of the materials because some of the materials were in Canada and it would have been cost-prohibitive to pay the Import tariffs to bring the materials to (b) (4) warehouse then sell them for salvage value. We were, however, able to get a rough estimate from (b) (4) supplier as to the scrap value of the materials in Canada (see attached e-mail). > > At this juncture, we are trying to dose the books on this subcontract and would like your thoughts on what portion of the (b) (4) termination cost would be reimbursable by DOE. We think the costs In question are (i) the reasonableness of the (b) (4) material salvage value (credit) that Southern received in the termination charge; (il) the (b) (4) rofit that was part of the termination charge; and (Iii) claimed loss of operations for a period of (b) (4) (b) (4) Southern would like to seek reimbursement from DOE for (b) (b) (4) (DOE's cost share amount) of (b) (4) which is a portion of the termination charge that we believe does not raise any questions as to relmbursability. The rationale for this reimbursement amount Is set forth In the attached Word document, but In sum, this amount Is comprised of labor charges, a materials handling charge, and a (4) 3 SoCo FOIA Response 001761 reasonable profit o(b) (4) <> (b) (4) (2) Close-Out Costs fo -The facts associated with this subcontractor are set forth In the attached e-mail. Here is a quick overview: Southern had a contract with this company to fabricate and furnish steam pipe fittings for both the GI and the CC portions of the Orlando project. The GI-reiated piping was needed to connect the gasification island to the combined-cycle facility, so the charges for the piping would have been charged to the GI portion of the Orlando project. The total value of the steam pipe fittings for the GI Is approximately (b) (4) . When the GI was cancelled, the GI-related piping was no longer needed because the sole purpose of the piping was to tie the Gl into the overall facility. At that lime, (b) (4) had already ordered the materials and fabrication had begun, so the work was beyond the point of cancellation without Incurring the total cost of the contract. The steam piping for the GI was specialized and used materials that were thicker than materials for typical piping. There is little to no ability to remarket the piping. Consequently, (b) (4) quoted cancellation charge of (b) (4) , which Southern (b) (4) subsequently negotiated down to (b) (4) . Did (b) (4) ever provide rationale or supporting or even the (b) (4) ? How did they arrive at that detail for their cancellation charge of (b) (4) number? Did they get a quote from the subcontractors who were In possession of the materials? Based on the rationale provided in the attached e-mail, Southern elected to pay the cancellation charge rather than accept the specialized materials and attempt to find a buyer for them. At this juncture, Southern would like permission to seek reimbursement for (b) (4)of the cancellation charge. (b) (4) <> (b) (4) (3) Cancellation Costs for Is the the Orlando subcontractor that won the project. Only 1 of the 4 buildings was related to the Gl portion of the project - that was the conference center. The total value of the GI portion of the Contract was (b) (4) At the time of cancellation, engineering work was complete. Under the termination payment provisions of the Contract with (b) (4) Southern Is required to pay the vendor's actual costs Incurred up to the date of termination plus reasonable overheads and profit on the actual direct costs. (b) (4) laimed the appropriate amount of the termination payment was (b) (4) Southern's calculation of the termination payment pursuant to the Contract Is (b) (4) Negotiations with (b) (4)are continuing, but we expect to arrive a resolution on this Issue soon. Accordingly, Southern would like permission to seek reimbursement for (b) (4) of the $(b) (4) cancellation cost that Southern has calculated as representative of an appropriate termination payment per the Contract with (b) (4) (4) (b) (4) -This agreement was for designing, engineering, supplying and constructing the cooling tower for the GI and CC portions of the project. Before the project was cancelled, (b) (4) SoCo FOIA Response 001762 incurred (b) (4) In engineering labor costs for the Gl portion of the project. Although we received the Invoice for this charge In December (about 1 week after the termination), it has been overlooked until now. We would like to seek reimbursement from DOE for (b) (4) of the(b) (4) . - Southern entered into an agreement with to design, engineer, and supply coal handling switchgear for the GI portion of the Orlando project. (b) (4) was able to cancel (b) (4) of the work to be performed under the contract. However, the remaining (b) (4) was for engineering that was performed before the project was cancelled. The amount expended prior to the cancellation of the contract with (b) (4)l was (b) (4) . Again, we received the invoice for this charge In December (several days after the termination), but have not yet sought reimbursement due to an oversight. Southern would like to seek reimbursement for (b) (4) of the (b) (4) . (5) (b) (4) (b) (4) (6) Credit to DOE for Elimination of Stack Height - As you know, the cc portion of the Orlando project Is going forward without the GI portion. The natural gas fired combined-cycle facility Is being built by Southern, but will be owned by Orlando Utilities Commission ("OUC"). When the heat recovery steam generator ("HRSG") for the project was originally designed, it was designed, configured and fabricated to accommodate the project's syngas operations. (b) (4) (b) (4) (b) (4) At the time the GI portion of the project ed design changes to the HRSG were, pursuant to the contract, non-cancellable. Recently, when construction on the HRSG stack began, OUC decided that It would not (b) (4) (b) (4) Because the HRSG stack arrived at the site as materials and components and was then constructed on site, (b) (4) (b) (4) constructing the combined-cycle facility. Because this material was associated with the GI portion of the project, Southern plans to obtain 3 Independent scrap value estimates for this material and will credit DOE an appropriate amount for the value of those materials. ii Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (cell) (b) (6) 205-257-6381 (fax) jenmorrl@southernco.com This e-mail and any of Its attachments may contain proprietary information of Southern Company and/or Its affiliate that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e-mallls Intended solely for the use of the Individual or entity for which It Is Intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, 5 SoCo FOIA Response 001763 copying, or action taken In relation to the contents of and attachments to this e·mall is contrary to the rights of Southern Company and/or Its affiliates and Is prohibited. If you are not the Intended recipient of this e·mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 6 SoCo FOIA Response 001764 l'rMir&rd aud Canfidrnliul Cauu11u•kall.. wtlb OOE r•gc l of2 Southern Compnny Services, Inc. Ot·hwdo Gnsilirntion Pa·ojccl Close-Out Summnry ofTerminntion Chm·ge Pnid to (b) (4) nnd Pa·aJtosni for DOE ltelmbursemenl June 2, 2008 B~for~ termination, Southern hnd pnid (b) (4) in progress payments for its work to labricntc the (b) (4). DOE hnd reimbursed Southern lor (b) (4) ofthnt nmount, or (b) (4) The progress payments were based on n percentage of the ov~mll contmct price, ond were not tied to ~pecific lnbor cl!Rrgcs or mnt~rinls ~osts. To cnlculntc the termination charge, (b) (4) nnd Southern defined the vnrious categories of co~ts incurred for lhc work up to thnt point lind dctcrmin~d the actual costs (b) (4) had incurred for each cntegory of costs. The tcmtinntion charge breakdown is shown the "l21nl" column in the table below. Bru;~d on DOE's regulations nnd conversntions with DOE, the categories of costs in the termination charge thnt nrc of questionable reimbursnbility nrc o the r~nsonablencss of the (b) (4) lt.mtcrinl ~al.\·age \'111\tt; that Sol!!hcnt rceeh·ed in the termination charge; o (b) (4)prolitthnt 1\'llS part of the termination charge; ond o (b) (4) for (b) (4) clnimcd loss of opemtions for n period of (b) (4) .... Commented (IKR1J: lflht IIUIK•' To nrrivc ntll reasormblc n:solution on rcimbursnbility, Southern determined whnt portion of the tcrminntion chnrge was nttributnble to cnch of the categories of costs that made up the termination charge. These perc~ntngcs nrc shown in the right-hnnd column, with the hemling "% ofTotol," in the table below. SCS llf.SPONSI:: Drinley, We u• net 1"1Vfllinaolul DO£ rrimbune Ul for anr rortioo orehc: Tcrminarion CNI'Jt th.ac i1 """i11al "ilh nuoerofit - Instead of seeking reimbursement for (b) (4)profit, Southem seeks reimbursement for I (b) (4)profit. l.oss ofOpemtion~ - lteimbnrsemenl is U21 sought for Oil)' portion ofthc !ass of opemtions costs. Abo. tt.c Dm·rriwbuuedJiftOUAit \\111not sJ:.o\''"P In tiM DOE ftuncblr..,..n• l. ....... : o o o o (b) (4) __________________ ~sn~u _ r Comnoented I•KRl]: 11'!111 ...,:trillo ue in obi• bnc7 S (b) (4)Nil maaniah 1kllllt in t{'oltMlon? ltlll~c ~s R t: Hrofi\ (b) (4).. ........................ Malertals Overhead Charge Labor Costs (b) (4) Tole! . COIItmenttd [BKRS]I Plwcdori~· shllthhltrror.sonoctuo! "'"'a~ Pot<"O,UthJt ~ould lu\'t:bttn innntN lud lMprQjC'(t contiauN SCS RfSPO:"SE: Dr;nlc)·. thll ift<..,cohn4 no1 oa "loll opponunity" ••••· I bop Friday, September OS, 2008 11:35 AM Robbins, Brittley Madden, Diane; Pinkston, Tim E. Kemper County -- Amended Cooperative Agreement and RepaymentAgreement Cooperative Agreement (SCS redline of DOE draft 9-5-0S).doc; Repayment Agreement (Amendment 2) (SCS redline 7-1B-08).doc Hello Brittley, Attached is redlined version of the Cooperative Agreement for the Kemper County project that shows our proposed changes to the agreement that you sent in June. As you will see, we did not propose many changes and most are clarifying in nature. Also attached is a redlined version of the Repayment Agreement. Tim will be calling you and Diane soon to try to schedule some time to discuss these documents. We look forward to talking with you and finalizing these agreements! Thanks, Jennifer <> <> Jennifer B. Morrison Southern Company Services, Inc. 600 North 18th Street Birmingham, Alabama 35203 205-257-6730 (office) (mobile) (b) (6) 205-25 7-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain proprietary information of Southern Company and/or its affiliate that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 1 SoCo FOIA Response 001767 From: Sent: To: Cc: Subject: "Warren, Daniel H." < DHWARREN @southernco.com > Thursday, September 18, 2008 2:14 PM Madden, Diane Meling, Jeff; Hargis, Richard; Pinkston, Tim E.; Toth, Brian RE: Southern Company Factsheet Diane, We have no further comments on the Kemper County IGCC Project Factsheet. Also, when do you expect the factsheet to be finalized and be available to include in the NEPA Stakeholder transmittal package? Thanks, Dan -----Original Message----From: Diane Madden [mailto:Diane.Madden@NETL.DOE.GOVJ Sent: Tuesday, September 16, 2008 3:04 PM To: Warren, Daniel H.; Pinkston, Tim E. Subject: Southern Company Factsheet Dan, Tim, Attached is the fact sheet, I accepted all of your suggested changes and will use your diagram in the final version of the factsheet. Diane SoCo FOIA Response 001768 From: "Warren, Daniel H." Monday, September 22, 2008 7:49 AM Mansell, Debbie; Meling, Jeff cindy.j.house-pearson@usace.army.mil; Berry, Charles Rick (MPC); Webb, Cindy 5.; Madden, Diane; Templeton, John D.; McCurry, Jesalyn P.; Hargis, Richard; Toth, Brian RE: KCIP: Draft Final Postcard and Box Ad Sent: To: Cc: (b) (4), (b) (6) Subject: Agreed. From : Jeff Meling [mailto:jmeling@ectinc.com] Sent: Monday, September 22, 2008 5:15AM To: Warren, Daniel H.; 'Debbie Mansell' Cc: Richard.Hargis@NETL.DOE.GOV; Diane.Madden@NETL.DOE.GOV; Berry, Charles Rick {MPC}; McCurry, Jesalyn P.; Webb, Cindy S.; 'Brian Toth'; (b) (4), (b) (6) cindy.j.house-pearson@usace.army.mil; Templeton, John D. Subject: RE: KCIP: Draft Final Postcard and Box Ad J suggest changing last sentence in first paragraph in both postcard and ad from: Associated facilities are proposed for Kemper, Lauderdale, Clarke, and Jasper counties including electric transmission, surface mine, natural gas and carbon dioxide pipelines. To: Associated facilities are proposed for Kemper, Lauderdale, Clarke, and Jasper Counties and include electric transmission lines, a surface mine, and natural gas and carbon dioxide pipelines. From: Warren, Daniel H. [mailto:DHWARREN@southernco.com] Sent: Thursday, September 18, 2008 4:08PM To: Debbie Mansell Cc: Richard.Hargis@NETL.DOE.GOV; Diane.Madden@NETL.DOE.GOV; Jeff Meling; CRBERRY@southernco.com; JPMCCURR@southernco.com; CSWEBB@southernco.com; Brian Toth (b) (4), (b) (6) (b) (4), (b) (6) Subject: KCIP: Draft Final Postcard and Box Ad SoCo FOIA Response 001769 Debbie, Attached is the draft final postcard text. It is a little long, but see if you can fit it onto the card without making the font so small the reader would need a microscope. Also attached is the final draft box ad to be published in local newspapers. Rich Hargis will review and approve prior to distribution. You have the distribution list for the postcard. We still owe you a list of local newspapers (and contact info) for the box ad. «File: Postcard Final 092408 (3).doc » «File: Boxad Final 092408.doc » Lastly, you will notice the DOE seal on the box ad . It would be good if you could add that seal onto the postcard if you can find room. Perhaps on the front near the return address. Also, the return address will be the same Rich Hargis address as shown on the front of the postcard. Thanks, Dan P Please print this email only if absolutely necessary. Daniel H. Warren, Southern Company;205.257.6947; ell; The information contained in this E-mail message is attorney privileged and confidential information intended only for the use of the individual or entity named above. If the reader of this message is not the intended recipient, or the employee or agent responsible to deliver it to the intended recipient, you are notified that any dissemination, distribution or copying of this communication is strictly prohibited. If you have received this communication in error, please immediately notify us at 205-257.6947. Thank you. (b) (6) 2 SoCo FOIA Response 001770 From: Sent: To: Cc: Subject: Attachments: "Pinkston, Tim E." Thursday, October 02, 2008 3:05 PM Robbins, Brittley Henderson, Charles W.; Madden, Diane RE: Financial information for DOE cost accrual TEXT.htm Brittley, Our records show that DOE has paid SCS $23,460,941.80. We expect that DOE will pay SCS about an additional $55,000 for costs Incurred through September 30, 2008. Please let me know If you need additional Information or have questions. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) From: Brittley Robbins [mallto:Brittley.Robblns@NETL.DOE.GOV] sent: Thursday, October 02, 2008 8:51AM To: Henderson, Charles W.; Pinkston, lim E. Cc: Diane Madden Subject: Rnancial information for DOE cost accrual Good morning Charles, NETL Is required to update cost accruals on all projects on a monthly basis. However, the accrual for the period ending 09/30 is the most Important one of the year since it Is the accrual at the end of the government fiscal year. With that said, we need your assistance In obtaining cost information on the Kemper County project (NT42391). Our records Indicate that DOE has paid Southem $23,460,941.85 to date. Rrst, please confirm that this Is correct. Second, please let us know the dollar amount of all goods and services (induding any termination costs on subcontracts - whether or not approved by DOE I.e. (b) (4) should be induded In the amount) through September 30, 2008. That is, what Is the total amount of costs Incurred through Sept 30 2008 that have not been billed to DOE already as part of the $23,460,941.85. If you have any questions regarding this request, please contact either Diane or myself. We request that you provide this Information as soon as you can but no later than COB Oct 6. The total dollar amount you provide to us will have no effect on the amount on the future funding you will receive from DOE nor will it affect any payments to be made to you. Thanks in advance, Brittley SoCo FOIA Response 001771 Brittley Robbins Contract Specialist, DOE-NETL Acquisition and Assistance Division (412) 386-5430 2 SoCo FOIA Response 001772 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Brittley Robbins Friday, March 13, 2009 3:55 PM Moles, Amy Leeann Madden, Diane; Lombardi, Linda Re: Southern Host Site Agreement TEXT.htm; Host Site Agreement SCS MPC.pdf Amy, Attached is the host site agreement for the Kemper County project. We are still working on the answers to your three questions re: closeout costs, cost Increase etc. Hope to have to you on Monday. Have a good weekend, Brlttley >>>"Moles, Amy Leeann" 3/12/2009 8:49AM>>> Brittley Can you please forward me a copy of the derinitized host site agreement for Southern? Thanks Amy @••~ £.!)1{..~.. Amy (Hayes) Moles CPA, CIA Office of Inspector General PO Box2001 Oak Ridge Tennessee 37831 P- 865·241 ·8219 F- 865-576-3213 E- molesal@oro.doe.gov SoCo FOIA Response 001773 04/10/2008 13:01 PAGE SOUTHERN 4045060544 ·soUTHERN 02/02 A_ COMPANY Elw-gy IO s~l'l'l' Yoi/T \!lh/J Jennifer B. Morrison Senior Attorney SCSLegal Southern Company Services, lnc. 600 North Bigbteenth Street Birmingham. A111bama 35203 Tei205.2S7,6730 Pax 205,257.6381 jenmoni @soulhemco.com AprillO, 2008 Mr. Tom Russin! U.S. Depattment of Energy National Energy Technology Laboratory M/S922M214 626 Cochran's Mill Road Pittsburgh, Pennsylvania l5236-0940 Re: Proposed IGCC Project in Kemper County, Mississippl Agreement between Mississippi Power Company and Southern Company Services, Inc. Dear Mr. Russial: Enclosed is a fully executed copy of the agreement between Mississippi Power Company ("MPC") and Southern Company Services, Inc. ("SCS") regarding MPC's proposed IGCC project to be located in Kemper County, Mississippi. Please note that MPC and SCS have afforded this agreement confidential treatment and respectfully request that DOEINETL afford the agreement the same are treatment. Please contact me if additional infonnation regarding this matter is needed, and I will forward that information to you as quickly as possible. ,. Very ttul*'y yours, ~- nntfer cc: :.~ ~ . ~ orrison Randall Rush SoCo FOIA Response 001774 SoCo FOIA Response 001775 76 SoCo FOIA Response 001777 78 (b) (4) (b) (4), (b) (6) (b) (4), (b) (6) (b) (4), (b) (6) (b) (4), (b) (6) (b) (4), (b) (6) (b) (4) SoCo FOIA Response 001779 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Baker, Lisa A. Tuesday, April 21, 2009 4:28 PM Gottlieb, Paul Dowdell, Bonnie; Mosser, Morgan H.; Russial, Thomas Fwd: Request for Waiver of U.S. Competitiveness Clause -- SCSCooperative Agreement DE-FC21·90MC25140 DOE Letter Seeking Waiver of US Clause of PSDF Cooperative Agreement (4-16-09).pdf Usa lisa A. Baker Intellectual Property Counsel U.S. Department of Energy National Energy Technology Laboratory Phone: (304)285·4555 Fax: (304)285-4292 E-mail: Usa.Baker@netl.doe.gov bS >>> "Buettner, Jennifer M." 4/16/2009 11:18 AM >>> Hello Usa, As a follow-up to our conversation a couple of weeks ago regarding SCS's plans to license the TRIG(tm) technology In International markets, please see the attached letter requesting a waiver of the U.S. Competitiveness clause In the PSDF Cooperative Agreement advance patent waiver. You will receive the original copy of this letter tomorrow by Federal Express. We appreciate your assistance In this matter. Please contact me If you need additional Information or If I need to take any further action at this point. Best regards, Jennifer < {4-16-09).pdf> > Privileged and Confidential Communication (b) Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (office) (6) (mobile) 205-257-6381 (fax) jenmorrl@southernco.com This e-mail and any of Its attachments may contain non-public and/or SoCo FOIA Response 001780 proprietary Information of Southern Company and/or Its affiliates that is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e·mall Is Intended solely for the use of the individual or entity for which It Is Intended. If you are not the Intended recipient of this e·mall, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e·maU is contrary to the rights of Southern Company and/or its affiliates and Is prohibited. If you are not the Intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 2 SoCo FOIA Response 001781 JenniFer M. Duetlner Managing Allorm:y SCS Legnl Southern Company Sen ices, Jnc. 600 North Eighteenth Street Bin 7N-8374 Birmingham, Alabama 35203 United States Tel 205.257.6730 Fnx 205.257.6381 jcnmorri@southcrnco.com April 16,2009 By Federal Exp•·css and E-Mail Ms. Lisa Baker U.S. Department of Energy National Energy Technology Laboratory 3610 Collins Ferry Road Mail Stop: P04C Morgantown, West Virginia 26507 Re: Request for Waiver of U.S. Competitiveness Cluuse under Advance Patent Waiver Provisions of Cooperative Agreement Number DE-FC21-90MC25140 Dear Ms. Baker: This letter concerns Southern Company Services, Inc.'s ("SCS"} Cooperative Agreement Number DE-FC21-90MC25140 for the Power Systems Development Facility ("PSDF") ("Cooperative Agreement") and, more particularly. the advance patent waiver regulations of the Cooperative Agreement (Section 3.8). Section 3.8(t) of the advance patent waiver, entitled ..U.S. Competitiveness," requires that: .. . any products embodying any waived invention or produced through the use of any waived invention will be manufactured substantially in the United States, unless [SCS] can show, to the satisfaction of DOE that it is not commercially feasible to do so. By this letter, SCS respectfully requests that DOE waive compliance with this "U.S. Competitiveness" requirement so that SCS may engage in global efforts to SoCo FOIA Response 001782 Ms. Lisa Baker April 16, 2009 Page 2 of3 commercialize subject inventions under the Cooperative Agreement to which SCS has retained and/or will retain title. As good cause for the waiver, SCS explains as follows. To date, SCS has elected to retain title to three (3) subject inventions under the Cooperative Agreement, but it is possible that SCS could disclose additional subject inventions and elect to retain title to those as well. Two (2) of those three subject inventions generally relate to and are associated with the transport reactor integrated gasification technology ("TR[Gn1"). More specifically, the TRIQTM technology can be used to convert low-rank coal into syngas, which in turn can be used as a clean fuel source for power generation. Two (2) of the above-referenced subject inventions to which SCS has elected to retain title are enhancements to TRIQTM and, thus, they advance the benefits ofTRJGTM as a clean-coal technology. The same may be true for any future subject inventions to which SCS elects to retain title under the Cooperative Agreement. For many years, DOE has supported and encouraged the development and deployment of clean-coal technologies. Technologies like TRJonr and the associated subject inventions developed under the Cooperative Agreement bring environmental, sustainability, and economic benefits by, among other things, (i) reducing electric power plant emissions, (ii) providing opportunities for the use of plentiful, inexpensive coal as a feed stock for electric power generation, and (iii) creating low-cost sources of electricity. Deploying technologies such as TRIG1 "' and the associated subject inventions on a world-wide basis (not just in domestic markets) will maximize each of these benefits. SCS's commercialization efforts for TRIG1111 and any associated subject inventions under the Cooperative Agreement will be global in scope. SCS anticipates licensing TRJGTM and associated subject inventions to foreign entities in foreign countries. If such effot1s are successful, it is not likely that the foreign entities will have the subject invention components of the licensed TRIG1 "' technology manufactured in the United States. Accordingly, SCS will not be able to ensure compliance with the U.S. Competitiveness clause. In short, as contemplated by the U.S. Competitiveness clause, it will "not (be] commercially feasible" for SCS to ensure that "any products embodying any waived invention or produced through the usc of any waived invention will be manufactured substantially in the United States." As a result, SCS requests that DOE issue a \vritten waiver that excuses SCS from compliance with the U.S. Competitiveness requiremenl of the Cooperative Agreement for any subject inventions to which SCS has elected or elects to retain title under the Cooperative Agreement. SoCo FOIA Response 001783 Ms. Lisa Boker April 16, 2009 Page 3 of3 Please contact me if additional information regarding this mauer is needed. look forward to hearing from you. Very truly yours, 9-~f?t·~ Jennifer M. Buettner cc: Mr. Tom Russia! U.S. DOE I National Energy Technology Laboratory 626 Cochrans Mill Road Mail Stop: 922-M214 Pittsburgh, Pennsylvania 15236-0940 Mr. Morgan Mosser U.S. DOE I National Energy Technology Laboratory 3610 Collins Ferry Road Mail Stop; MS E06 Morgantown, West Virginia 26507-0880 Mr. Randall B. Rush (SCS) Mr. Kerry W. Bowers (SCS) SoCo FOIA Response 001784 Dunlap, Ann C. From: Sent: To: Cc: Subject: Baker, Lisa A. Wednesday, April 22, 2009 9:34 AM Russia!, Thomas Dowdell, Bonnie; Mosser, Morgan H. Fwd: RE: Request for Waiver of U.S. Competitiveness Clause -·SCSCooperative Agreement DE·FC21-90MC25 140 FYI. I'll ask Jennifer to address this issue. »> "Marchick, Robert" 4/22/2009 9:17AM >>> DELIBERATIVE PROCESS PRIVILEGED COMMUNICATION We have had similar requests based on the point that the foreign sales would necessarily have to be based on foreign production, as In the case of power plants, blofuel reactors, or in this case, gasifiers. In the Westinghouse nuclear reactor cases, for example, such as for China sales, we agreed to modify after assurances by W that there would nevertheless be many US design/engineering jobs created or maintained, i.e. "alternate US benefits", despite foreign production. In this request, I don't see any substantial addressing of alternate US benefits other than mentioning using coal as a feedstock. Not clear If they are talking about exporting US coal, or using coal from the respective foreign areas. At the very least, it would seem, they should provide Info on US jobs created or maintained. -----Original Message----From: Gottlieb, Paul Sent: Wednesday, Aprll22, 2009 7:11AM To: Marchlck, Robert; Field, Linda Subject: FW: Request for Waiver of U.S. Competitiveness Clause -SCSCooperatlve Agreement DE-FC21-90MC2.5140 bS 5 Paul Gottlieb Assistant General Counsel for Technology Transfer & Intellectual Property U.S. Department of Energy 1000 Independence Ave., SW Washington, DC 20585 202-586-3439 (fax 2805) Paui.Gottlleb@HQ.DOE.GOV http:l/www.gc.doe.gov/intellectual prop lab partner.htm From: Lisa Baker [mailto:Lisa.Baker@NETL.DOE.GOV] Sent: Tuesday, April 21, 2009 4:28 PM SoCo FOIA Response 001785 To: Gottlieb, Paul Cc: Dowdell, Bonnie; Mosser, Morgan; Russia!, Thomas Subject: Fwd: Request for Waiver of U.S. Competitiveness Clause -SCSCooperative Agreement DE-FC21-90MC25140 Paul, bS Thanks! lisa Usa A. Baker Intellectual Property Counsel U.S. Department of Energy National Energy Technology laboratory Phone: (304)285-4555 Fax: (304)285-4292 E-mail: Usa.Baker@netl.doe.gov >>>"Buettner, Jennifer M." 4/16/2009 11:18 AM >>> Hello Usa, As a follow-up to our conversation a couple of weeks ago regarding SCS's plans to license the TRIG(tm) technology in international markets, please see the attached letter requesting a waiver of the u.s. Competitiveness clause in the PSDF Cooperative Agreement advance patent waiver. You will receive the original copy of this letter tomorrow by Federal Express. We appreciate your assistance In this matter. Please contact me if you need additional Information or if I need to take any further action at this point. Best regards, Jennifer < (4-16·09).pdf> > Privileged and Confidential Communication Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin ?N-8374 Birmingham, Alabama 35203 205·257-6730 (office) (mobile) (b) (6) 205-257-6381 (fax) jenmorrl@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary Information of Southern Company and/or its affiliates that 2 SoCo FOIA Response 001786 Is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the Individual or entity for which it Is Intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or Its affiliates and Is prohibited. If you are not the Intended recipient of this e-mail, please notil'y the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 3 SoCo FOIA Response 001787 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Robbins, Brittley K. Wednesday, May 06, 2009 1:27 PM Johnson, Raymond D.; Russia!, Thomas Madden, Diane R. Fwd: Insurance Program Write up • Kemper County lGCC - DOE AwardDEFC26·06NT42391 11441 DOE Insurance Write-up on Kemper Co.doc Ray and Tom, Just as an FYI - see attached. Brittiey >>>"Henderson, Charles W." 5/5/2009 5:22PM>>> Diane, Attached is a write up of the insurance program for the Kemper County IGCC project. This insurance program Is intended to be typical of the coverages that would be placed for a retail plant for the Southern Company. These coverages will be placed for both Southern Company Services (SCS) and Mississippi Power Company (MPC) as appropriate. The deductibles may vary between SCS and MPC. The Department of Energy would be named as an additional insured on all appropriate policies. Please let me know If you have any questions concerning this Information. <> > Charles Henderson > Admin & Project Support Manager Gasification Technology > 8-824-5844 - Wilsonville (b) (6) 8-992-7313- Inverness (205) 992-7313 > > > > SoCo FOIA Response 001788 Southern Company Services' (SCS) Insurance Program And Considerations for the Kemper County IGCC Project SCS: CURRENTINSURANCEPROGRAM (b) (4) SoCo FOIA Response 001789 SoCo FOIA Response 001790 SoCo FOIA Response 001791 SoCo FOIA Response 001792 SoCo FOIA Response 001793 SoCo FOIA Response 001794 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: ~ • • It Baker, lisa A. Monday, May 11, 2009 4:36 PM Stiegel, Gary; Mosser, Morgan H. Russial, Thomas Fwd: FW: RE: Request for Waiver of U.S. Competitiveness Clause--SCSCooperative Agreement DE·FC21-90MC25140 Correspondence 5-l-09.pdf • I. bS >>> "Marchick, Robert" 5/11/2009 1:34PM >>> Usa To follow up, I just discussed this with Paul. bS Message·-··· From: Marchlck, Robert Sent: Monday, May 11, 2009 1:04 PM To: Baker, Lisa Cc: Gottlieb, Paul Subject: FW: RE: Request for Waiver of U.S. Competitiveness Clause --SCSCooperative Agreement DE·FC21-90MC25140 bS SoCo FOIA Response 001795 b5 -----Original Message----From: Usa Baker (mailto:Usa.Baker@NETLDOE.GOV] Sent: Monday, May 11, 2009 11:39 AM To: Marchlck, Robert Subject: Fwd: RE: Request for Waiver of U.S. Competitiveness Clause --SCSCooperatlve Agreement DE-FC21·90MC25140 b5 Thanks! Usa Usa A. Baker Intellectual Property Counsel U.S. Department of Energy National Energy Technology Laboratory Phone: {304)285-4555 Fax: {304)285-4292 E-~11: lisa.Baker@netl.doe.gov >>> "Canada, Mary-Kathryn Shaw" 5/1/2009 3:22 >>>PM>>> Usa, The attached letter is from Jennifer Buettner In response to your e·mail below. Please send her an e-mail if you have any follow·up questions or comments. Thank you, Mary Kathryn S. Canada, CP Paralegal scs Legal Services and Government Contract Compliance 600 North 18th Street (BIN 7N·8374) Birmingham, AL 35203 Phone: 205.257.5293 Cell: (b) (6) Fax: 205.257.6381 2 SoCo FOIA Response 001796 From: Usa Baker [mallto:Lisa.Baker@NETL.DOE.GOV) Sent: Wednesday, April22, 2009 8:40AM To: Buettner, Jennifer M. Cc: Bonnie Dowdell; Morgan Mosser; Thomas Russia!; Benson, Heather; Bowers, Kerry W.; Rush, Randall E. Subject: Re: Request for Waiver of U.S. Competitiveness Clause -- SCSCooperative Agreement DE-FC21-90MC25140 Jennifer, bS Usa lisa A. Baker Intellectual Property Counsel U.S. Department of Energy National Energy Technology Laboratory Phone: (304)285-4555 Fax: (304)285-'1292 E-mail: Llsa.Baker@netl.doe.gov >>>"Buettner, Jennifer M." 4/16/2009 11:18 AM>>> Hello Lisa, ¥ -I As a follow-up to our conversation a couple of weeks ago regarding SCS's plans to license the TRIG(tm) technology In International markets, please see the attached letter requesting a waiver of the U.S. Competitiveness clause In the PSDF Cooperative Agreement advance patent waiver. You will receive the original copy of this letter tomorrow by Federal Express. 3 SoCo FOIA Response 001797 We appreciate your assistance In this matter. Please contact me If you need additional information or If I need to take any further action at this point. Best regards, Jennifer < Agreement (4-16-09).pdf» Privileged and Confidential Communication (b) Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (ortlce) (6) (mobile) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary Information of Southern Company and/or its affiliates that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e-mail Is Intended solely .for the use or the Individual or entity for which It is Intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail Is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the Intended recipient of this e-mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 001798 Jennifer M. Buettner Managing Anorncy SCS Legal Southern Company Services, Inc. 600 Norlh Eighleenlh Street Din 7N-R:l74 Birmingham, Alnbamo 35203 United Stales Tci20S.257.6730 Fox 205.257.6381 jenmorri @southernco.com May 1,2009 By Federal Expa·css and E-Mail Ms. Lisa Baker U.S. Department of Energy National Energy Technology Laboratory 3610 Collins Ferry Rand Mail Stop: P04C Morgantown, West Virginia 26507 Re: Request for Waiver of U.S. Competitiveness Clause under Advance Patent Waiver Provisions of Cooperative Agreement Number DE-FC2l-90MC25140 Dcat· Ms. Baker: This letter concems Southern Company Services, Inc.'s ("SCS") Cooperative Agreement Number DE-FC21-90MC25140 for the Power Systems Development Facility ("PSDF") ("Cooperative Agreement"} and, more particularly, the advance patent waiver regulations of the Cooperative Agreement (Section 3.8). Section 3.8(t) of the advance patent waiver, entitled "U.S. Competitiveness," requires that: .. . any products embodying any waived invention or produced through the usc of any waived invention will be manufactured substantinlly in the United Stales, unless [SCS] can show, to the satisfaction of DOE that it is not commercially feasible to do so. By this letter, SCS respectfully requests that DOE waive compliance with this "U.S. Competili veness" requirement so that SCS may engage in global efforts to SoCo FOIA Response 001799 Ms. Lisa Baker May 1, 2009 Page 2 of 4 commercialize subject inventions under the Cooperative Agreement to which SCS has retained and/or will retain title. As good cause fol' the waiver, SCS explains as follows. To date, SCS has elected to retain title to three (3) subject inventions under the Cooperative Agreement, but it is possible that SCS could disclose additional subject inventions and elect to retain title to those as well. Two (2) of those three subject inventions generally relate to and are associated with the transpon reactor integrated gasification (''TRIGTM") technology. More specifically, the TRIGTM technology can be used to convert low-mnk coal into syngas, which in turn can be used as a clean fuel source for power generation. Two (2) of the above-referenced subject inventions to which SCS has elected to retain title are enhancements to TRIQTM und, thus, they advance the benefits ofTRIQTM as a clean-coal technology. The same may be true for any future subject inventions to which SCS elects to retain title under the Cooperative Agreement. For many years, DOE has supported and encouraged the development and deployment of clean-coal technologies. Technologies like TRJQTM and the associated subject inventions developed under the Coopemtive Agreement bring environmental, sustainability, und economic benefits by, among other things, (i) reducing electric power plant emissions, (ii) providing opportunities for the use of plentiful, inexpensive coal as a feed stock for electric power generation, and (iii) creating low-cost sources of electricity. Deploying technologies such as TRIGTM and the associated subject inventions on a world-wide basis (not just in domestic markets) will maximize each of these benefits. In particular, TRIGTM(and the associated subject inventions) allows power producers to convert low-rank coal (supplies of which are plentiful throughout the world) into a clean burning synthesis gas, thereby promoting sustainable fuels while protecting the environment. Applications ofTRJQTM.based IGCC for electric power generation throughout the world will facilitate the reduction of C02 and other emissions on a worldwide basis. Because the global demand fo1· electricity continues to rise, countries around the world will continue to rely upon abundant coal supplies to meet that demand. Converting coal to a synthesis gas (through the TRIGTM technology) that can be used with conventional combined-cycle gas turbines presents a solution to concerns about the environmental effects of C02 emissions. Commercial applications of TRIGTM using lower cost, low-rank coals in foreign countries where those coals are available will also help to address the economic challenges faced by developing countries and, as a result, in other parts of the world, including the United States. By making coal, especially lower-rank coal - which is among the least expensive fuel sources for power generation- a viable option for meeting increasing electricity demand, TRIGTM will reduce energy costs and thereby facilitate economic development. The effects of such development extend beyond the SoCo FOIA Response 001800 Ms. Lisa Baker May I, 2009 Pnge 3 of 4 boundaries of a single country- increasing financial stability in one area of the world generates economic opportunities in other parts of the world, including the United States. SCS's commercialization efforts for TRJGTM and any associated subject inventions under the Cooperative Agreement will be global in scope. SCS anticipates licensing TRIGTM and the associated subject inventions to foreign entities in foreign countries. If such efforts are successful, it is likely that lhe foreign licensees will choose to have the components of the subject inventions manufactured in their own countries or other countries outside the United States. There are a couple of reasons for this. First, the costs will likely be lower and the administrative aspects of the procurement process will be more efficient and effective if foreign entities procure manufactured products from entities within their own countries. Second, the components of the subject inventions are the same types of components that comprise the entire TRlGTM system (e.g., valves, tanks, and pipes) and, thus, are not likely to be procured separately from all of the other components. For example, it would be impractical for a foreign licensee to procure the tanks for the subject inventions from one vendor in the United States and all of the tanks for the other components of the TRIG1 M system from its standard vendors. Accordingly, SCS will not be able to ensure compliance with the U.S. Competitiveness clause. However, it is impot1ant to understand that the spirit and intent of the U.S. Competitiveness clause will be achieved. Specifically, TRJGTM is an American-owned and controlled technology and, therefore, American companies and their employees will be involved in marketing, engineering, and certain operating aspects of each project that is licensed. Thus, SCS's global licensing efforts will lead to the creation and/or preservation of business and engineering jobs in America. Moreover, SCS anticipates that the successful demonstration of TRIQTM and the associated subject inventions in foreign markets will spur domestic demand for the technology, thereby creating opportunities foa· applications ofTRIG1111 in the United States where licensees will more readily procure American-manufactured equipment and will certainly employ American workers. In short, as contemplated by the U.S. Competitiveness clause, it will "not [be) commercially feasible" for SCS to ensure that "any products embodying any waived invention or produced through the use of any waived invention will be manufactured substantially in the United States." As a result, SCS requests that DOE issue a written waiver that excuses SCS from compliance with the U.S. Competitiveness requirement of the Cooperative Agreement for any subject inventions to which SCS has elected or elects to retain title under the Cooperative Agreement. SoCo FOIA Response 001801 Ms. Lisa Baker May 1,2009 Pnge4 of 4 Please contact me if additional information regarding this matter is needed. I look forward to hearing from you. Very truly yours, CC:tB:1~~ cc: Mr. Tom Russia! U.S. DOE I National Energy Technology Laboratory 626 Cochrnns Mill Road Mail Stop: 922··M214 Pittsburgh, Pennsylvania 15236-0940 Mr. Morgan Mosser U.S. DOE I National Energy Technology Laboratory 3610 Collins Ferry Road Mail Stop: MS E06 Morgantown, West Virginia 26507-0880 Mr. Randall E. Rush (SCS) Mr. Kerry W. Bowers (SCS) SoCo FOIA Response 001802 From: "Pinkston, Tim E." Friday, May 15, 2009 3:03 PM Robbins, Brittley; Madden, Diane CWHENDER@southernco.com; JENMORRI@southernco.com Cooperative Agreement Number DE-FC26-06NT42391 - MajorEquipment Strategic Sourcing Sent: To: Cc: Subject: The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. As we discussed, Southern Company Services, Inc. (SCS) is planning to issue a single procurement package for several pieces of major equipment for the Kemper County IGCC Project. The list of equipment types expected to be included in the package is attached. The value of the package could be dollars or more. (b) (4) For the Gasification Island portion of the IGCC alone, there are more than 600 pieces of equipment, and the procurement schedule for the overall Project is tight. In consideration of the overall tight schedule and the large number of major equipment, SCS is planning to pursue a Major Equipment Strategic Sourcing package, which will simplify, streamline, and compress the Project's procurement process by limiting the total number of procurements and contract negotiations. In addition, SCS and the Project owner, Mississippi Power Company, are unable to commit to major equipment procurements until after the expected approval of the Project by the Mississippi Public Service Commission (MPSC) in mid-October of this year. Since the major equipment contracts will not be awarded until after the MPSC decision, the procurement schedule is further compressed. Combining the major items of equipment into one procurement package will reduce the time spent in procuring each item of equipment and will better enable SCS to maintain the aggressive Project schedule. The Strategic Sourcing package approach is expected to result in a lower overall cost than individual packages because the vendors that submit bids will have an opportunity to make a large sale without incurring the additional administrative costs associated with negotiating each item separately. Also, SCS is expecting to obtain considerable volume discounts due to the breadth of the package. The successful bidder will be in a much better position to pass along lower material costs and schedule manufacturing slots at a lower cost. In addition, there will only be minor differences in terms and conditions for each class of equipment, thus contract negotiations are expected to be greatly SoCo FOIA Response 001803 simplified and shortened. Moreover, SCS has recently completed large purchases and contract negotiations on other projects with the two vendors who will be bidding on the Strategic Sourcing package, so the parties are accustomed to negotiating with each other, which will also reduce the time and administrative costs of negotiations. Since the combustion turbines (CTs) and the associated long Term Service Agreements (LTSA) provided by the CT vendors will be included in the package, the vendors that will have an opportunity to submit proposals are limited- SCS is planning to request proposals from two vendors ((b) (4) (b) (4) and (b) (4)). Both and (b) (4) are fully qualified to bid on each item of equipment. We believe that the two vendors identified (in part through an earlier CT inquiry process) provide the best overall option for the equipment included in the package. In addition, the Project is being designed with the ability to accommodate either the (b) (4) or the (b) (4) Separate parts of the Strategic Sourcing inquiry package will be issued to the vendors for each equipment class as the required inquiry package information becomes available. Although the vendors will submit separate bids for each equipment class, the vendors have been instructed to bid based on the entire package being awarded to only one bidder. The vendors understand that SCS will evaluate each vendor's bid based on the overall value of the total bid, not as separate parts. Evaluation of the overall package will include a life cycle evaluation for the LTSA. All of the LTSA is not part of the scope under SCS's Cooperative Agreement with DOE since it is expected to cover 96,000 hours of CT operation and will extend beyond the demonstration period in which DOE is participating. However, the overall award for the Strategic Sourcing package, including the parts of the package that will include DOE-allowable costs, will be made based on the lowest evaluated value for the entire package, including the LTSA. Although the LTSA will be included in the package, a separate breakout of the l TSA costs will be provided by the vendors, and the LTSA costs will not be billed to DOE beyond any allowable portion during the demonstration phase. SCS is requesting that DOE approve this Strategic Sourcing plan, which is expected to result in highly competitive bids with the potential for volume discounts and will ultimately enable SCS to maintain the Project schedule by streamlining the overall sourcing and contract negotiations for the subject equipment. Please let me know if you have questions or would like to arrange a conference call to discuss. Tim Pinkston Project Manager 2 SoCo FOIA Response 001804 Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) 3 SoCo FOIA Response 001805 Dunlap, Ann From: Sent: To: Cc: Subject: Attachments: c. Brittley Robbins Monday, May 18, 2009 10:57 AM Russia!, Thomas Madden, Diane; Johnson, Raymond Fwd: Cooperative Agreement Number DE-FC26-06NT42391- MajorEquipment Strategic Sourcing TEXT.htm Tom, bS >>>"Pinkston, Tim E." 5/15/2009 4:01PM>>> The Recipient of Cooperative Agreement DE-FC26-06NT'I2391 considers the material furnished herein to contain confidential business information which Is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. As we discussed, Southern Company Services, Inc. (SCS) Is planning to Issue a single procurement package for several pieces of major equipment for the Kemper County IGCC Project. The list of equipment types expected to be Included in the package Is attached. The value of the package could be (b) (4) dollars or more. For the Gasification Island portion of the IGCC alone, there are more than 600 pieces of equipment, and the procurement schedule for the overall Project is tight. In consideration of the overall tight schedule and the large number of major equipment, SCS Is planning to pursue a Major Equipment Strategic Sourcing package, which will simplify, streamline, and compress the Project's procurement process by limiting the total number of procurements and contract negotiations. In addition, SCS and the Project owner, Mississippi Power Company, are unable to commit to majOr equipment procurements until after the expected approval of the Project by the Mississippi Public Service Commission (MPSC) In mid-October of this year. Since the major equipment contracts will not be awarded until after the MPSC decision, the procurement schedule is further compressed. Combining the major items of equipment into one procurement package will reduce the time spent In procuring each Item of equipment and will better enable scs to maintain the aggressive Project schedule. The Strategic Sourcing package approach Is expected to result in a lower overall cost than individual packages because the vendors that submit bids will have an opportunity to make a large sale without incurring the additional administrative costs associated with negotiating each Item separately. Also, SCS Is expecting to obtain considerable volume discounts due to the breadth of the package. The successful bidder will be In a much better position to pass along lower material costs and SoCo FOIA Response 001806 schedule manufacturing slots at a lower cost. In addition, there will only be minor differences In terms and conditions for each class or equipment, thus contract negotiations are expected to be greatly simplified and shortened. Moreover, SCS has recently completed large purchases and contract negotiations on other projects with the two vendors who will be bidding on the Strategic Sourcing package, so the parties are accustomed to negotiating with each other, which will also reduce the time and administrative costs of negotiations. Since the combustion turbines (CTs) and the associated Long Term Service Agreements (LTSA) provided by the CT vendors will be Included In the package, the vendors that will have an opportunity to submit proposals are limited - SCS is planning to request proposals from two vendors ((b) (4) and (b) (4) ). Both (b) (4) are fully qualified to bid on each item of equipment. We believe that the two vendors Identified (In part through an earlier CT inquiry process) provide the best overall option for the equipment Included in the package. In addition, the Project Is being designed with the ablllty to accommodate either the (b) (4) or the (b) (4) Separate parts of the Strategic Sourcing Inquiry package will be Issued to the vendors for each equipment class as the required inquiry package information becomes available. Although the vendors will submit separate bids for each equipment class, the vendors have been Instructed to bid based on the entire package being awarded to only one bidder. The vendors understand that SCS will evaluate each vendor's bid based on the overall value of the total bid, not as separate parts. Evaluation of the overall package will include a life cycle evaluation for the LTSA. Ali of the LTSA Is not part of the scope under SCS's Cooperative Agreement wllh DOE since it is expected to cover 96,000 hours of CT operation and wlii extend beyond the demonstration period In which DOE is participating. However, the overall award for the Strategic Sourcing package, Including the parts of the package that will indude DOE-allowable costs, will be made based on the lowest evaluated value for the entire package, Including the LTSA. Although the LTSA will be Included in the package, a separate breakout of the LTSA costs will be provided by the vendors, and the LTSA costs will not be billed to DOE beyond any allowable portion during the demonstration phase. SCS Is requesting that DOE approve this Strategic Sourcing plan, which is expected to result in highly competitive bids with the potential for volume discounts and will ultimately enable SCS to maintain the Project schedule by streamlining the overall sourcing and contract negotiations for the subject equipment. . -1 Please let me know If you have questions or would like to arrange a conference call to discuss. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) 2 SoCo FOIA Response 001807 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Baker, Lisa A. Wednesday, May 20, 2009 12:40 PM Clayton, Stewart; Stiegel, Gary; Mosser, Morgan H.; Klara, Scott M. Russial, Thomas Fwd: FW: RE: Request for Waiver of U.S. Competitiveness Clause--SCSCooperative Agreement DE·FC21 ·90MC25140 Correspondence S-1-09.pdf In anticipation of our lpm conference call, this e·mallls from HQ patent counsel In response to SCS's May !letter. Bob Marchlck should also be on the call today. >>> "Marchlck, Robert" 5/11/2009 1:34PM >>> Usa b5 From: Marchick, Robert Sent: Monday, May 11, 2009 1:0'1 PM To: Baker, Lisa Cc: Gottlieb, Paul Subject: FW: RE: Request for Waiver of U.S. Competitiveness Clause --SCSCooperative Agreement DE·FC21·90MC25140 bS SoCo FOIA Response 001808 b5 Message----From: Lisa Baker [mallto:Lisa.Baker@NETL.DOE.GOV) Sent: Monday, May 11, 2009 11:39 AM To: Marchlck, Robert Subject: Fwd: RE: Request for Waiver of U.S. Competitiveness Clause --scscooperatlve Agreement DE-FC21-90MC25l'IO b5 Thanks! lisa Usa A. Baker Intellectual Properly Counsel u.s. Department of Energy National Energy Technology Laboratory Phone: (304)285-4555 Fax: (304)285-4292 E-mail: Lisa.Baker@netl.doe.gov >>> "Canada, Mary-Kathryn Shaw" 5/1/2009 3:22 >>>PM>>> Lisa, The attached letter is from Jennifer Buettner In response to your e-mail below. Please send her an e-mail if you have any follow-up questions or comments. Thank you, Mary Kathryn S. Canada, CP Paralegal SCS Legal Services and Government Contract Compliance 600 North 18th Street (BIN 7N·837'1) Birmingham, AL 35203 Phone: 205.257.5293 Cell: (b) (6) Fax: 205.257.6381 2 SoCo FOIA Response 001809 From: Lisa Baker [mallto:Lisa.Baker@NETL.DOE.GOV] Sent: Wednesday, April 22, 2009 8:40 AM To: Buettner, Jennifer M. Cc: Bonnie Dowdell; Morgan Mosser; Thomas Russlal; Benson, Heather; Bowers, Kerry W.; Rush, Randall E. Subject: Re: Request for Waiver of U.S. Competitiveness Clause -- SCSCooperative Agreement DE-FC21-90MC25140 b5 Lisa Usa A. Baker Intellectual Property Counsel U.5. Department of Energy National Energy Technology Laboratory Phone: (304)285-4555 Fax: (304)285-4292 E-mail: Llsa.Baker@netl.doe.gov >>>"Buettner, Jennifer M." 4/16/2009 11:18 AM>>> Hello Usa, ; I As a follow-up to our conversation a couple of weeks ago regarding SCS's plans to license the TRIG(tm) technology In International markets, please see the attached letter requesting a waiver of the u.s. Competitiveness clause In the PSDF Cooperative Agreement advance patent waiver. You will receive the original copy of this letter tomorrow by Federal Express. We appreciate your assistance In this matter. Please contact me 3 SoCo FOIA Response 001810 If you need additional Information or If I need to take any further action at this point. Best regards, Jennifer < Agreement ( 4-16-09).pdf> > Privileged and Confidential Communication (b) Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (offtce) (6) {mobile) 205-257-6381 {fax) jenmorri@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary Information of Southern Company and/or Its affiliates that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e-mail is Intended solely for the use of the individual or entity for which It Is Intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or Its affiliates and is prohibited. If you are not the Intended recipient of this e-mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 001811 From: Sent: To: Cc: Subject: Attachments: "Pinkston, Tim E." Wednesday, May 20, 2009 4:29 PM Madden, Diane CWHENDER@southernco.com Approvals Required for Cooperative Agreement DE-FC26-06NT42391 Approvals.doc Diane, As required by Article 2.29 of the Cooperative Agreement, a document is attached that lists the subject approvals required for the Kemper County IGCC. Please let me know if you have questions. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cel (b) (6) «Approvals.doc» SoCo FOIA Response 001812 Approvals Required for the Kemper County IGCC PERMIT/MILESTONE Air PSD Permit Develop PSD permit application Work with MDEQ to issue Draft Permit Final Draft Permit to Public notice Modification Required by Changes Associated with C02 Capture NPDES surface water discharge permit- if required Model outfall characteristics Prepare permit application Groundwater Test Well Permit Groundwater Production Well Permit Review test data and calculate well(s} specs Prepare application Storm water Construction Permits Facility Storm water Construction Permit Support Materials Modification Design Storm water controls for facility construction Prepare Storm water permit modification Ash Storag e Facility Permit Complete Geotech investiaation Desian storaQe facilitv Prepare permit application NEPA Environmental Impact Statement AGENCY MILESTONE DATE MDEQ FILING DATE APPROVAL DATE 12120/2007 10/14/2006 EXPECTED APPROVAL DATE 12/19/2007 7/23/2008 8/16/2008 12/31/2009 MDEQ 5/1/2009 11/30/2009 3/1/2009 4/1/2009 MDEQ 5/30/2007 6/26/2007 MDEQ 5/21/2008 6/24/2008 10/5/2007 11/13/2007 4/30/2006 5/20/2008 MDEQ MDEQ 11/13/2007 8/1/2009 9/1/2009 MDEQ 4/2/2010 1/1/2012 6/30/09 12/31/2009 4/1/2010 DOE 3/1/2010 SoCo FOIA Response 001813 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Tom, Madden, Diane R. Tuesday, June 09, 2009 10:46 AM Russial, Thomas Fwd: Kemper County IGCC Project Update lTC Certification Update.pdf; Order Denying Motion to Stay & Establishing a Schedule.pdf . Diane >>>"Pinkston, Tim E." 6/8/2009 4:58PM>>> <> Di <> ane, The two documents that we discussed are attached. Please call me if you would like to discuss further. Tim . ' SoCo FOIA Response 001814 Fflil) 06/0 1/2009 lfJ!MicF~f\~ Commission ey• 3nd CouNelars BSB --l'.O.IIower Company ("MPC" or the "Company") and files this Update of the Company's certification status under the Investment Tax Credit ("lTC") Program established pW'suant to Tit[e XIII of EPAct 2005 and Section 48A of the Intemnl Revenue Code and would show unto the Mississippi Public Service Conunission ("Conunission") the following: 1. On or about April 7, 2009, MPC filed its Clarification of the Investment Tax Credit Program ("Clarification Filing"), which the Company incorporates herein by reference, as updated and modified berein. In the Clarification Filing, the Company outlined the process by which the Company applied for, and was allocated $133 million in Investment Tax Credits from the lntemal Revenue Service ("IRS") established under Title XIII of EPAct 2005 ("Phase I Credits") for the Kemper County IGCC Project. The Clarification Filing detailed the Company's ~ ·• then-current understanding regarding the required "placed-in-service" date for the proposed Kemper County IGGC Project necessary for preservation of the ITCs and the impact of that "placed-in-service" date on the scheduling order proposed by the Company in order to permit timely construction of the Project. 10!6116 *Electronic Copy* MS Public Service Commission* 6/8/2009 * MS Public Service Commission* Electronic 1 SoCo FOIA Response 001816 · c:: FILED 06/01/2009 ty1S Pubhf§ervice Commission 2. In its Clarification Filing, the Company stated that it ••has complied wi@@0011WA·14 requirements under 26 U.S.C. § 48A(e)(2) and is awaiting fonnal certification from the IRS" of the Company's Section 48A application. On advice of its tax experts who were communicating directly with representatives of the IRS, the Company expected that such certification would be received very soon after the Company's November 24, 2008, certification to the IRS and thus, would require a "placed~in·service" date for the Kcmpe1· County IGCC Project of November 2013 to preserve LheJTCs. 3. It was not tmtil a letter dated May 11, 2009, however, that the IRS formally certified the Company's Section 48A application, confinning the Company had complied with Section 48A(e)(2) ("Certification Letter"). A trne and correct copy of the Certification Letter is attached hereto as Exhibit "A." The IRS dctcnnincd in the Cctiification Letter that pursuant to Section 6.03 ofNotice 2006·24 (as updated by" Notice 2007-52, Notice 2008-26, Notice 2008-96, and Notice 2009-24) ("IRS Guidance"), which provides the IRS's official guidance on the advanced coal project investment tax credit program, the date of Certification Letter (i.e. May 11, 2009) constitutes the date of certification ofMPC's Section 48A application. 4. Based upon this IRS certification and pursuant to Section 48A(d)(2)(E), MPC now h~s five (5) years from the date of the Ma}' 11, 2009, Certification Letter to place the Kemper County IGcc-Project in service. According to the Certification Letter and the IRS Guidance, if the project is not placed in service on or before May 11, 2014, "the certification will no longer be valid and the Section 48A credits allocated to Mississippi Power Company fol' the integrated gasification combined cycle project in Kemper County, Mississippi, will be forfeited." While the authority to establish the certification date for :NIPC's 48A application rests with the IRS, once the certification is issued, the "placed~in-service" date established by Congress under JOJ6JI.6 2 * Electronic Copy * MS Public Service Commission * 6/8/2009 * MS Public Service Commission * Electronic • SoCo FOIA Response 001817 --···. --·-- FILED 06/01/2009 [ ,'MS fJJblic Service Commissiot]_ EPAct 2005 for the Phase I Credits cu!Ulot be altered without further amendment to by Congress. S~~BtYA-14 Specifically, Section 48A provides that "[a]n applicant which receives a certification shall have 5 years from the date of issuance of the certification in order to place the project in service and if such project is not placed ·in service by that time period then the certification shall no longer be valid." 26 U.S.C. § 48A(d}(2)(E) (West 2009). 5. While the Phase I Credits allocated to and now certified for MPC will not be forfeited until May 11, 2014 (instead of November 29,2013 as originally understood by MPC}, it is still extremely impottant that consideration of the Company's ce~·lificate application be undertaken in a timely mrumer. In its filing, the Company proposed thut hearings be conducted in June 2009 and that an order be issued by August 2009. This schedule was proposed to aUow adequate time for all parties to consider the application, conduct discovery, file and hear motion~, file comments and testimony and hear the case. Allowing for contingencies, the schedule provided what the Company considered to be the minimal time, considering the risk of losing the ITC allocation, to design, procure, construct, and test the Project in time to meet the commercial operation date ofNovember 2013. 6. Almost five (5) months have elapsed since the Company's filing on January 16, 2009. The proposed scheduling order contemplated the completion of several milestones in the regulatory review process, none of which have even been scheduled by the Commission, much less undertaken by the parties. Only the intervention and discovery processes have been proceeding while a decision on a schedule for this proceeding is being considered. No other parties have identified witnesses or filed testimony, no provision has been made for addressing issues fn a pre-hearing conference, no hearings have been set, and no provision has been made for the treatment of confidential infonnation in such hearings. Over five (5} years of continuous 101611.6 3 • Electronic Copy* MS Public Service Commission • 6/8/2009 * MS Public Service Commission • Electronic .• SoCo FOIA Response 001818 c. FliED 06/01/2009 MS Public Service Commission &.-.....-_. • - - - planning, designing, engineering, procurement, constntction and testing are required_2t)l!J!!Jgl!fA~ 14 new baseload project of this type into service. The Company submits tha_t the e:rtension of the "placed~in-service" requirtment for preservation of the ITCs does not allow for a schedule delay. The lTC extension should at most allow tor the completion of this proceeding not more than five (5) months following the Company's original proposed schedule, still allowing for reasonable schedule contingencies, without unnecessarily delaying the process. Stated differently, the new "placed-in-service" deadline only recovers the time lost from the Company's proposed schedule. 7. As indicated in Ben Stone's March 5, 2009, letter to the Commission, any significant delays in the resolution of this proceeding beyond the schedule originally proposed by would require Company to shorten the required time to design, procure, and construct the Project (i) increasing the l'isk of higher costs due to schedule compression; and/or (ii) delaying the placed-in-service date beyond that required for the preservation of the ITCs. Further, the Company believes a delay of this project beyond the May 2014 date could compromise the Company's ability to retain the larger $270 million funding incentive awarded under CCPI2, significantly jeopardizing the Project. It also expose.c; the Company to spending commitmeJtts beyond whal MPC can reasonably risk without certainty ·of recovery. Stopping spending or otherwise interrupting the continuous development processes further jeopardizes our ability to deliver the Pl'Oject when needed. The Company is and bas always been committed to maximizing the federal incentives available for the Project, because we believe that to be in the best interests of our customers. Therefore, the Company submits that preserving the lTCs and the May 2014 in service date are important reasons for the timely administration of this docket IO)IlU 4 * Electronic Copy * MS Public Service Commission * 6/8/2009 * MS Public Service Commission * Electronic 1 SoCo FOIA Response 001819 Respectfully submitted on this, the / ~ay of June, 2009. . I FliED 06/01/2009 MS Public Service Commission ~009-UA-1 ~ MISSISSIPPI POWER COMPANY BY: BENH. STONE BALCH & BINGHAM LLP BY,~ ·~ ~tone Mississippi Bar No. 7934 TIMOTHY A. FORD Mississippi Bar No. 5415 RlcKY J. Cox Mississippi Bar No. 9606 LEO E. MANUEL Mississippi Bar No. 101985 • BALCH & BINGHAM LLP 1310 Twenty-Fifth Avenue Post Office Box 130 Gulfport, MS 39502-0130 Phone: {228) 864~9900 Facsimile: {228) 864-8221 . 1 10l6ll' s _. Electronic Copy* MS Public Service Commission _. 6/8/2009 * MS Public Service Commission • Electronic r SoCo FOIA Response 001820 c:: FILED 06/01/2009 MS Public Service Commission STATE OF MISSISSIPPI 2009~UA-14 COUNTY OF HARRISON PERSONALLY appeared before me, the undersigned authority in and for the said County and State, within my jnrisdiction, the within named BEN H. STONE, who after being duly sworn on oat~t acknowledged that he is Attorney for MISSISSIPPI PO\VER COMPANY and that for and on behalf of the said MISSISSIPPI POWER COMPAI'fY and he signed and deliv~red llS its act and deed, the above and foregoing instnunent of writing for the purposes mentioned orr the day and year therein mentioned, after first having beet\ duly authorized by said MISSISSIPPI POWER COMPANY so to do, and that the statements -contained in the foregoing instrument are true and correct to the best of his knowledge, infonnation and belief. SWORN TO .AJ.'\lD SUBSCRIBED BEFORE ME, this the ;4:/:day of June, 2009. k~ .• UBL!C My Commission Expires: __j-4 1016lU 1/p / ki!J 6 *Electronic Copy* MS Public Service Commission* 6/8/2009 * MS Public Service Commission" Electronic • SoCo FOIA Response 001821 - --·-C FILED 06/01/2009 !f!:1S Public Service Coml1)ission CERTIFICATE OF SERVICE 2009-UAM14 I, BEN H. STONE, counsel for Mississippi Power Company in the foregoing filing on even date herewith du hereby certify that in compliance with Rule 6.112 of the Mississippi Public Service Commission Public Utility Rules ofPraclice and Procedure: (1) An original and twelve (12) copies ofthe filing have been filed with the Commission by U.S. Mail to: ~r. Brian U. Ray Executive Secretary Mississippi P~1blic Service Commission 501 North West Street Suite 201A Jackson, Mississippi 39201 (2) A copy of the filing with all exhibits attached thereto has been provided to the following persons via U.S. Mail, postage prepaid: Robett C. Wiygul, Esquire Attorney for MS Chapter SietTa Club Waltzer & Associates 1011 Iberville Drive Ocean Springs, MS 39564 J. Kevin Watson, Esquire Attorney for Ergon Refining, Inc. Watson & Jones, P.A. Post Office Box 23546 Jackson, Mississippi 39225 Andrea Issod, Esquire Mr. Roland Woodward Siena Club Envirorunental Law Manager - Energy Supply Program Ergon, Inc. 85 Second Street, 2nd Floor Post Office Box 1639 San .Francisco, California 941 OS Jackson, Mississippi 39215 Sondra McLemore, Esquire Special Assistant Altomey General Office of the Attorney General Post Office Box 22947 Jackson, Mississippi 39225-2947 IDIGIU Kathedne W. King, Esquire J. Randy Yow1g, Esquire Lauren M. Walker, Esquire Attorneys for Untegra Power Group LLC Kean Miller Hawthorne D'Armond McCowan & Jarman Post Office Box 3513 Baton Rouge, Louisiana 70821 7 * Electronic Copy * MS Public Service Commission * 6/8/2009 * MS Public Service Commission * Electronic t SoCo FOIA Response 001822 I - FILED. 06/07/2009 ,MS Public Service Comf]1isswn 2009-UA-14 Mr. Steve McKerma 741 County Road 313 Pachuta, Mississippi 39347 Mr. Hunter Lipscomb Commercial Development Representative International Energy Solutions, Inc. 105 Hummingbird Lane Starkville, Mississippi 39759 Mr. Queshaun Sudbury 4700 28th Street Meridian, Mississippi 39307-4223 Robert G. Waites, Esquire Executive Director Mississippi Public Utilities Staff 501 Norlh West Street, Suite 301B Jackson, Mississippi 39215-1174 Brad Pigott, Esquire Attorney for Magnolia Energy LP and Entegrn Power Group LLC Pigott, Reeves & Johnson 775 North Congress Street Jackson, Mississippi 39202 George Fleming, Esquire General Counsel Mi5sissippi Public Utilities Staff 501 North West Street, Suite 301B Ja~;kson, Mississippi 39215-1174 Gail A. Crowell, Esquire Attorney for South Mississippi Electric Power Association Gail A. Crowell, P.L.L.C. Post Office Box 6214 Gulfport, Mississippi 39506-6214 Mr. Ralph Smith Larkin ned Associates 15728 Fanninglon Road Lavonia, Michigan 48154 Henderson S. Hall, Jr., Esquire Attomey for Entergy Mississippi, Inc. Wise Cmter Child & Caraway, PA Post Office Box 651 Jackson, Mississippi 39205 Mr. Miguel Campo Managing Director Boston Pacific Company, Inc. 1100 New York A venue, NW, Suite 490 East Washington DC 20005 Mr. David Magnus Boonin Multi·Utility Research and Policy National Regulatory Research Institute 203 Riverview Rond Swarthmore, Pennsylvania 19081 IOIUI.& 8 *Electronic Copy* MS Public Service Commission* 6/8/2009 * MS Public Service Commission* Electronic 1 SoCo FOIA Response 001823 -- - - . FILED 06/01/2009 - [ MS Public Sf!.rvic_e Commis_~on (3) MPC has complied with all other requirements of the Mississippi Publ&J@~A-74 Commission's Public Utility Rules of l)ractice and Procedure. Datedthisthe[~ dayofJune,~ . ~ ~. IU6JU 9 *Electronic Copy* MS Public Service Commission* 6/8/2009 * MS Public Service Commission" Electronic 1 SoCo FOIA Response 001824 -- FILEO .. 06/01/2009 MS Public Service Commission : [ DEPARTMENT OF THE TREASURY INTERNAL REVENUE SERVICE WASHINGTON, D.~. 20224 large and Mld-Sizo Buslnus Division MAY 1 12009 Mr. Tim L. Fallaw Assistant Controller The Southern Company & Subsidiaries 241 Ralph McGill Blvd. NE Bin 10139 Atlanta, GA 30308 Dear Mr. Fallaw: The enclosed copy of a letter Is sent to you under the provisions of a power of attorney and declaration of representative or other proper authorization currenlly on file with the Internal Revenue Service. If you have any questions, you may contact me or Marc Bernabe, LMSB Project Manager, at 713-209-3958. ~7;1·~ Keith M. Jones Industry Director Natural Resources and Construction Enclosure EXHIBIT i ----ttAtt *Electronic Copy* MS Public Service Commission* 6/8/2009 * MS Public Service Commission • Electronic • SoCo FOIA Response 001825 I - . -- FILED 06/01/2009 MS Public Serv1ce C9mm1sS/Of1 OEPAR'fMENT OF THE TREASURY INTERNAL REVENUE SERVICE WASHINGTON, D.C. 20~24 Latge ~n>> "Buettner, Jennifer M." 7/1/2009 11:16 AM >>> Hi Lisa, I apologize for the delay in our response, and I appreciate your continued review of our waiver request. Om responses to your questions are set out below. If there is additional infom1ation thut you need for us to provide, please contact me. Thank you, Jennifer (1) (n) Please see the attachments to this e-mail, which are (i) a copy of our letter to DOE Patent Counsel disclosing and electing to retain title to the two (2) subject inventions that will be part of the TRIGT technology that SCS is seeking to commercialize, and (ii) copies of DOE Patent Counsel's letters acknowledging our disclosure of and election to retain title to those two subject inventions. These two subject inventions are entitled Continuous Coarse Ash Depressurization System and Continuous Fine Ash De!>ressurization System. (b) One additional subject invention1·elnted to TRIGT is disclosed here, and relevant materials are attached. This subject invention is entitled Method and Apparatus for the Separation of a Gas-Solids Mixture in a Circulating Fluidized Bed Reactor. (c) Please note that SCS's May I, 2009letter requesting a waiver of the U.S. Competitiveness clause seeks a waiver that will be applicable to all past and fi.tturc subject inventions that SCS discloses and elects to retain title to under Cooperative Agreement Number DE-FC21-90MC25140. lf such a "blanket" waiver is possible, SCS respectfully requests that it be granted fat· subject inventions under the Cooperative Agreement. (2)(a) SCS is currently engaged in a project under Cooperative Agreement Number DE-FC26-06NT42391 to deploy TRIGT technology ("Kemper County"). The Kemper County pi'Oject will be the first application of TRIGT in a commercial setting. Based on the success of the Kemper County project, SCS anticipates the opening of a larger mmket in the United States tot· licensing TRIGT, particularly since this technology is SoCo FOIA Response 001839 uniquely designed to be used with low-rnnk coal, which accounts for approximately one-half of the coal reserves in the United States. (b) Under its Cooperative Agreement Number DE-FC26-06NT42391, SCS is required to prepare and submit to DOE a Commercialization Strategy report, which will contain information of the nature described in the second sentence of item (2) of your e-mail. Such a report docs not exist at this time because that deliverable is not yet due to DOE. (c) SCS requests that the waiver of the U.S. Competitiveness clause also apply not only to products embodying subject inventions in applications of the technology in foreign countries, but also in the United States. (3) KBR does not have a role regarding this request because it is SCS who is in privity of contract with DOE. Therefore, we have not informed KBR of this t·equest. Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (office) (mobile) (b) (6) 205-257-6381 (fax) jenmorl'i@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary Information of Southern Company and/or its affiliates that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is Intended solely for the use of the Individual or entity for which It is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the Intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: lisa Baker [matlto:Lisa.Baker@NETL.DOE.GOV] Sent: Tuesday, June 02, 2009 3:06PM To: Buettner, Jennifer M. cc: Morgan Mosser; Thomas Russia! Subject: Additional information required for evaluation of request to waive US competitiveness requirement Jennifer, Based on the review of your May 1 letter by DOE HQ and NEn personnel, we'd like to have some additional Information and clarification on the following: 1. Please provide a clear description of the scope of the technology/components/Inventions to which Southern would like this waiver to apply. Reference to specific Invention disclosures should be provided, Including any disclosures that have not yet been submitted to DOE patent counsel. If there are any such unreported Inventions, please either submit them or describe them and provide a date by which you Intend to report them. 2. Describe Southern's plans to deploy/market the TRIG technology In the US. If Southern Intends to take active steps to deploy/market TRIG In the US, state that and describe the steps. Do you want the waiver to include US sales or only foreign sales? 2 SoCo FOIA Response 001840 3. Describe any role that KBR has regarding this request. Do they object to the grant of this request? Thanks I Usa 3 SoCo FOIA Response 001841 Department of Energy Office of Science Chicago Office 9800 South Cass Avenue Argonne, Illinois 60439 May27, 2009 Ms. Jennifer M. Buettner Southern Company Services, Inc. 600 North Eighteenth Street Bin 7N-8374 Birmingham, AL 35203 Dear Ms. Buettner: SUBJECT: DISCLOSURE ENTITLED: "CONTINUOUS FINE ASH DEPRESSURIZATION SYTEM" UNDER CONTRACT NO. DE-FC21-90MC25140 In regards to the letter sent to you on May 20, 2009 acknowledging receipt of the aboveidentified invention disclosure, we Inadvertently advised you of an incorrect DOE case number for the disclosure. Please disregard this previously stated DOE case number. The correct DOE Caso Number assigned to this disclosure is S-119, 091. Please refer to the above number In all future correspondence. Please contact me at (630) 252-2171 it you have any questions or if I may be of any further assistance. Sincerely, Mark P. Dvorscak Deputy Chief Counsel Intellectual Property Law Division Printed on Recycled Paper SoCo FOIA Response 001842 Department of Energy Of1ice of Science Chicago Office 9800 South Cass Avenue Argonne, Illinois 60439 May 27,2009 Ms. Jennifer M. Buettner Southern Company Services, Inc. 600 North Eighteenth Street Bin 7N-8374 Birmingham, AL 35203 Dear Ms. Buettner: SUBJECT: DISCLOSURE ENTITLED: "CONTINUOUS COARSE ASH DEPRESSURIZATION SYTEM" UNDER CONTRACT NO. DE·FC21-90MC25140 In regards to the letter sent to you on May 20, 2009 acknowledging receipt of the aboveidentified Invention disclosure, we inadvertently advised you of an incorrect DOE case number for the disclosure. Please disregard this previously stated DOE case number. The correct DOE Case Number assigned to this disclosure Is S-119, 092. Please refer to the above number in all future correspondence. Please contact me at (630) 252.:2171 If you have any questions or If I may be of any further assistance. Sincerely, ii Mark P. Dvorscak Deputy Chief Counsel Intellectual Property Law Division Printed on Recycled Paper SoCo FOIA Response 001843 A SOUTHERN COMPANY Jennifer M. Duellncl' Managing Auorney SCS Legal Soullnllu Cumpuuy SI!I'Vil:t:~, Inc. 600 Nordt Eighteenth Street Bin 7N-8374 Birmingham, Alabama 35203 U.S.A. Tel205.257.6730 Fax 205,257.6381 jcnmorri @southcrnco.com April 10,2009 Patent Counsel Intellectual Property Law Division U.S. Department of Energy Chicago Operations Office 9800 South Coss Avenue Argonne, Illinois 60439 Re: Proprietary and Confidential Notification of Two (2) Subject Inventions under Cooperative Agreement Number DE~FC21-90MC25140 Dear Patent Counsel: Section 3.8(c)(i) of Cooperative Agreement Number DE-FC21-90MC25140 between Southern Company Services, Inc. {"SCS") and the U.S. Department of Energy for the Power Systems Development Facility {"PSDF') ("Cooperative Agreement'') requires that SCS notify Patent Counsel of any subject inventions developed in the performance of the Cooperative Agreement. It is the inrent of this letter to provide the information requested by the Cooperative Agreement. To this end, enclosed with this letter is a wriuen report that provides a summary of two (2) subject inventions and identifies the inventors. In addilion to the foregoing disclosure, pursuant to Section 3.8(c)(ii) of the Cooperative Agreement, SCS hereby notifies Patent Counsel of its election to retain title to the subject inventions described herein (and any permutations thereof} in the United States and in all foreign countries in which patent protection may be filed and/or claimed. We intend for the enclosed report and the notifications provided in this letter to fully comply with the requirements of the Cooperative Agreement. To the extent udditionul information is needed, please contact me and I will expedite the process of addressing any such needs. SoCo FOIA Response 001844 April I0, 2009 Page 2 of5 In closing, SCS respectfully requests that you treat the information in this letter and the enclosed report as proprietary and confidential to SCS. Very truly yours, oe-n~L -1_.5~ le~nifer ~..Buettner Auorney for Southern Company Services, Inc. Enclosure cc: Mr. Morgan Mossel' (Mail Stop: P03D) Ms. Lisa Baker (Mail Stop: P04C) U.S. Department of Energy National Energy Technology Laboratory 36 10 Collins Ferry Road P.O. Box 880 Morgantown, West Virginia 26507 Mr. Tom Russia! 626 Cochrans Mill Road Mail Stop: 922-M214 P.O. Box 10940 Pittsb\Jrgh, Pennsylvania 15236-0940 Kerry W. Bowers, Director PSDF Randall E. Rush, General Manager, Gasification Technology Heather Benson, Govemment Contract Compliance SoCo FOIA Response 001845 Proprietary and Confidential to Southern Company Services, Inc. Subject Invention Report lo DOE Patent Counsel April tO, 2009 Title of Subject Invention Continuous Fine Ash Depressurization System Contributors Guohai Liu; Wan Wang Peng; P. Vimalchand Description of Subject Invention This invention relates generally to discharge ofpaniculate matters from fluidized bed combustion or gasification systems and pru1icularly to the cooling and depressurization of fine particles from high pressure and high temperature gas streams from fluidized bed combustion or gasification systems. The invention relates to a depressurization system in fluid communication with a high pressure, high temperature gas stream having entrained fine solid particles therein, such as for example, a fly ash stream from a gasification system. In one aspect, the system comprises an apparatus for cooling the high pressure, high temperature gas stream and a pressure letdown device (i.e., a separator) for depressurizing the cooled fine solid particles. In one aspect, the pressure letdown device has a housing defining un interior separator cavity and having a housing wall and a filter within the interior separator cavity. In another aspect, the filter can have an inner wall and a spaced outer wall, the outer wall being spaced therefrom the housing wall and defining an enclosed annulus between the filter and the housing wall. In this aspect, the inner wall defines a conduit in fluid communication with the high pressure, lower temperature gas stream. The filter can be configured to allow at least a portion of the cooled fine particles to pass through the conduit and exit via a solids outlet positioned adjacent a distal end of the conduit, while at least a portion of the entrained high pressure gas stream can be directed to a gas outlet, which results in a lower pressure outlet for the cooled fine particles. (b) (4) (b) (4) SoCo FOIA Response 001846 Proprietary ami Confidential to Southern Company Services, Inc. (b) (4) Title of Subject Invention Continuous Coarse Ash Depressurization System Contributors Guohai Liu; Wan Wang Peng; P. Vimalchnnd Description of Subject Invention This invention relates generally to discharge from fluidized bed combustion or gasification systems. Specifically, the invention relates to the cooling nnd depressurization of conrse solid particles from high pressure and high temperature fluidized bed combustion or gasification systems. The invention relates to a depressurization system in fluid communication with a high pressure, high temperature dense phase solids stream with entrained gas, such as for example, a coarser ash stream from a fluidized bed gasification system. In one aspect, the system comprises an apparatus for cooling the high pressure, high temperature solids and a pressure letdown device (separator) for separating the cooled coarse solid pa11icles from a portion of the entrained gas stream in order to reduce the stream pressure to desired exit discharge pressure. An integral part of the depressurization system for coarser solids is a hot·izontnl or vertical column of moving packed bed column of solids stream in which the gas is flowing faster than the solids to induce necessary pressure reduction. Together with the friction of the particles and the wall, the packed bed flow in the horizontal or vertical pipe can substantially reduce the amount of gas separated from the solids in the pressure letdown device (separator). The horizontal or vertical pipe can also be configured as a double pipe heat exchanger to provide a part or all of cooling that is necessary depending on flowrate and temperature of solids stream. In one aspect, the pressure letdown device (separator) has a housing defining an interior separator cavity and having a housing wall and n filler within the interior SoCo FOIA Response 001847 Proprietat·y and Confidential to Southern Company Services, Inc. separator cavity. In another aspect, the filter has an inner wall and a spaced outer wall, the outer wall being spaced therefrom the housing wall and defining an enclosed annulus between the filter and the housing wall. In this aspect, the inner wall defines a filter conduit in nuid communicAtion with the high pressure,lower temperature gas stream. The filter is configured to allow at least a portion of the cooled coarse solid particles to pass therethrough the filter conduit and exit via a solids outlet positioned adjacent a distal end of the filter conduit, while at least a portion of the high pressure gas stream is directed to the gas outlet, which results in a lower pressure outlet for the cooled coarse solid particles. In this invention, there are no moving parts or valves in the solids path. The only valve in the system is a pressure regulating valve on the clean vent gas stream. This fact alone improves the reliability of the depressurization system significantly.(b) (4) (b) (4) SoCo FOIA Response 001848 I~~Ill ~ 111~11111111111!11111111!11 ~Ill ~11111~1111111111!1!~~ Ill! H! 1111 IIIII US 20080216655A I c1~> United States c121 Patent Application Publication Vimalchand et al. {54) METIIOI) ,\ND AI'I',\IL\TUS JI(}Jl TilE SEP,\UA'fiON OF A GAS.SOLmS MIXTUitF. IN,\ ClRCUI.ATING l;LUIOIZED UEI> IU:,\CTOR lm·cntors: l'unnnlnl Vltnnlclumd, ninninglmm, AL (US); Gnulml Llu, ninninghnm, AL (US); Won Wang l'cnt:. flirminghmn, AL (US) C~s110ndencc Addn:ss: Dnlla~rd S1mhr ,\ndre\V5 & lngcnoll, LLI' SUJTF. 1606, !l!l!l l'E,\CiiTitF.E S'f'JU:rn ATLANTA, G.\ ~030!l-3915 (US) (21) AIIJll. No.: 11/684,405 (22) Fikd: M11r. !l, 2007 Pub. No.: US 2008/0216655 Al Pub. Date: Sep. 11, 2008 l'uhllcallon <:lu~~IQ~ntlon (51) Im.CI. (52) (76) (JO) (431 now 45112 (2006.01) u.s. C:l............................................ 95/271; 4221144 (57) ABS'I'llt\CT The system of the rresent invcntilication Publication Set>· II, 2008 Sheet 4 of 14 US 2008/0216655 A 1 400 470 440 . ;! FIG. 4 SoCo FOIA Response 001853 Potent Application Publication US 2008/0216655 At SCJl. 11, 2008 Sheet 5 of 14 ! 600 420 200 490 430 ~300 470 440 FIG. 5 SoCo FOIA Response 001854 Potent Application Publication Scp. llt 2008 Sheet 6 or 14 US 2008/021 6655 A 1 400 ! 600 --.._ 430 300 200 490 460 \._ 440 FIG. 6 SoCo FOIA Response 001855 Patent Application Pnblicntion Scp. 1 I, 2008 Sheet 7 of 14 US 2008/0216655 A I l Air - "' FIG. 7 SoCo FOIA Response 001856 Patent Application Publication Scp. 11, 2008 Sheet 8 of 14 US 2008/0216655 AI FIG. 8 SoCo FOIA Response 001857 Patent Application Publication US 2008/0216655 AI Scp. ll, 2008 Sheet 9 of 14 tOO ~., 90 I eo 01 c::: 0 Ul Ill a. ~ 6 70 60 -I 7 ,. 50 40 1 30 20 10 0 L.. "" 10 tOOO 100 particle size (microns) FIG. 9 100 p go 80 70 60 Cl c::: ·'1 R - 1... 50 ·~ 40 a. 30 ~ 20 II' ~ L/ :- 10 - L,_.....- 1---- 0 0 10 100 1000 particle size (microns) FIG. 10 SoCo FOIA Response 001858 Scp. 11, 2008 Sheet 10 or I 4 Palcnl Applicalion Publication 100 US 2008/0216655 A 1 j.:--" lrJ a:J m D1 IJ f) c ·u; ....ns !iJ ..,: 40 I 0... :tl J "" ID 1--' 0.1 - v IOD 10 1IXXI p11rtlele sl:re (microns) FIG. 11 liD ... 00 .I QO IT 70 D) c ·u; Ul nl c. ., s ~ j_ m vJ rill co - :!0 :Ill 10 ~ .... v-"" 0 0 .100 1.000 IO.OW 100.Ql0 1000000 particle size (microns) FIG. 12 SoCo FOIA Response 001859 Patent AJlplication Publication Scp. 11, 2008 Sheet 11 of 14 US 2008/0216655 A1 . l---'~ 1 ! I -· v v ./v /~ 1/ 0 10 ~ ~ v ·' - - · f- ! t 20 -·- f 30 40 50 60 70 80 90 100 110 120 Solids to gas mass ratio (lb/lb) FIG. 13 ~ entrance wloclty =60 fils -&-entrance wlocity =90 ltls -a-entrance w!ocily 37 ftls = 30 :2 -~ 25 c: .Q 20 iV "5 15 e :I u ..' ;;; u IV 10 (/) "0 '6 (/) 5 0 0:00 0:28 0:57 1:26 1:55 2:24 lime (hour) FI'G. 14 SoCo FOIA Response 001860 llatent Application Publication SeJJ. 11,2008 Sheet 12 of 14 95 - - - 1--+--+--+---+---1---+- :_~~~ 90 ;;; 85 ·1- i 75 5 __..-- .....,. -1-~.--:.-+-- - f - - - -·. ... · -f-·- 7 - ·r?'-·· 70 ~ --f-~ 1 .- b ·u so -1----l- k ~ US 2008/0216655 Al _,~ ~ • ·- ; -1-~---1 -·--1---1 -·-~- ·- ·-f--- f---~-- . ·f---1--· ··f---- . .. 65 - / -+--1--+--·-- f---f60~,,-r--1·---r-~-r--4---+--,_--+---~-+--~ 55 ..-+--- --~- 1---4-- 1--+-- -+--+- .5 ~ 50+---~-4--~-4--~---4--+-4---+---1--+----1 0 15 45 30 60 75 90 105 120 135 150 165 180 solids loading (lb solldsllb gas) FIG. 15 --FWIOiarOlG Slca hjecl Rl70l -+-- TCoOaAO fm10 - - TC-06 F0520 100 Ij . . 80 'i ";/: -so Q c: l ·:40 I'll .i - 0.. 20 -. .. - -1- - ... 0 0 , ao G:t~ . .. --....... - -··:l....;:~--'[JE !~ ·' ·~ rb I~v .¥ n 10 100 1000 Size (microns) FIG. 16 SoCo FOIA Response 001861 Patent Application Publication .. --char Injection with DDP - ~ 40 30 20 t.-o -· I I. . ~./ ./ ; ·ID· ./ . .I.. ' tf' • I ' 1- --. b_ ~-~ r-- 1- - --- !"-- j ~ 1-. . . I? . .' 10 t--- celllto lnloctlon with COP -•- Silica ln)ocuon without OOP --Silica ln)cotlon \'YIIh DDP 100 90 80 "$. 70 1 60 2' 50 US 2008/0216655 AI Sep. 11, 2008 Sheet 13 of 14 ;,1 · ,, .. 1 - 1- -· ~I ··- ~ 100 10 1 0 .. ,,pt. ~ ·- --- ·- I 0 -- --·· , .! !- ~· ···· .. . Size (microns) FIG. 17 E 161 CYCI.ONE -2nd CYClONE 100.0 .i ~ I , !;'~ '7 I 90.0 J-- .. I 80.0 t 70.0 -. -- t.:l IJ 1 iI - I 60.0 10 Size (microns} - I w .. I I ! I 100 1000 '--·----------···--------------' FIG. 18 SoCo FOIA Response 001862 Patent Application Publication \ - tst CYCLONE -2nd CYCLONE 100.0 95.0 - 00.0 w = 80.0 '1ft >- ...,~ 65.0 ~ 75.0 g ~~ .~ - IT - ·r · - - ·-:- - ···· -j- ·-r 1-!I 60.0 - - ·· -··- -- ! - I _.. -- - --- - -r.. .. - I ; i 70.0 1-- 65.0 US 2008/0216655 A1 Scp. 11, 2008 Sheet 14 of 14 I ~ ~r· I I 10 1000 100 Slzo (microns) FIG. 19 -r~ ·CYCLONE -2nd CYCLONE I 100.0 '! 97.5 ...jj' ;It 95.0 I -· · c ) II 92.5 t--4= w I ·~ ..r1 ~ ~ 85.0 .. r I .. i I 87.5 1-- j - 90.0 f - - - ' - I I I II IIIII I . 11 1 -1-1- !I' I I 10 100 1000 Slzo (mlcrtllls) FIG. 20 SoCo FOIA Response 001863 US 2008/0216655 A I l\11!:'1'1101) t\ND AI'I',\IUTUS FOI~ 'I'll£ SF.PAUAT!ON OF A G,\S-SOLIDS i\UXl'URE IN t\ CIRCUL,\'fiNG FLUJI)JZ.ED BED IU:AC:TOR FIELD OF TilE INVF.NTION 100011 This itl\'~ution relntcs to the sep~mtion of gns nml solids mixtures thmuglt an assembly of pnniculnte collection de\•it-cs nml the method oforcrnting thedeviccs.Ju pnrticulnr, the in\'ention relates to n method and appnmtus for the sepn· mtion of gus-solids mixture in n circulating lluidi"L'll bed (C:Fil) reactor med ns n combustor, gasifier. fluid cnllllytic cmckcr (FCC), or gns-hi!!hl)' dispers~ solids contnctor. I!ACKGROUND 01' THE INVENTION (00021 A circulnting fluidized bed (CFO) 1\.'acturcnn time· lion ns u hl'll\')' oil cracker, combustor or I!R~ilicr to process cnrbonncwus materi~k For ull uf these nrplil,tlions, th., reactor typicnlly comprises ~imilnr comroncnts, rmmdy n riser, n pnnicul:ttecollections system, o stondpipcnnd n solids !low control \'ilh•c. In nddition, the I'C'ilctors used for these \'arions opplicntions also opcrnte inn similar mnnner, n.1mely by: pro\'iding lUI upwnrd flow of gas-solids mixture in the riser; collecting particles from the gus Dlld conveying the collected panicksto the standpipe; nnd gnt\'ilntionolly flowing thecollcctccl p.1r1ielcs in the slnndpipeand panicles llowing throttgh n l'al\'e located in the tx)uom of the stnndpipc to the bottom of the riser. (OOO:l) For mpicnl p;~niculnte collection systems comprise a combinntinn of nn upstream disengngc:r or !low impactor and a downstrunm tl!ntrifugnl ~-yclone. "lltis combi· nntionnllows lor tlu: r~tno\'al oflllrgcr pllr1icles nml n signilicnnt CL-duction in panicle loading before entering tl1e cyclone. J0005J Although the gravity separator used in tandem with a centrifugnl cyclone e<~ntuke nd\';llltageofthccbomctcristics of both de\'ic~'S. the intcgmlion faces serious chnllcngcs coo. For <.-xamplc, the Iorge fi10tprin1 and vessel si~e of the discm· gngcr ns well os the incrensL'll cost incurred nn: some of the chall~ngcs encomucrc:d when integrating these systems. J0006) More specifically, since n gm1•ity separnlor utilizes the nccclcmtion of gnwlty to nllow solid particles to settle Sep. II, 2008 nwny from ll g.1s slR.'nm, the drag cxencd on the panicles b)' g:ts Illlist be much less than that by the gntvity to separate the pnt1icles lium the @liS strunm. Rougltly speaking, the superficin! gas velocity in the gm,•ily scpnmtor should therefore be less lhnn I 1\Js to sepnmtc p.1rticlcs with diameters larger than I 00 microns. As n rc;;uh, the din meter of nn eOicient r the snme reactor capability and to mnkc the opcrntion of the cyclone nsscmbly n:linble for C:Ffl ns n gnsifier or n con1bustor. {00121 In ouc aspect, a dcsnllalion device for scpnmling particulate mat~rinllrom n p;~niculnh: lndcngns solids strt!mn in n system ol'lhe pn."Scnt inwntion comprises n centripetal cyclun.:. ,\c~"Ordinp, Ill this uspect, the cenlrip~t:~J cychme Clllllllrisei n housing defining n conduit extending between an upstream inlet nnd n clownstrenm outlet. In ;m exemplary aspect, the cross-sectional ar~n of the downstn::un oullct has n lnll!cr cnlss-sectimml 11re:1 than the upstream inlet. In another aspect, II lens! n portion of o conduit botlom surlhce tnpcrs downwardly nnd nwuy from the conduit lop surfncc.ln operutiun, wltenn p:lrticulnte Ioden gns·sulids stream [liiS~es thn.1ugh I he ups~nm housing inlet, the porticulntc Jnden gas· solids slrc:un is directed through the conduit nnd nt least n portion ofthe solids intbc particulah! Ioden gns-solids stream nrc subjected to n centripctnl forc:e within tho conduit. 100131 Rclntcd 111ethods of 011ernlion ore also pro\•ided. Otltcrsysl~ms, methods, features, nnd advantages of the particulate collectillll system for use in CfB n.':lctors will be \lr bc.:nme O)lpurentto one with skill in the art upon exnmirnnion of the f\11lowing figures nnd detailed description. It is intcndl!lltlttt nil such ntlditiunnl ~)'llleniS, melhtxb, fealllr~"S, nnd ndvantnges be included within this d~'icription, be within the scope of the partlculntc collection system for use in CFB re.1ctors, nnd be prutc.:tc:d by the accompanying clnims. llRIEF [)J!SCRJlYI'ION OF TilE DRAWINGS {00!41 TI11: accomp:myins dmwin~~S, which nrc incurp11· rntro in nml constitute n part of litis ~pccificntion, illnslrntc certain aspects of the instnnt illl'enlilm and together with the description, serve 10 explnin, without limilnlion, the prin· ciplesofthc invention. Like rcfcrencechnmclers used therein indicate like parts lltroughmll the severn[ drawings. 100151 l'IG. I is n schenmtic illustrnlionnfnn embodiment of a desnh:uion device of the present hwention, showing nn elongated inclined cross over and nn elongnted desnltntion \'esscl. 100161 FICi. 2 is n pCI'li('CCtivc schcmntic illustmtion of an cxcm11lary inclined cn1ss over, showing n cross over housing lmvin& nn upstream r~'Ceiving inlet, nnuppnsed spaced upart downstream outlet, nnd n continuous side wull extending there between, fom1ing nn inclined cross over cnnduit. {00171 FICi. 3 n schematic illustration of rut exemplary dcsnltution vessel of the present invention. {001111 FIG. 4 n schcnmtic illustmlion ofnn cKen1plnry cir· culating fluidi7.ed bed renclor oflhc present invention, showing n pnrticulnte collection system. 10019) FIG. 5 is a ~chemotic illustration of on exemplary circulating fluidized bed renclor uf the pn:seut inwntion. ~howing n particulate collection S)'Sicm with n sen) lo:g t\1 retnm the collected solids to the standpipe. {0020] FIG. 6 is n schcmnlic illustrnlion of nn L'Xt:mplmy circ:nlating fluidized bat reactor of the pn:sent inwnlion, sl1owing n pnrticulntc collection system witlt on L.Vnlvc nnd indinctl k-g Ill rctum the roll~-ctcd sulids to the st;mdpi]>e. J0021J FIG. 7 is o schcnmtic illustration ol'n COIWCntinnnl circ:ulnting lluidi:tcd hed cold llow n!lldcl (00l2J FIG. 8 is n schematic illusuntion ufnn exemplary eirculuting lluidizad bed ~uld flow model according to one nspcct ofthe present invention. (00231 Flu. 9 is n gmph illustmlion of n p.1rticle si7.c dis· trihution for 1111 L'Xcmplnry cin:nlntinl! bo:d mnteriul utiliz.:tl in the nppcnded Exnmplcs. (00241 FIG. 10 is n graph illustration of n particle si7.c distribution fornu exemplary circulating bed material utilizo:d in thcappcmled Examples. (00251 fiG. U is u gr.1ph illnstrntilln of a pnrticlc size distribution forun t!Xemplary circulating bed mnlcrialutilized in the nppcmlcd Hxnlll]lles. {Otll6J fiG. 12 is a graph illnstrntion of n IIDrticlc ~ize distribution for an L'Xcmplarycirculating b~d mnterinlntilized in the nrpcndcd Examples. JOU27J PIG. 13 is n graph illustrntion of excu1plary gas vclocitie3 nnd solids loadings nccording to oue aspect of the present inventiou. J0028J FIG. 14 is graph illustration uf exemplnry solids accumulation rules accordiltg to one aspect of tho present invention. f0029J FIG. J5 is a grnpb illustrntion of the eorrclntion bctwc:cn saltation velocity and solids landing according In one us peel of the present invention. JOO~OJ FIG. 16 is n gr;tph illustmlinn of particle siT.e distributions for exemplnry mnterinls collected by n second stage ~yc:lom: uccording In unc nspL-cl uf the present i11v~ntion. JOO:liJ FIG. J7 is u graph illuslrntion of tlu: mass 1111:1111 pnrticle si7.e tor el\cmplury particles cmined b)•n second stoge cyclone ntcording to one asp~'CI of the pn.'Sent invention. J00321 fiG. 18 is u grnph illustmtion uf t:Kempl:try grdtlt: efficiencies lor char injection tests nccording to the preso:nt invcnli~m. (00331 FIG. 19 i~ u gruph i!lustmtion of exemplary ~v.ulc o:fficicncics fnrclmrsilicn llnurinjec:tinn lc:il$ neroroing tot he present invention. 10034) FIG. 20 is a graph illustration of cxempl~ry gmde eflicicncics lnr cellitc injc.:tion l~sts accordinG hi the present invention. DE'Ii\Jf.I!D DESCRIPTION OF THF. INVENTION 100351 The present invention cnn be under.nood more readily by reference tu the following detailed dcJ:Cription, ex:unplcs, dmwings, nnd clnims, and their previous nnd following description. However, bcf~1re tlte present devices, systems, and/or mo:tbods nrc disclosed and do:scribed, it is to be under.>tood thnt this invemiou is not limited lo thu specific devices, systems, nudlor methods disclosed unless otherwise s~'Cilicd, os such can, of course, vary. It is nlso 111 be under· SoCo FOIA Response 001865 US 2008/0216655 A I Sep. I I, 2008 3 stood tlmtthe tcnninology used l11:rein is for the purpose of particular nspects only und is not intended to be limitiug. (OO:llij ·nu: following tle~eriplion of the im•cntion i~ pnlvidcd ns an enabling teaching of the invention in its best, currently Jmowncmhooiment. To this end, those skilled in the relevont nrt will recogni:ro ond appreciate that mnny chnnges can be made to the v;~riuu~ aspects ofthe invo:nlion d•~ccibl!tl herein os from "nbout" one pnniculnr value, rutc.l/or to "nboul" another pnniculnr vnluc. When such o rnuge is C~J•ressed, nnother nsp.'Ct includes from the ut~~: particulur v:•lue nmlA~r to the otm:r purticulur value. Simil:lrly, when vnlues nn: cKpn:ssed ns nppmximotions, b)' usc of tllll nntccedent "about," it will be understood that the particulnrvnluc forms nnothernspccl. It will be furtherunderSiood thnttl..: endpoints of e;t(;h of the mnges on: signilicnnt both in n:lntion to the other endpoint, nnd independently of the uther endpoint. )0039) 1\s usl'tl herein, the ttlnns "optional" or"optionnlly" mcon that the subsequently described event or circnmstnnce may nr mny nut occur, ontl thnt the description includes inst:mces when: said event or eircumstuncc tx:curs nnd instnnccs when: it docs not. 100401 Referring now to the figures, in which like refercnce char.Jeter.;; imlic:~te like J•ans tluoughoutthe sc\·crul views, u nrst nspcct ofthe present invention i~ gcncrnlly shown in FIG. 1. As shmvn, the rresent invention provides 11 dcsnltation device I 00, comprised gcncr.•lly of nn clongnlcd inclined cross over 200 and nn elon~nted desnltntion vessel :100. The inclined cross over is ~umprised of n cross over housing 202 hnving on upst~~:nm receiving inlet 204, nn opposed spnccd !1pal1 du\VII$lrcnm utlllo:t 206, and n continuous ¥ide wnll extending then: IM:twecn, which forms nn inclined cross over conduit 20R. The cross O\'er housing can be constncct~-d in known fashion nod fmml.:nown mntcrinls suitnble fornccontmodnling the pnssage of n hot pressuril~'ll fluid, such ns n particulnlc Ioden g;ts process slrram. (00411 ·nte des.1hntion v~scl :100 is fanned nbont n substantinlly verticnllunsincdinnl oxis 1111d is also constmcted in kol>Wn f.1shion nud frum known nmterinls suitable foroccommodnting the pnssagc of n hot pn:ssurilcd ftuid, such ns n particulotlc lndL"'I WI¥ proccn liln:mn. ·ntc \'L"SSCI hus 11 top portion :102, nn OSc of one or more pnl1iculnte rnatcrinls entrnincd within n pnrticulntc lildc:n gns·solid stream tlrnt is to be din:cted through the inclim:d cross O\'er 200. 100491 The inclin~ conduit top snrfnce portion210 can in one R$pecl be nl lcnsl substnnlinlly plnnnr. for cxomple, nn exempl:tf)' plnnar conduit tup surfnc~ portion ~~~~~ ~~~lend, fnnn upstream Ill downstream, inn plane substnntially pnrnl· lei to the horizon\111 nxis. Alternatively, n plnnar conduit top surfnce portioncnn extend, frornupstrenru to downstream, in 11 plunc snb&lnllliully pnrnllellu n plnnnr bottom surfnee por· lion. In :mothcnspect,ntlcast n portion ofn pl:mnr top surfnce ponion 210 e:rn extend in n plnne, front upstrc.1m to down· stremn, up1Yanl and away from the horizontnl axis. In still ~nother nspect, Ute top surfncc portion 210 Cllll be non·plruw. For eltlllttple. as sltown in fiG. l, an exemplary non-plnnar conduit top surface po11inn cnn be nn:uale in shupe such tl~11 at least n por1ion of the tott surfnee extends, fn1m upstrcnm to downslr~rrr, :trcuntcly upwnrd and nwny from o horizontnl axis. (0050] ll1c inclined cross o\•cr of lhe prcs~nl invention enables a nowl method for '~'Pilrdlin~ pnrticulul~ mah:riul fnnn n par1ieulntc laden gns·solids strcnm In one aspect, the pnrticulote lndcu gus-solid strcnm mixture cnn, for cxnmple, hnvc 1111 opemtiug temperature intire mngc of fmrn opproxi· malcly 1000" r. to 2000° f. lu &till n further nspecl, the pnrticulnle lndcn gas-solid strenrn mixture cnn comprise a solids to gnsloading mtill in tltc rnngc of from I 0 to 60 pounds oft•aniculnh: nmtcri.1l per pound of gns. Furthcnnore, cxent· plaf)' pnniculate laden gas-solids mixture cnn nlso exhibit n llow \'eiocity in tlu:rrutgeoffmm, forc.~nmple, 25-75 1-.-clper second. !0051) In use, n SllpJllied pnr1iculatc lnden gns·solids mixture CIUI be n:cei\·eJ by the upsln:run cross owr irdc:t 204 of the desnllnlion device. Once rccci\'ed by the upstrenm inlet, tilt! pnrticuhrtt: hulen gsnl~,tion \'essel 300 according to one nspccl of the present im'Cntion is shown. 111c dcsnhntion vessel 300 i' lonned nbout n subslun· tially vcl1ical luugitudinnl nxis nnd is nlso eonslnrcted in known fashion nnd fn1rn known mnterinls suitable for nccomntodating the pn~suge of o hut pressurizw nuid, such 1rs n plll1icttlnte Ioden gas process stream. llrc vessel hns n lop po11ion 302,1111 opposed spnced npnr1 bonorn ponion :104, nnd a continuous side wall306 cxtc:nding there hc:twccrr, fnm1irrg n desnhntion chamber 308 withirt the rlesalmtion \'<'Ssel. A process strearu receiving por1l 10 is defined within the vess.:l sid~wallnnd is in cmnrnunicntion with the inelined cross over C\lrtduit 208 a11d the dcsaltutian cltmnbcr 30R. 1\ Mlucr:d pnniculate lndcn proccn sln:am dischnl\lc p•m 312 i~ formed within the llljt portion of the desnltntion vessel nnd is com· munication with the dcsallation chrunber :108. Tite n:duced particulate J~ded process stream dischn~c rort :112 can be us•'tl lOr dischn~ing n n:ducal pnrticulate L1dcn process slr1.'3m froru the desnllnlion vessel lbr further downstream processing. A Rrst solid strenm disclro~e pol1 :114 is formed within the bottom portion oftltedes.1ltntion vessel and is nlso communication with lire desnllrrlion chrunbr:r 308. TIIC lint solid strcnnt discharge port 314 cnn be used for discltn~ing o solid st=m from lht: desnhntion vessel for further downstrc:mt processing. (00541 Thedc$0lltllliocr vessel sidewall is tirrthcrcomJICised ofnn intesmlly fonned n:cei\•lng surfucc po11ion 320 nnd nn opposed impact surfnce rortion 322. AI. illuslrnt.-d, the pro· cess stream receiving inlet 310 is defined in u ponion oftltc receiving surfnce po11ion JlO and is inlcgrnll)' formed with the downstream outlet 2116. 100551 Tite dcsnllntion vessel cmt be consrnrcted and nmmg~>d to provide a desnltntionchnntbcrhavinganydcsired size nnd shnpc. Howc:ver, in one aspc:ct, the desollnliott cham· bcr is substnntinlly c)•lindricnl. SoCo FOIA Response 001867 US 2008/0216655 A I Sep. II , 2008 5 [0056[ 'l11e downstrcmn outlet of the iuclinL'Cl conduit can be et.lnstructed nud nrmnged such that n process strcnm exit· ing the downstrcnm outlet, i.e., n reduced particulate lnden gas str~rn nJ1dlor n solid ~tll!nm, will enter the dcsnltation cnndnittnngcnlinlly. The tnngcntinl introduction ofn pnrliC\1• lute lnden fluid str.:am into n cylindrical dcsnltntion conduit can fi1rthcr enhance the rolk-ction nndlor separntion cffi· cicncy of the desolation de\•ice by subjecting cntmined pnr· ticles in thegns phose ofn pmccs~ str.:mn to centrifugal forces resulting from the rotationnl fluid motion of the process str~'ilm nruund tlec contour of the dL-suhntionehnmber. [0057) The dcs.1ltntion \'cssel300 lin1hcr comrrises n top wsscl portion 302 nnd n bouom wssel portiou304. TI1c top portion 302 comprises u substnntinlly wrticul longihtdim•l flow nxis 302(n) and cnn further be configured to rcc:ch·c a fi111t r.:duced pnrticle laden gns·solids stll!mn from the down· str~m outlet 206 of the iuclined conduit208. In use, the top purtion302 COil 1\.'\:0:iW ond din:cl;e rOO need p;llticulatc lmJcn gns·solids strcom lilrtltcr downstr.:mn for subsn1ucnt pro· ccssing, including for example, introducing n reduced pnr· ticulntc Ioden gas $lremn to n second stage cyclone wherein the reduced particulnte laden gus.solids stream crut be sera· rntcd imo n ~l-c:ond solid stream nnd n 5ubstnntinlly pnrticlc free process g:t~. In one uspo:ct, the top portion 302 furthcr comprises n n.'Cluccd particulntc lndcn process strcmn dis· chn~c purt 312 tlmt is lorml'Cl within the top portiun of the desnltntinn \'cssel nnd i5 in communication with the desnltn· tion clmmber 308. J0058J The bollom pnrtion304 ofthcdcs.,ltntionvesscl can also be cunllgurcd to ri.'Cei\'C u first solid stream frum the down~tream outlct206 of the inclitted ems5 nvcr conduit 208. ·n.us, in usc, the bonont conduit portion 304 cnn provide n solid stremndrnin pipe forcollectingand subsequently direct· ing the llrst solid strcmn downstream for addition.1lprocess· ing, including for exmnttle, introducing the solid strcnm to 11 stnndJ'iJ1c and/or n.-c:irculnting the solid strC] A portion or the imp:K:l surfncc 322 of the vessel side wnll e:nn optionntly fom1 nn bnt•nct recess 340 relntivc to the longilmlimelllownxisofthcdesaltation vessel top portion. At lenst n portion of the recessed impact surlitce can be positioned ubove nl lenS! n portion of the ptuce$5 stream receh•ing l'ort 310 nnd inn plnnu that iutcr.ll'CI~ the lougilll· dinal flow axis ofth~ desalt.1tion vessel top portion. "lo that end, lhe optionnl intpuct recess cnn be configured in any d~siroo shnpc, however, itt one nspcct nnd ns exemplified in Flample, nnd without limitation, he incnrpomted into a cir· culaling 1\uidize.'Cl bed reactor cunfignred fur use as n comhus· tor, gasifier, tluitl cntnlytic cracker (fCC), or gas·highly dis· pen;ed solids contnctur. [00611 Referring now to FIG. 4, nn exemplary circulntinl! fluidized bed n:actor 400 L'Omprising a particulate collection system according to the present iiJVention is shown. As shown, the circulating lluidized bold reactor comprises n de>altnlicn de\•ice 100 ns described niKwe, compri~cd of nn inclined cross over 21l0 and n des:Jitation vessel 300. A cyclone 410, having n pn1cess slrCct be nconventionnl ccntrifugnl cyclone. Altemntivcly, I he second cyclone cnn he n second desnltatiou d<.-vicc os described in accordance with lh..: pte$11111 invention. As cxcml•lillet!, the cyclone 410 is u coneless stnndpipe hnving n top110r1ion 430 and n bottom portioo 440. 'n1e reduced pnrticulntc l;1den gns·solid stre01m dischnl)!,e outlet 312 is connected to the receiving inlet nfthc cyclone by, far example, a com•entilmnl cross over pipe 460. In one aspect, the cross over pipe 460 c;~n nlso be an inclined cross owr. J00631 In use, the strcnnt enters the cyclone tnngentially 111, for example, o vclotity in the mngo: of lium 40·100 IVs depending on such vnrinblei as the percentngc solids landing, llllrlicle size intheg:1s strc:nn, und thedianu•teroftht:t:ydonc barr.:]. TI1c tangential introduction will result in 111c pnrticlc lndenj!.IIS str.:~m spinning ~long the inner cyclone wall. 'lltis spinning or nthllion nfthe gns slren•n \\'ill npemte to remove solids particles from thegns str.:nm. Titc g11s stream ho\•inj! solids purticles removed thcrdrom to provide n reduced sol· ids loading gns stream will exit the lop ofthe cyclone. In one aspect, a vortex finder (not sbown) con be instnllcd nt the cyclone exit. 'll1c solids pnrticlcs removed from the stream will How dll\\'nwnrd nlonp, 1hc SIIUldpipe nnd cnn then be rccyciL'd to Ihe riser. The solids particles collected cnn also be metBed with the solids from the desalltltion vessel. {00641 In still rutothcr aspect, thu standpiJle cyclone cffi· ciency can be enlmnccd by the globe downwmd flow gns in the stnndpipc. AccordingI)', il will be npprccintLod uponpmc· tieing the present invention that the cyclone ellldcncy cnn be optirni7.cd by ntljusting o\'Crnll solids circulation rntc within the circulating fluidized tx.'Cl loop. [00651 "lh: bottom portion 304 oftltcdesnltntion vessel, ns dLoscriho:d nbove, is conligured lo recei\•c o first solid stream from the downstream outlet 206 of the inclined cross over. 'lltus, in opcmtiun, the bottom conduit portion304 functions ns n solid slrcnm drnin pipe for collecting nndlordirccting the first solid stn:~m downstn:mn for additional prucessing, which cnn include, for exnn1ple nnd not n1C surfncc portion of lhc cenlris~etnl cyclone conduit. To this end, by 5ubjccting 1hc rurticulnlc mnlerinl within II gn~-so1ids procc>s slrenm to n ccnuipclnl forL-c thut spins porticulnte mnlcriill ;1way from the lop Sltrfnce ponion, n rc!ntively high paniculnle SeJ1o1r.tlinn nnd colh:clion efficiency can bl! achieved while also mininti7.ing the erosive clli:cls of ll~e pnni<:ulnte mnlerinl will1in Ihe proccs9 slrenm. [0072) ·n~e reduced rnniculntc Ioden 1!115 phnsc will c:on· tinue to !low nlong or nenr the upper wall portion or the cenlripclal cydone and lnugelllinlly enter lhedcs.1llnlioncondnit. In one nsrcct, a n:duccd paniculntc Ioden gns·solids strenm c:m comprise cnlrnined solids having ft plll1iclc sizll tlinmeler in the range of 0 to 100 microus. t\ddilionally, in ;molhcr uspecl, lhe me;~n runlcle $i:tc uflhe solitls cnlmined within Ihe: reduced parliculale laden gn9 solid slrc:un cnn, for example, be in I0 to 30 micron rauge nnd panicle deiiSities mnging from 110 lo 160 lb/cu fl. I007JJ Aflerenteringlho:desnllltlion cunduit, nt lcasl;t pur· tion of the n:duc:cd pnniculate Ioden gas strcnm will optionally inlplnge upon Ihi! opliounl improct recess to further SCJlll· rnlc nnd coliL'CI pnrti<:les enlraincd in the reduced paniculnlc laden gus stream. "llte s~amled solids obt.-.incd by lhe impact upon tiiC impnct recess and from the solid slrcnm exiling lite ccntripclal cyclone will flow grnvilnlinnnll)· downward into the dr"din pipe pori inn ofthe desuh;diun \'l'sscl. The colk'Cted solids in the drnin pipe can then be lmnsponed by grovil)' to lhc standpipe lhmugh L·\'lllvc 490. 100741 The reduced pnniculnte lndcn go~ sucnm exiling the dL'Silltotion wssel vin eros~ owr pipe 470 1:111ers the st:utdpipe cyclone 400 to funhcr scpnrntc the reduced pnnicul:lle laden gnS-SOtitJ Slf<".llll intO U IUbStallliliJiy J1Ur1ie!t: fn:c JllllCCSS giiS nnd a s«ond dense solid stream. In one nsrc:cl, lhe suhstnntinlly p:~niculalc fr.'C process g.1s stream comnins enlminc:d solids having nn nvernge lllelm rnnide no ~nter tlmn 3Jlpn1,.;imntcly 10 microns. In still n funho:r nspccl, 1he snb· slaotiully paniculalt: frc:c proc~ss gas sln:am is substnntinlly absent nny enlraincd solids. SoCo FOIA Response 001869 US 2008/021665.5 A I Scp. II, 2008 7 10075] '11•~ roouccd pnrticulalc laden gns stn:am cnn in one us peel enter the standpipe cyclone 400 tilngcntinll)'. 'l11e tun· gcntinl inln•dnction of the n:duc~'d otherwise, r~•rt~ urc part~ by weight, tcmpemtun: is dcgrc.}s C oris nt nmbient tcmpemturc, nnd pn:ssurc is nt or near ntmosphcric. 10076] I. Cold Flow Unit and Tests (0077) As shown in fiG. 7, n conventio11.1l cin.-ulnting llnidi7.cd b<:d (CFB)cold flmv modclwns provided hnving nn 10 4" Riser, n3" crossover,mt8" coneless cyclone nlsu called lite finn-stage cyclone, n 12" standpipe, a second-stage C)'clone and n loop-seal nndthreebng lillcrs.AII pipes were nuulc from plnstic materinls fur e:1sy visutllizution. (00781 Aller initiul compilr.ltil•c control test nms, the CFB sy&lcm wns modi lied 111 climinntc ~nltnlion in the crossover fn11n the riser to the first·stnge cyclone. The modincd cold flow model is sc:ltemnticnlly shown in riO. 8. Spccifk;~ll)', the cold flow model of riG. 7 was modified to provide nn iuvcnti\·c pilrliculnte cnllection system ns described above, cont· prised of un inclined cn•ssowr, a lee nud o section ofverticnl pipe with one end going to the cyclone cntmnce oml theotllcr to the standpipe dwngh on L·valv~:. Tite function of the inclined cromwer w~stll prevent solid snltotion in the section so that solids can \lllilomlly llow to the Ice section. 'l11e purpose of the tee is lu withdntw those solid~ prct:ipitntiug from thegns strenmat the tL'C. In dtis wny, thegns slremn with lower solid c:oncL'Ittmtions will hove little or no solids saltn· lion in the ~ntmncc of the cyclone. 'Ill wider ond pnrticle si7.c smaller so thlll tiM: c:xo:mplnry cyclone eOicio:ncy me:tsurcmcctt could bt: £im· plilied. The PSD ofthL'Se& test malerinls nrc ~portL-.1 in riGS. I 0, 11, nnd 12. 10082) A series of tests were pcrform.-d under the srecific tesl conditions giVlln in Tnble L Tlte objectives fhr these test$ were lo evaluate the influence of I'Orlex Hndcr, entrnnce gns velocity, diiTen:nl mntcrinls injected nnd particle sizes on the pcrfomt.,ncc of the inventil'e high solid lom:ling cyclone sys· tem. In Tobie I column S, under thutitle "DcsaltOJtion" ctlll· tains three tc:mts: "NO", "ON", and "orr•·. 'll1e tcnn "NO" indicntcs that the DDI' wns not instnllcd during these colllnll tests. 'l11e desnllntion "ON" means that the DDP wns instnlled amltbnt ncrntiou Ia the drainpipe wns !lowing nnd saltation in the cyclone inlet W:l!l eliminuted. TI1e "Of\" dcsi~natcs lhut the DDP wns instollcd nnd thnt ncrntion \\";IS shut on; lhcdmin pip.: wns fully pnckcd with solids, nnd the cyclone inlet gen· ernlly l~1d solids saltnlion during these tests. TABLE I J"Cydoae tntcl Jnjf'l.1ioD ~btrriJ.l E.•:~~~•pl• • i:lllal I 2 Sand Mixnlt<' ) Mi~turc 4 S>ll Mi,lutC Ml~nLte \'ortcK l~!o.:ily DP!I.i1<1 Dr•stt.uion Filllltr tllfsl Ci:I·II,OI :-.'0 :-.'0 ) "/)'U 60 60 60 150 6().90 42·54 Amount ,\,Jitiw '""' Siti<• Flour 5ll Silic.J. Flour Silic.aflour 40 31.3 NO On On On On 3"/)'t. 3"/)'('1 2..:yca 2../)'C'I ·r1>'u 2"/)'tl 60 CiO 60 60 4] .50 ~0 SoCo FOIA Response 001870 US 2008/0216655 A I Sep. II, 2008 8 TADLE 1-continucd t••t')·don~: Jnjcclion MJtcri~l l:umplo # in lk\1 Addi1L\·c: l Mi.tor< 9 MiMUI't IO II ~tbr.tuJ\" MiMU~ Ccllil< 12 Mi>.nuc Ch.u ll 14 S:m~ I~ ~li:\1l1C\~ Mi"'Utt' I7 IG 19 20 ~ti~tll~ ~fi:\IIU\" Frcah S:Uld Mixtul\• n Mixtn~ 22 H 24 2S Mi>1Ur< 26 (lhs) C:ctslt.J.Iica Fi!Ukr On On 2 ..1)"<1 l"lyc1 J"/ycl l"/yrs l"'/ )..1 i"i)"tl ~.78 On l".O)'tl 10.68 10 llll" On l"lyu 2'1yn 6.6 011" 6.6 On On 16.06 IO.Il Mb.tuN 16 Jnler ,\mount On On On On 18.44 On s.ss O!T Clur 10.~1 orr l\00 Frnh 5.00 Celli< 6.74 On Mh.11u'-' l."0 NO z.;o 10.24 Oil" 4~ 45-60 z.;o 0\"0 1001131 Initially, the test nppnratus wns loaded mnnunlly with snnd. ,\ lines feeder wns then cxtemroorizcd from an existing 4" pipe to fwd the fines while the cold llow model wns running. The 1\,ooer was basoo un principle~ uflluidiled bed OJ1l!rutions. For n nonnalstnrt·Up, nerntion gns sltlrts fJCSt to fluidize the ~fo>lUI\' Mixhu-r f{) fiO fiO xo xo DP Risd toward the cyclone inlet inn J•UIS.11ing mnnncr, likely due to !he nmount ofsolids nccumulaling in the cn1ssovcrand due tn the chan~~: i11 the shear stress uf WJ5 plmsc on I he top lnycr ofthe accumulnted solids. TI1cse solids din:ctly nuublcd inlo tl1c cyclone nt th~ enlrnnce and would lmvc fnllcn downwartlulonglhe wall on lite cyclone inlet side but forohservcd intcrfo:rcncc with the I00 g strcnm. To this o:nd, lite I00 g·slro:um nftcr making OliO! round around the cyo:lone barrel interfen:d with the I gslream nnd prevcnl~o>dn portionofthosc solids from directly fhlling nlunr, the<.'ltlmnco: side wnii.As n result, the l g slrl-amtogcrho:r with n portion of I00 g siream fonm:d new stmnds flowing in l~elicnlanglcs ofabout 60-70". 1009J I Tite flow p.1ncrns of these two slrc:tms can be fun her dC$cnhcd ns fnllnws: when the 100 g slrcam makes n tum in lhe verm Clllllrnclu n!gion, in which tht: m:~ority of the purticlcs nrc 11ushcd toward the cyclone wnll and In he rollccled by the cyclone, nnd relttrllS to th~: inlet l'qlion rutd meets tl1e freih incoming I (I stream. Roth strcums chungc momentum. Tite I g slrenm incn:rues its momentum and 100 g srrcrun decrc~scs its monu:ntum. !-'or Ihe firs! tjUilrter of a tum, the majority of twn strenms actually flow together nboul S-6" nlong the mill befo~~: roughly HO-IJO% of solids dn1ps out of the gas strenmund the two streams ngain become distinct. 100921 Because nf ituerfcrencc bctw~n the 100 g and I g streams, it cnn bll observed thnt periodicnlly solids were cscnping from the first-stnge cyclone. Further, someoflhcso: purlicles l~ulmt nppruximatc ~ize L"{llnlto rhc top size oftlu: circulating bed materials. '11tns, lhc~e lnrgcr particles escaping from the lirsl·stngc cyclone were collected intire SL'Condn.y cyck•ne. The top size of pnrtich:s escnping the s~o'Cond· stage cyclotiC i~ nboul 2011111 with n mnss mean less 2-S 11111. '!11~ mlc nf solids ~:xi ling lht: second-stuge L')'~lon~ wn~ continuous nnd nt o relatively low mte. (06931 Generally, n hish solid loading is the primary e:tuse of sullntion in the crossover. lo this end, tiiC highest solids loading that enn convo:utionnlly be achieved without signili· cant saltation is typically 30 (lh solids/Jb l!IIS) nt ngas velocity ofnbmn70 Ills. While solid lonrlings ns high ns 70 lb. solidsllb gas Cltn 00 n~o'\.>dl\l in II Cf-0, the ~\lrTCSpunding gus \'elocity nC'Cd~o>d Ia climinnlc solids snltntion in the crossover was csli· mnled to be nbovc 140 11/s. However, a~ the gas \'cloeity is gelling higher, w:rll erosion bL'Comes a sitP~ilicnnl contem. Tilfft:fore, il is desired lo prevent solids snllalion wiliiOUI incrc01sing tho: l!'•s ''ducity bcyund the nonnnl u{ll!rnlin~ rnnge. (00941 DnSI.>d on the visunl observnlions on flow pntlcm in the cyclone entrnnc:c during Ute control experiments, the elimination of snllnlion hecon~es significant co borh improving the cyclone collection efliciency nnd ~ucing erosion. To evnlunle 1111! signiflcnnce, lire inventive dcsnltnlion drnin pipe {ODP) wa~ instulled in till! exemplary cuhl flow mudel. '111e llow pnllcru in the drnin pipe wns gcnemlly a dense pl~1se lrrursport with many clnngnled irregular bubbles, generated fromm.:mlion gns in lhe4-inch·di:mwtcr pipe. TI1e nmuunl uf gns to tltc slnndpipc is roughly cqunlto lhnl of gns emrnincd lrom solids plus nddcd lld to hnvc no prncticnl inHncnce on the flow pnncm within the C)'donc. 100961 'l11c lee section wns vcrydl'cctii'C in desnllution due lo both gns flow direction change and the impncling on the wall. Specifically, because the inventive crossover comprised nn inchncd pipe, the solids flawed directly from lite riser tn Ihe 11!1! without snllnlion. J\hhoush the solids were still flowing nlong the bonom 1•ortionof1•ipe, they were moving continuously One~ re.1ching the Icc, the majority of the Sltlids tumbled imutlll! dmin pipe while 1111: rest WLTO: ~arricd by gns to the cyclone. As long ns the drain pipe hns !he capacity co remove !he scparnled solids, the gas strc:.m going to !he cyclone wns at lensl substruninlly free of sall:tlion. 10097) When lhe DDP is in operation. tltc flmv paii<.'I'R~ in the cyclone entrance regiact nrc visibly dill'erenl from the ~onlrol te•t~ conducted wilhuut the use nf the tlesallnliun drniu piJie. As the gas cnrrying the n.>duccd conccnlrnlion or particles enh:rs the cyclone, particles grouped into one or a few slfl.'nl:s or stnmds nbout 'la·'IJ~ wide. Titcse stmnds conlain~o>d approximately 90% or morc of tl:e entering particles and flowed into lhc cyclone entrnnce in a substanlinlly horizontniJlRitem fnnnnllci1S11hefirst 'l•lo 'hofnturnm•undthe cyclone b.1rrel, depending on the solids lo:Kiing and the carlYing power oftlte gns. After litis initinlltori1.onlnl lrn\'el, Ihe: slmnds sinned to fom1 downward spirnls with n helical nngle in the rnngt:r of nllout 20-24•. IOO'JHJ As long as these wlids expericnc~d lillie or no sal1alion in the cyclone enlmnce 7Dnc nor did tho: solids loading become vel')' low (Jess lhan about 0.1 lb solids/lb gas) the hclicnl ru1gk., fonnl>d hy the t•articulnlc strands changed little wit II the solids loading and the catrnncc gas velocity, contmry lo lhc com·cnlionallogic. Under COIII'~o'lllional conditions, the nnglc is exp~.-..:t~d to de~rease with u d~oocr.:otsl! in the l'.lts velocity and/or nn increase in the solids loading. HowC"o•cr, in Ute observed Row pnttcnts, Ihe nngle changed minimnlly if111 all across 11 relntivcly wide range of gns velocity nnd snlids Iandini! condirions. The g<~s \'elocity nnd solids landings did however rc~ult in clmngcs in the numb~oTofrhc slmnds formed and strnnds oscilln1ion along the wall in the vertical din.'Ciion. For example, nt the high gns vclocil y nnd low solids landing, fewer and nmrowcr, possibly thinner, tilrnnds were foml<.'d and ll1cy nlso oscillnlcd \'et1ically. At lower velocity and higher londiog, mosl of till! solids fomtcd a single stmnd flowing spirnlly downward with little oscillation. A few scul· tered pnrticles were also obscrwd spinning nlon11 the w;,ll subslnntinlly hori7ontall)'. TitcSt: panicles after spimliog npproximnlcly one lum rcmmcd Ill tltc culrnnec nnd joined fresh incoming particles .:nlcriug into the slrnnds. I0099J 0\'ernll Collection Efllciency: Titc ov.:rnll eolk"!· lion efficiency for the primary cyclone can be ealculntl!d ns follnws, (l) SoCo FOIA Response 001872 US 2008/0216655 A I Sep. II, 2008 10 In equntion (I), t], symbolizes the m•crnll collection cffi· cicncy; F.1 I' 1 nntl Fz nre dcsign~tcd ns the solids circulation rnte, solids llow mte In the diplcg~nd to the bng lilter, rcspcc· lively. )01 00) Since the cydonc efficient)' for these tests nn: gen· cmlly greoterthnn99.9%,to distinguish the cHkicnc)' easier, "tenn cnlk'tl the numbcrof~epnmtion stul!c~,lllcnu similnr to numhcrof mnss trnnsferunit, cm1 he defined n~: t-.1 l'~f=-"'l\1 - tl) ,,, ) iiiii Nolethnl in this definition the vnlucofNSS i~ also cqunllo the number ofnines in the percent of efficiency (e.g., for 99"/o of cllicicncy, NSS cqnnls 2; for99.9"/oellicicncy, NSS is 3,ctc.). )0101) Grode Efficiency: 'l11c p:trticlc collection efficiency is defined as follows .. ,,,. ... teo;:=; (3) In equation (3), l)p represents theponiclecoli<'Ciion efficiency nnd w, stnuds f\lr the flow rate ofcollect...d pnrticlo:s with size less thnn n specified grndc. In other words, the pnrticle col· lection cRicicncy i¥ 11 WOidc efficiency based un lluw rule inslend of the solid inventory in the system. )01 021 Table II provides the test results indicating the infln· enccofentrnnccgas \'clocity on the ov.:mlllirsl·st:tgccyclone collection eftlciency. From the dnta in T.1blc II, one cnn see ll1.1lll1e collcclion cnici.:ncy is 1111: snme for lht: cnlmncc g.1s velocities of 60 nls nml I 00 fils. TA8l.F.Il M~tco1i1l• lnj..ct.d Clur Ct>lik ., ii Ellkid ns on ndditiw nnd the injL'Ciion mte was fnster (2·3 lblmin) thnn in pre\•ious tesls in ordcr to give inst:mlnncous high solids lo:1ding nnd to mnkc cflkiency men.mn:mcnl ca~icr. Tnhle Ill provide~ the le51 rc5ults, which indicate llml within the tcstL'tl rnnge, the entrance velocity hnd lillie intloence on the total solids collection elTiciency. In pnrtict1lnr, when one cxnmincs the nonnnlized solids nccumulntion rntc in the dipleg gi\·en in the l:ast column in Tnhlc Ill, onecan seo thai the nonnnlizt:d occumnlntion mtes nn: the smne for lhc IL'Sil'tlgns cnlrnncc \'elociry of37 nnd GO fVs. t\1 the inlet velocities of 37 and GO fils the system has belh:r coiiL'Ction efficient)' for fines. The enusc fortl1c cyclone being lower in the colll'Ciion cllicicncy at 90 fVs may lmvc been due to rc·~'lltmiruucm, as will be discussed below in fur1herdctnil. TABLF.lll Mu5ize (u:n) 5106 15.44 5106 95.96 11.)1 61.16 Tout c.u~. Cyclone 'lltus, iu one exempt~()' nspcct, il ~ppenrs that thecntrnnce gns velocity c~n reach a mnximum point :~htwc which li1rthcr increases In tl1e velocity will not improve the coli\.'Ction clll· ciency. I r the frictionnl ftlrce is neglected compared to the solids grnvity lllrce,thc only forcl'S on the mixmrc stn:-nm nrc the centrifugnl forces mnioly lb: 10 the gas velocity nnd gravity forces mninly <.:xcr1ing on solids. Then the fm\:c bnl· a11<:e provides <'t]UUtiun (4) beluw: (4) U,= In cqu:uion (4), D, s. w•. w. nnd 0 symbolize, in the gi\'ell order, cyclone bnrrcl dinmctcr, gmvitnlionnl occclcmtion,lJM !low rate, solids llow rntc nnd the solids downw~rd flow hclicnl nnglc. To use equntion (4) for the prclliction of the lisrr veloc-ity tWo) \'ctocity 1ft'•) IUtc(lbJ'kl) u l7 )1)00 29 (JJ )IJOO ')2 J15\l0 .w iolrt SolldJ Cth."Ubtio:t Ctllitc f'cotl(lb) 1.34 1.6 8.0 N'on1uliml Sol:at Colla.'lipltl!.. 51.5 H .9 45-J 2.97 2..:0 2.32 ••The sol d. ~c.-mullt.on inch~ ,fipl~ it r.cnn.slilt\1 tt.urd on il:k"hCJ .&C'cU· naa..bl...t in til<: a1iplrg for ..r the collection efficiL,tcy oflnrgcr panickos. II rtausiblc c:ondU$iOil for this obscrvmion i5 tl1:11 Ill hi~h ~n)ids loading a lower gus velocity f.1\'0rs fine collection and n higher g.u velocity gives l1igh c:ollcction clliciency for conn~L-r pnrticlcs. SoCo FOIA Response 001873 US 2008/0216655 A I Sep. II, 2008 II IU1071 FIG. JS providessomc fitrthcrexnmplcs ofcnlculntion results b.ul!d on the described cor~lation. For the cold now model, the solids lo.1ding ntthe cyclone inlet is oboutJO (lb solidsllb gos) nller desollntion. From FIG. 11, the cnlcu· lntcd sollotion vdocity is 70 1\/s foro lop ~i~e of50JUII, wllile the ohsen·cd solid~ collection efficiency dccr~:nscd nt 90 Ill$ of the cntr.mcc: wlacity. 'llti9 ~'Orrelntionuguin 5eems to IIRI· vide a vinhlc: prediction. Since the lnll!er panicles have n higher snltotiun velocity nml nrc hnrdcr to be n.'l:lllrnim:d, the high cnlrnncc vdocity should hove substonliolly no unfovornble inllncncc on collection efficiency for those larger par· ticles. Morcov~T, n high gos velocity will exert n weatc:r centrifngol force on huger particles. ·nms, this reasoning con e:1>1' is primarily for eliminating saltation limn the stream entering the cyclone nnd thus n:dncing the loading to the ttrinmry cyclone by sepnrntingsubstnntinl nmottntssolidsonddi~ctly sending the solids to the standpipe. As n result ofsnbstanti:LIIy eliminating snltnlion, the perfommnce of the first stage cyclone can be improved as shl'l\\'11 in Tnblc IV below: TABLE IV WiL~lJUI' P.\tJJJ:.ttCI"' \\'illlout DDP Clw- lnicx1it'ln f:ffiDP improves the cyclone performance in nil reported l.!lltl!!!orics. l':•rticulnrly, fur the sume dmr inj~-ction, with the DDP bothD,0 nnd maximum dPor D.,.., from tln:cyclonccxil decnmsc campan:d to without the DDP. lOll OJ In another asp~-ct, the: perfornumcc ofthc IJDI' cull be evaluated to determine the solids cmweying cnpncity lor the dmin pirc. To that end, exemplary c:1pacity test results nrc listed in Tobie V. 'llte results seem to indicate thnlthc llux for the drain pipe rctnnins ulmusl constunt for most uf the tests with n value nbaut 220 (lblll2 s). llowcver, nuder one test condition, the llux was ns high as 350 lb/(112 s). In equntion (II), dp,o• Jl, b, N,, V,, Pp• p• stnnds for, in lite given onler, tlte nmss menu purticlc dinrneter, gns viscosity, cyclone inlet width, rmmbcroflnms mnde by solids, inlet gns \'clocity, solids (lllrticle true density nnd gns density, respectively. 101141 11tc functionnlity of the voncx Iinder in a cyclone is to provide nn initial downward velocity comrmncut for the particJ~S tO l'l:lltkr them fimving 0111 Of the C)'Ciolle barre) SL-ctimt or to shorten the ~.~idente time of the coUccted rnr· ticles. To this end, some tests wen: also perlimned to identify the role oft he vortex find Lor on the collection enlcicnC)' of the inventive system. [01151 l11e test results for the vortex linller dli.'Ct arc 11iven in Tnble VI. ·ntcsc d.~ In seem to indicate that without n vortex finder tlte cyclone lms equnl or better collection efficiency TADLEV M:usftow IU.to Salf,lsflu" l 'odlkit4C K ic tq.a tbrhr llblt) (lb'• It') th'(s in1 ~1 S!2011 JSJ.Il 17600 27500 U9 7.6-1 224 JSO 0.16 61100 IS900 4.~2 202 0.7& ·let>) Riscr\'d«it~· Cif'-"'Uio~rit~n II!• tblh 27.2 29 29.6 How R:~tcia Or.1i~ Pipe l .J5 JS.4 5~600 IS~OO 5.22 2J~ 0.92 ~9 31416 mno ~.116 223 0.~6 SoCo FOIA Response 001874 US 2008/0216655 A I Sep. I I , 2008 12 Ctlntpm·l!d to with the vortex Iinder. "Jitblc VI ~I so shows that sm;~Jier exit pipe dinmctcr gh•es beucr colkction cfiiciency. 'Ji\IU .EVI C\-.:l"ne u HI \'<'tne!C 2" lllao•t fnjC'\:liOA Clur t:.lll:ip surfnc snrtiu:e process gns str~n111 contains cntrninal $ Wednesday, August 26, 200910:43 AM Madden, Diane Blair, Andrea D.; CWHENDER@southernco.com Kemper County IGCC Project TEXT.htm; IGCC Reporting Requirements.mpp Diane, The recent scheduling order issued by the Mississippi Public Service Commission allowed the timeframe for key project decisions and milestones to be firmly set. Once these overall milestones were set. the attached draft schedule for all the Cooperative Agreement requirements was prepared. The schedule file is in Microsoft Project format. Let me know if you do not have access to Microsoft Project, and I will send you a PDF document. Please let me know if you have questions, comments or additions. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) SoCo FOIA Response 001877 IGCC Reporting Requirements. I 10 ask Name Prajo!ct Management Plan Develop Dr.lft or PIO)eet HIJIIa!ll!"'""t Plan Internal Reoiew and ~of Project Management Plan ~"' Final ProJect Hanagen>ent Plan DOE Feedback on Pro)ect Hanagoment Plan Resok*>n or DOE Fl!l!dJild< on ProJect Management Plan DOE Approyal ol Project Plan c:on.m.dallzatlon 5tnlte9Y Report Develop Draft ol Commeltlalizatlon Slraleov RfiiOI1 lnlemal Reoiew and Feedback on CommercialiZation 51ra1eov RfiiOI1 Mil-"' ~"'Anal Commerdallzatlon Slraleov RfiiOI1 Commerdallzatlan Strategy summary Develop Commeltlallllltlon Sll'lltegy SUmmary for DOE Demonstration and Tut Plan (Commissioning Plan) Develop Draft of Oemonstnltlon and Test Plan l!eport Internal Reoiew and Feedback or Draft or Demonstration and Test Plan Report ~11! Final ~and Test Plan RfiiOI1 DOE Feedback on Demonstration and Test Plan l!epart Resok*>n ol DOE fl!l!dJild< DOE Approyal ol Demonstration and Test Plan l!epart Colllllllsslonklg alld Startup Report Develop Draft or Commissioning and Slanup RfiiOI1 lnlemal Reoiew and - o r Draft of Commissioning and stwtup Report ~"' Anal Commlulonlng and Slartup l!eport DOf Reoiew of Anal Commissioning and SlilltUp Report Reolutlon of DOE Fl!l!dJild< DOE Approya~ of Commlsslonlno and Startup l!eport Tat Plan for Demonstration PhloM Oew!lop Draft ol Test Plan for Oemonstnltlon Phase lnb!mal Reoiew and Feedbad< of Draft of Test Plan for Demonstration Phase Pl1!paf1! Anal Test Plan fflf Demonstration Phase DOE Reoiew ol Final Test Plan fflf OemonsiJation Phase Resolution of DOf Fl!l!dJild< DOE Approval or Test Plan for Demonstration Phase Site Prep~~ notion Plan, Scheduladt of Draft EIMronmental Compllana! l'liln """'""'Anal EnWII.metUI ~ l'liln DOE ReYiew ol ErMronmental Compliana! l'liln -.uon ol DOE ft!t!ll>adt SIDnlt Etwlronmenlill Comlilance Plan to DOE Envlnln...,tal Monllllrlnv ....., DeYolop Draft of Eti'Aronmerttal Hotitonng Plan Internal RetOew and Fetdlacl< of Draft Envtronmenlal MCititoring Plan ~"' Anal Environmental Monltonng Plan DOE Review of Environmental Mo!Otoring Plan R5llutlon of DOE F~ Sllbmlt EnWoomeriClll Monlloring Plan 10 DOE DeUons and Comments DOE Approval of Detailed Cost Breakdown for flhase IV Ewrytl*>g In P1a Tuesday, September 01, 2009 9:27 AM Johnson, Raymond; Russia!, Thomas Madden, Diane Fwd: SCS's Kemper County Cooperative Agreement -- Gas TurbineSupplier TEXT.htm; Buy Amer_Perf of Work in US.docx Sorry in advance about the long email. It was this or a conference call so I went with the email. rr Thanks, Brlttley bS << 8/12/2009 8:30AM >>> Brlttley, Tim and I would like to talk with you about a couple of concerns that our gas turbine supplier has raised with regard to the Flowdown Provisions that we have Included in the procurement agreement we are SoCo FOIA Response 001881 negotiating wllh this supplier. Specifically, the concerns relate to the Buy American Act, the provision regarding the use of direct labor In the United States, and the remote possibility that new patentable Inventions could be developed during the term of the supply agreement between SCS and this supplier. My secretary says you will be back In the office on Thursday (tomorrow) - correct? If you want to give me a call then, I can give you more details. After that, you might want/need to gather up whomever from NETL needs to be involved and we can have a larger group conference call. Tim and I are available next week for a conference call with your team -- Monday afternoon looks good as do most of Tuesday and Wednesday. Thank you, Jennifer (b) Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (office) (6) mobile) 205-257-6381 (fax) jenmorrl@southernco.com This e-mail and any of Its attachments may contain non-public and/or proprietary Information of Southern Company and/or Its affiliates that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail Is Intended solely for the use of the Individual or entity for which It Is Intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or Its arfillates and Is prohibited. If you are not the intended recipient of this e-mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you . • 2 SoCo FOIA Response 001882 2.19 Compliance with Buy American Act (OCT 2004) In accepting this award, the Recipient agrees to comply with sections 2 through 4 of the Act of March 3, 1933 (41 U.S.C. IOa-lOc, popularly known as the "Buy American Act"). The Recipient should review the provisions of the Actio ensure that expenditures made under this award are in accordance with it. 2.35 Pcrfo•·mancc ofWoa·l<. in the United States (AUG 2003) The Recipient ag•·ees that at least 75% of the direct labor cost for the project (including subcontractor labor) will be incurred in the United States unless the Recipient can demonstrate to the sntisfaction of the DOE that the United States economic interest will be better served through a greater percentage of work performed outside the United Slates. SoCo FOIA Response 001883 Dunlap, Ann c. From: Sent: To: Cc: Subject: Attachments: Thomas Russial Thursday, September 03, 2009 8:18 AM Robbins, Brittley Madden, Diane; Johnson, Raymond Re: Fwd: SCS's Kemper County Cooperative Agreement -- Gas TurbineSupplier TEXT.htm >>>Raymond Johnson 9/1/2009 10:5'1 AM>>> Brittley, bS From a quick reply perspective...... I believe the locally developed Performance In the u.s. provision was based upon the project as a whole vs. Individual portions or performers. Secondly, the provision provides a window of opportunity If the recipient can satisfactorily demonstrate to DOE that the U.S. economic Interest Is better served if the 75% direct labor In the U.S. can not be met. On the Buy American aspect, I'd have to look Into this further but may be Tom will have a quicker reply on hand. However, I believe your guidance to Jennifer Is on point and It's up to the recipient to adequately document their files regarding any non-Buy American determination Is made and whether the basis Is on price, availability or other factors.......... >>> Brlttfey Robbins 9/1/2009 9:27AM >>> Sorry In advance about the tong email. It was this or a conference call so I went with the email. I spoke to Jennifer about this issue last week. She explained that Siemens, their gas turbine supplier, Is an American company but they do a lot of manufacturing In canada. Indeed, for the Kemper project, almost all of the turbine work will be done In canada. Further, most of the parts that Siemens orders for the turbine are foreign parts. Given the above, Siemens takes issue with two clauses: Buy American Act and Performance of Work In the United States. A few notes on each clause and my discussion with Jennifer about each is contained below. Buy American: As background, the Buy American clause Is Included In the Agreement because the funds under the project were appropriated under the Interior and Related Agendes Appropriations Act (not Energy and Water) thus SoCo FOIA Response 001884 requiring inclusion of the clause. I Informed Jennifer that the Buy American requirement was not an absolute requirement and In certain Instances where Buying American Is not reasonable (price or avallabillty)1 the Recipient Is required to document their Internal files as to the reason they did not Buy American. She understood but had some concerns about what Information Siemens would be able to provide as to their justification for not Buying American. Siemens solicits quotes from vendors and in most Instances goes with the lowest price available. They don't really do any tracking or cost/availability comparison with American vs. non-American products. Siemens has offered to send Southern a description of their procurement practices and once Southern receives that1 they will forward to us. All this to say1 do you have any Insight on what type of Information Southern or Siemens will need to retain within their files to justify not Buying American. Is Siemens approach of going with the lowest price available (If that truly Is the case) good enough of a justification to not purchase American or is there a certain cost percentage that the American good must be X% more in price than the non-American good? Performance of Work in the United States: Because Siemens does their manufacturing In Canada, there is likely no way that they can meet the requirement that at least 75% of the direct labor be Incurred in the United States. However, I talked to Jennifer and explained to her that the Performance of Work In the US clause may apply only to the project as a whole and not necessarily at the Individual subcontractor level but I wasn't sure. Can you confirm whether the Individual requirement for 75% direct labor would apply to Siemens? Or Is it that for the entire project (Orlando to Kemper) as a whole1 at least 75% direct labor must be incurred In the US (Including subcontractor labor)? Both clauses are attached as a reference. Jennifer and I didn't discuss the patentable Inventions item that she mentions In her email below1 so I am not sure what that Is about. Thanks, Brlttley << 8/12/2009 8:30AM>>> Brittley1 • Tim and I would like to talk with you about a couple of concerns that our gas turbine supplier has raised with regard to the Flowdown Provisions that we have Included In the procurement agreement we are negotiating with this supplier. Speclflcally1 the concerns relate to the Buy American Act1 the provision regarding the use of direct labor In the United States1 and the remote possibility that new patentable Inventions could be developed during the term of the supply agreement between SCS and this supplier. My secretary says you will be back In the office on Thursday (tomorrow) - correct? If you want to give me a call then, I can give you more details. After that, you might want/need to gather up whomever from NETL needs to be involved and we can have a larger group conference call. Tim and I are available next week for a conference call with your team-- Monday afternoon looks good as do most ofTuesday and Wednesday. Thank you1 Jennifer Jennifer M. Buettner Southern Company Servlces1 Inc. 600 North 18th Street1 Bin 7N-8374 Blrmlngham1 Alabama 35203 205·257·6730 (office) 2 SoCo FOIA Response 001885 (b) (6) (mobile) 205-257-6381 (fax) lenmorrl@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary information of Southern Company and/or Its affiliates that is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e·mail Is Intended solely for the use of the individual or entity for which it Is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e·maills contrary to the rights of Southern Company and/or Its affiliates and Is prohibited. If you are not the Intended recipient of this e-mail, please notify the sender immediately by return e·mall and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 3 SoCo FOIA Response 001886 From: Sent: To: Subject: Attachments: (b) (4), (b) (6) Tuesday, December 01, 2009 9:14 AM Toth, Brian D.; House-Pearson, Cindy J SAM; Berry, Charles Rick; dabbott@mdah.state.ms.us; damon.m.young@ usace.army.mil; Warren, Daniel; Madden, Diane; Florance_Watson@deq.state.ms.us; Pukanic, George;(b) (4), (b) (6) Templeton, John D.; Meling. Jeff; Trouart, Joel E.; Carleton, Ken; Grunewald, Matthew M. SAM; olinwilliams@choctawnation.com; lieb, Pamela Edwards; rafferty@anthro.msstate.edu; Hargis, Richard; tcole@choctawnation.com RE: Venue and Draft Agenda: Kemper County IGCC Proj ect - Draft Programmatic Agreement Review Meeting, 1 PM - S PM, December Bth,Jackson, MS TEXT.htm Thanks, Dan. I agree with you - I do think that it would be particularly helpful (at least in the sense of having a maximally productive meeting on the 8th) if anyone with specific issues about the PA were to share them with the group beforehand. That way, we can all come in prepared to talk about any such issues and we aren't trying to deal with them on the fly. Know what I mean? See you all next week. Safe travels (b) (4), (b) (6) anlel Warren :dnesday, November 25, 2009 5:42 PM 1ela Edwards Ueb; Carleton, Ken; tcole@choctawnatlon.com; ollnwlnlams@choctawnatlon.com; damon.m.young t;usace. anny.ml~ House·Pearson, Cindy J SAM; dabbottOmdah.state.ms.us; Richard Hargis; George Pukanlc; Diane Madden; Templeton, John D.; Trouart, Joel E.; rafferty@anthro.msstate.edu; (b) (4), (b) (6) Charles Rick Berry; Toth, Brian D.; Jeff Mellng; (b) (4), (b) (6); Grunewald, Matthew M. SAM; Florance_Watson@deq.state.ms.us Venue and Draft Agenda: Kemper County IGCC Proj ect • Draft Programmatic Agreement Review Meeting, 1 PM • 5 PM, December 8th, Jackson, MS Greetings, Pam Lieb, Mississippi Department of Archives and History, has reserved the boardroom for this meeting in her office building (The Charlotte Capers Building) in Jackson, Mississippi. Directions to the building, street address and location of the boardroom are provided below. DOE intends to provide a copy of the draft Programmatic Agreement for the Kemper County IGCC Project (KCIP) by the end of next week for your review prior to the December 8th meeting. A draft agenda is attached and also provided below for your review and edit. If you have particular concerns or issues with the draft PA, please share them with the group and they can be added to the agenda. Let me know if you have any questions. Best regards, Dan Warren Directions: SoCo FOIA Response 001887 Boardroom: The Charlotte Capers Building. It is located on the other side of the Old Capitol from the Winter building. From I-55, if you take the Pearl Street exit and take a right on State Street you will go to Amite Street and take a right. The first driveway on your right takes you to the parking for the Old Capitol building. You can park there. The Charlotte Capers building is to the left of the Old Capitol and has a large confederate monument in f ront of it. The address for the building is 100 South State Street, Jackson, Mississippi 392014400. You will enter through the lobby and the secretary will have you sign in. The boardroom is located on the 2nd floor. Take a right when you get off the elevator and it will be the last door on the left. Link to a map: http://www.bing.com/maps/default.aspx?v=2&cp=32.29900944983101"'90.1802 45&1vl: 15&sty=r&where1= 100'Yo20S %20State 'Yo20St'}'o2C'}'o20J ackson '}'o2C'}'o20MS '}'o2039 201-4400 «File: Agenda 8 Dec 09 Mtg reDraft PA Jackson.doc » Draft Agenda Draft Programmatic Agreement for the KCIP The Charlotte Capers Building 100 South State Street Jackson, Mississippi 39201-4400 Boardroom, 2nd Floor December 8, 2009, 1 PM to 5 PM • Welcome and Introductions • Overall status of the KCIP • Review and address issues related to draft PA 2 SoCo FOIA Response 001888 • Next steps: process to complete regulatory compliance, additional review periods, signatories, deadlines, etc. • Adjourn -----Original Message----From: Warren, Daniel H. Sent: Monday, November 23, 2009 3:47PM To: 'Pamela Edwards Lieb'; 'Carleton, Ken'; 'tcole@choctawnation.com' ; 'olinwilliams@choctawnation.com'; 'Pamela (Pam) Edwards Lieb (pedwards@mdah.state.ms.us)'; 'damon.m.young@usace.army.mil'; 'House-Pearson, Cindy J SAM'; 'dabbott@mdah.state.ms.us'; 'Richard Hargis'; 'George Pukanic' ; 'Diane Madden'; Templeton, John D.; 'Trouart, Joel E.' ; Berry, Charles Rick (MPC); Toth, Brian D.; 'Jeff Meling' ;(b) (4), (b) (6) (b) (4), (b) (6) Grunewald, Matthew M. SAM Subject: RE: Kemper County IGCC Project - Draft Programmatic Agreement Review Meeting (b) (4), (b) (6) Greetings, Please pencil in the afternoon of December 8th for a meeting to discuss the draft Programmatic Agreement for the Kemper County IGCC Project. We will meet in Jackson, Mississippi starting at 1:00PM. Meeting venue and draft agenda will be provided later. Also, let me know if there are others who you think need to be invited to this meeting. Thanks, Dan Warren Jl Please print this email only if absolutely necessary. Daniel H. Warren, Southern Company;205.257.6947; (b) (6) cell; lh<: onfonnJuun contJon..' mcsso~;c os not the onMiol<'tl rocopocnt, or the cmploy<-c or •Mcnt rcsponsobl" lu dell\ cr it to the wtcnol•'tl r.'Copo.'llt \ ou ar" notolicol that Dn) doss.mmotoon dostnbuloon or CUJl) mg of thos communoo.::>tooon os slnctlv pmhobot<'tl If ) OU h.,.., n.'Cch·cd thos communocouon on •·nor, plc;asc omn><:oloalcl) 111M If) us at 205-257 69~7 lltanl )OU 3 SoCo FOIA Response 001889 From: Sent: To: Cc: Subject: Attachments: "Blair, Andrea D." Monday, December 07, 2009 10:20 AM Madden, Diane Pinkston, Tim E. FW: Kemper County IGCC Project- Cooperative AgreementRequirements Update TEXT.htm; IGCC Reporting Requirements.mpp; !GCC Reporting Requirements Revl.pdf Good Morning Diane, Tim indicated that you were unable to find the latest IGCC Reporting Requirements schedule. I have attached the requested documents as well as the original email for your review. Please let me know if you have any questions. Thanks, Andrea D. Blair Project Engineer Engineering and Construction Services Gasification Technology From: Blair, Andrea D. Sent: Wednesday, September 30, 2009 5:17 PM To: Dlane.Madden@NETL.DOE.GOV Cc: Henderson, Charles W.; Pinkston, Tim E. Subject: Kemper County IGCC Project - Cooperative Agreement Requirements Update Diane, Attached is the latest revision of the schedule of all the Cooperative Agreement requirements. I have made the corrections that you suggested to Tim. Several DOE approval dates in the file were modified: Project Management Plan to 30 days, FEED Report to 60 days, Test Plan for Demonstration Phase to 45 days, Final TRIG report to 90 days, and Construction Report to 45 days. I also changed the DOE Approval of Detailed Cost Breakdown for Phase IV from 7.38 to 7 days. The Environmental Compliance and Monitoring Plan tasks have been modified to show milestones during the approval status, this ensures that the first Environmental Report (newly added Activity 95) is complete by October 31, 2010. Note that we will start quarterly environmental reports on 10/112010. Please let me know if you have any other suggestions. The schedule is in Microsoft Project format. I have also attached the schedule in PDF document; however, this format only shows the left columns. I look forward to your review and feedback. Thanks, Andrea D. Blair Project Engineer Gasification Technology Southern Company Generation Office: (205) 992-5758 Cell: (b) (6) 1 SoCo FOIA Response 001890 SoCo FOIA Response 001891 .. I L j ;;;;:a~; ~~·~• !!:;~~~~; !!:.::;~ ;; : 11:;~ t;;:!~i;;l; 3; II '!! !:0! ! I •Z l ................................... --····- ,_, ______ , ~~ i~~~~~~~!~~~~~ ~~~~~~~~~ie~~ee ~~~ ~~~~~~~~~~~ ~~ ~~ll§l!l~~···· lj~~::~£j~:~~~j ~jj j:il!:l~~~~ ~-~~ §§··· •••• ······-····· · ······· ·--· ~ • •• ~~~~~~~~~ llf!~~~ll j ~~ I' j ! -~-------~-· I ~ i i i ~ i ~ ~ ~ ~ ! ~ ~ ~ ~ ~ ~ e§~ ~ ~ ~ ~ e~ ~ ~ ~ e~ e~ ~ ~ ~ ~ ~ i ~ ~ ~ §~ ~ ~ ~ ~ ~ ~ ~ ~ ~ § ~ i 1~ § ~ i s1 4 ~~ll~l~Jjli~!'~~~~:E~~lJJ~~~~~jl~~iiJI!!~!iJ~!~~j~~~~ji~~lJJJ~I 1l • SoCo FOIA Response 001892 ] 1~~~~~5fi~~i~£~~~~~i~S§~~~S5~i~i~~~ii~~ili~5SSi~i~!ss~£i~ ~~~~l~~~~ll~J~~i~~!lj~~~~~~~:£~~~~&&1~~~~11ll~jl!~Jjjj ~~=22g===~=ia:n==e2~~ i ~:~~~·:~=~i~~~~~~~~~~~~~~=~~g~~~ I ~!!ffi[ff!l!!tf!!iiii!f!!~i!!!!il~!!iiiill!!!!!i!!!!!! • ll I SoCo FOIA Response 001893 Project Manilgement Pfiln Develop Draft of Project Management Plan Internal Review and Feedback of Project Management Plan Prepare Final Project Management Plan DOE Feedback on Project Management Plan Resolution of DOE Feedback on Project Management Plan DOE Approval of Project Management Plan Commerdallutlon Strategy Report Develop Draft of CommerdaWzation Strategy Report Internal Review and Feedback on Commerdalizatlon Strategy Report Prepare Final Commerdallzatlon Strategy Report Commercialization Strategy Summilry Develop Commercialization Strategy SUmmary for DOE Demonstration and Test Plan (Commissioning Plan) Develop Draft of Demonstration and Test Plan Report Internal Review and Feedback of Draft of Demonstration and Test Plan Report Prepare Final Demonstration and Test Plan Report DOE Feedback on Demonstration and Test Plan Report Resolution of DOE Feedback DOE Approval of Demonstration and Test Plan Report Commissioning and Startup Report Develop Draft of Commissioning and Startup Report Internal Review and Feedback of Draft of Commissioning and Startup Report Prepare Final Commissioning and Startup Report DOE Review of Final Commissioning and Startup Report Resolution of DOE Feedback DOE Approval of Commissioning and Startup Report Test Plan for Demonstration Phase Develop Draft of Test Plan for Demonstration Phase Internal Review and Feedback of Draft of Test Plan for Demonstration Phase Prepare Final Test Plan for Demonstration Phase DOE Review of Final Test Plan for Demonstration Phase Resolution of DOE Feedback DOE Approval ofTest Plan for Demonstration Phase Site Preparation Plan, Schedule, and Layout Develop Draft of Site Preparation Plan, Schedule, and Layout Internal Review and Feedback of Draft of Site Preparation Plan, Schedule, and Layout Prepare Final Site Preparation Plan, Schedule, and Layout Submit Site Preparation Plan, Schedule, and Layout to DOE Updated Commercialization stntegy Report Develop Draft of Updated Commercialization Strategy Report Internal Review and Feedback of Updated Commercialization Strategy Report Pre are Final ated Commercialization Stra rt Ouralion 208 days 90 days 14 days 14 days 30 days 30 days 30 days 104days 60 days 14 days 30 days 10days 10 days 162 days 60 days 14 days 14 days 30days 14 days 30 days 162 days 60 days 14 days 14 days 30 days 14 days 30days 177 days 60 days 14 days 14 days 30 days 14 days 45 days Bldays 30 days 7 days 14 days 30 days 74days 30 days 14 days 30da s Start Tue9/1/09 Tue 9/1/09 Tue 1/5/10 Mon 1/25/10 Fri 2/12/10 Fri 3/26/10 Fri 5/7/10 Mon 10/8/12 Mon 10/8/12 Mon 12/31/12 Fri 1/18/13 Fri 3/1/13 Fri 3/1/13 Mon 9/3/12 Mon 9/3/12 Mon 11/26/12 Fri 12/14/12 Thu 1/3/13 Thu 2/14/13 Wed 3/6/13 Thu 5/15/14 Thu 5/15/14 Thu 8/7/14 Wed 8/27/14 Tue 9/16/14 Tue 10/28/14 Mon 11/17/14 Frl2/1/13 Fri 2/1/13 Fri 4/26/13 Thu 5/16/13 Wed 6/5/13 Wed 7/17/13 Tue 8/6/13 Mon 5/3/10 Mon 5/3/10 Mon 6/14/10 Wed 6/23/10 Tue 7/13/10 Tue 5/15/18 Tue 5/15/18 Tue 6/26/18 Mon 7 16 18 Finish Thu 6/17/10 Mon 1/4/10 Fri 1/22/10 Thu 2/11/10 Thu 3/25/10 Thu 5/6/10 Thu 6/17/10 Thu 2/28/13 Fri 12/28/12 Thu 1/17/13 Thu 2/28/13 Thu 3/14/13 Thu 3/14/13 Tue 4/16/13 Fri 11/23/12 Thu 12/13/12 Wed 1/2/13 Wed 2/13/13 Tue 3/S/13 Tue4/16/l3 Fri 12/26/14 Wed 8/6/14 Tue 8/26/14 Mon 9/15/14 Mon 10/27/14 Fri 11/14/14 Fri 12/26/14 Mon 10/7/13 Thu 4/25/13 Wed 5/15/13 Tue 6/4/13 Tue 7/16/13 Mon 8/5/13 Mon 10/7/13 Mon 8/23/10 Fri 6/11/10 Tue 6/22/10 Mon 7/12/10 Mon 8/23/10 Fri 8/24/18 Mon 6/25/18 Fri 7/13/18 Fri 8 24 18 Predecessors 2 3 4 5 6 98 9 10 11 15 16 17 18 19 96 22 23 24 25 26 29 30 31 32 33 36 37 38 108 41 42 Page 1 SoCo FOIA Response 001894 IGCC Reporting Requirements.l JD 0 ~ ~ ~ ~ ~ 49 50 r---s1 ~ f----53 f----54 r----ss "'56 57 ~ r---sg f---60 "'51 62 • •• •• • •• • •• • ----n • ---ro63 64 ~ ~ ~ ~ 69 70 71 ~ ~ ~ ~ 76 17 ~ ----e-1 --a2 83 84 ---o5 ---ss • ITaskName Updated Commercialization Strategy Summary Develop Updated Commercialization Strategy Summary for DOE Environmental Compliance Plan Develop Draft of Environmental Compliance Plan Internal Review and Feedback of Draft Environmental Compliance Plan Prepare Final Environmental Compliance Plan DOE Review Df Environmental Compliance Plan Resolution of DOE Feedback Submit Environmental Compliance Plan to DOE Environmental Monitoring Plan Develop Draft of Environmental Monitoring Plan Internal Review and Feedback of Draft Environmental Monitoring Plan Prepare Final Environmental Monitoring Plan DOE Review Df Environmental Monitoring Plan Resolution of DOE Feedback Submit Environmental Monitoring Plan to DOE Develop Cost Breakdown for Phase Wb Anal Cost Codes and Accounting Rows for Project to Support DOE Requirements Prepare Draft Detailed Cost Breakdown for Phase Illb DOE Review of Breakdown Prepare Final Cost Breakdown DOE Review Df Breakdown Resolution of DOE Questions and Comments DOE Approval of Detailed Cost Breakdown for Phase Illb Everything in Place for DOE to Reimburse Costs (Except NEPA) Develop Cost Breakdown for Phase IV Prepare Draft Deta~ed Cost Breakdown for Phase IV DOE Review Df Breakdown for Phase IV Prepare Anal Cost Breakdown DOE Review of Breakdown Resolution of DOE Questions and Comments DOE Approval of Detailed Cost Breakdown for Phase IV Everything In Place for DOE to Reimburse Costs Front End Engineering Design Report Develop FEED Report Draft Internal Review and Feedback Df FEED Report DOE Review of FEED Report Resolution of DOE Comments of FEED Report DOE Approval of FEED Report Preliminary Public Design Report Rename FEED Report to Preliminary Public Design Report & Submit Detailed Design Report Develoo Draft of Detailed DesiQn Reoort -. Duralion 10 days 10 days 111 days 30days 7 days 14 days 30 days 30 days 0 days 111 days 30days 7 days 11 days 30 days 30 days 0 days 178 days !day 21 edays 14 edays 60 edays 90 edays 30 edays 30 edays 1 day 188 days 60 edays 14 edays 60 edays 90 edays 30 edays 7 edays 1 day 238days 60 days 14 days 90 days 14 days 60 days S days Sdays 162 days 60 davs I Start Finish IPredecessors I Mon 8/27/18 Fri 9/7/18 43 Mon 8/27/18 Fri 9/7/18 Fri 4/30/10 Fri 10/1/10 Fri 4/30/10 100 Thu 6/10/10 47 Fri 6/11/10 Mon 6/21/10 Tue 6/22/10 Fri 7/9/10 48 Mon 7/12/10 Fri 8/20/10 49 Mon 8/23/10 Fri 10/1/10 50 Fri 10/1/10 Fri 10/1/10 51 Fri 4/30/10 Frl10/1/10 100 Fri 4/30/10 Thu 6/10/10 Fri 6/11/10 Mon 6/21/10 51 Tue 6/22/10 Fri 7/9/10 55 Mon 7/12/10 Fri 8/20/10 56 57 Mon 8/23/10 Fri 10/1/10 Fri 10/1/10 Fri 10/1/10 58 Thu 4/15/10 Tue 8/11/09 Tue8/ll/09 Tue 8/11/09 61 Tue 8/11/09 Tue 9/1/09 62 Tue 9/1/09 Tue 9/15/09 Wed 9/16/09 Sll1 11/15/09 63 Sun 11/15/09 Sat 2/13/10 61 65 Sat 2/13/10 Mon 3/15/10 Mon 3/15/10 66 Wed4/1'1/10 67 Thu 4/15/10 Thu 4/15/10 Mon 4/21/14 Thu 8/1/13 Thu 8/1/13 Mon 9/30/13 70 Mon 9/30/13 Mon 10/14/13 71 Mon 10/1'1/13 Fri 12/13/13 Fri 12/13/13 Thu 3/13/1'1 72 73 Thu 3/13/14 Sat '1/12/14 74 Sat 4/12/1'1 Sat 4/19/14 75 Mon 4/21/14 Mon 4/21/1'1 Tue S/4/10 Thu 3/31/11 Tue 5/4/10 Mon 7/26/10 97 78 Tue 7/27/10 Fri 8/13/10 79 Mon 8/16/10 Fri 12/17/10 80 Mon 12/20/10 Thu 1/6/11 Fri 1/7/11 Thu 3/31/11 81 Frl4/1/11 Thu 4/7/11 82 Frl4/1/11 Thu 4/7/11 Mon 10/8/12 Tue S/21/13 98 Mon 10/B/12 Fri 12/28/12 Page 2 SoCo FOIA Response 001895 IGCC Reporting Requirements.l 10 lo I !Task Name lrltemal Review and Feedbadt of Detailed Design Report Prepare Final Demonstration and Test Plan Report DOE Review of Detailed Design Report Resolution of DOE Feedback on Detailed Design Report DOE Approval of Detailed Design Report final Public Design Report Rename Detailed Design Report to Final Public Design Report & Submit Start Quarter1y Environmental Reports First Environmental Report (Covers: July - September) COD for Kemper County Conceptual Design for Kemper Detailed Design for Kemper County Construction on Kemper County IGCC NEPA Approval final TRIG Project Report Develop Draft of TRIG Project Report Internal Review and Feedback of TRIG Project Report Prepare Final TRIG Project Report DOE Review of Final TRIG Project Report Resolution ot DOE ~ck DOE Approval ot Flllcll TRIG Project Report Completion of Demonstration Period for Kemper County Construction Report Develop Draft of Construction Report Internal Review and Feedback of Draft of Construction Report Prepare Final Construction Report DOE Feedback on Construction Report Resolution ot DOE Feedback DOE Aooroval ot Construction Reoort Duration 14 days 14 days 30 days 14 days 30 days 5 days 5 days Odays 20 days Odays 363 days 634 days 1007 days 0 days 172days 90 edays 15 edays 15 edays 90 edays 30 edays Oedays 1043 days 177 days 60 days 14 days 14 days 30 days 14 days 45 davs I Start Mon 12/31/12 Fri 1/18/13 Thu 2/7/13 Thu 3/21/13 Wed4/10/13 Wed 5/22/13 Wed 5/21/13 Fri 10/1/10 Moo 10/4/10 Wed 5/14/14 Thu 12/11/08 Tue 5/4/10 Fri 7/2/10 Fri 4/30/10 Mon 5/14/18 Mon 5/14/18 Sun 8/12/18 Moo 8/27/18 Tue 9/11/18 Moo 12/10/18 Wed 1/9/19 Thu 5/15/14 Mon 5/12/14 Mon 5/12/14 Mon 8/4/14 Fri 8/22/14 Thu 9/11/14 Thu 10/23/14 Wed 11/12/14 I Finish Thu l/17/13 Wed 2/6/13 Wed 3/20/13 Tue4/9/13 Tue 5/21/13 Tue 5/28/13 Tue 5/28/13 Fri 10/1/10 Fri 10/29/10 Wed 5/14/14 Mon 5/3/10 Fri 10/5/12 Sun 5/11/14 Fri 4/30/10 Wed 1/9/19 Sun 8/12/18 Mon 8/27/18 Tue 9/11/18 Mon 12/10/18 Wed 1/9/19 Wed 1/9/19 Mon 5/ 14/18 Tue 1/13/15 Fri 8/1/14 Thu 8/21/14 Wed 9/10/14 Wed 10/22/14 Tue 11/11/14 Tue 1/13/15 !Predecessors 86 87 88 89 90 91 52,59 94 97 108 102 103 104 105 106 96 99 110 111 112 113 114 Page 3 SoCo FOIA Response 001896 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Brittley Robbins Friday, January 22, 2010 3:29 PM Buettner, Jennifer M. CWHENOER@southernco.com; Madden, Diane; TEPINKST@southernco.com Re: Kemper County -- Cooperative Agreement Flowdown Provisions Flowdowns in Commercial Agreements (10-1-09).DOC HI Jennifer, Sorry about the delay In getting back to you on this. I had been waiting on feedback from Tom Russia! so when he left that threw a wrinkle into my plans. Nonetheless, both myself and Ray Johnson, the Contracting Officer, have looked over the flow-downs and we have feedback to provide. I was originally going to walt until February to provide the feedback thinking we would be less busy but now seems like as appropriate a time as ever. I have the following questions/comments on the flow-down document. It doesn't appear that the flow-down of 10CFR600.331(a) Is fully covered by the "Termination" clause that Is in the Exhibit. 10CFR600.331(a) requires provisions be Included to allow for administrative, contractual, or legal remedies in instances in which a contractor violates or breaches the contract terms, and provide for such remedial actions as may be appropriate. The "Termination" clause In the Exhibit only allows for termination In the even that the Cooperative Agreement Is terminated. • Is there a reason why the Contract Work Hours and Safety Standard Act (From Appendix B to 10CFR600, Subpart D) requirement Is not flowed down? It seemed odd that it wasn't Included when the Copeland "Anti· Kickback" Act clause was Included. The Inclusion of the Copeland clause assumes it could be a construction contract. Or Is it contemplated that none of the construction subcontracts would be over the $lOOK threshold? • It seems the following Cooperative Agreement clause would need to be flowed down In one form or another: • Article 2.29 Permits and Licenses: Within sixty (60) days of the award date (identified in Block 21 on the face page) ofamendment A004 to this Cooperative Agreement, the Recipient shall submit to the DOE Project Officer a list of ES&H approvals that, in the Recipient's opinion, shall be required to complete the work under this award. The list shall include the topic of the approval being sought, the approving authority, and the expected submittal/approval schedule. The DOE Project Officer shall be notified as specific items are added or removed from the list and processed through their approval cycles. The Recipient agrees to Include this clause In first-tier subcontracts and agrees to enforce the terms of this clause. • The "Severability" flow-down Is based on the not-so-old procedures where a DOE Financial Assistance Appeals Board was still in existence. This was recently changed in Sept. 2009. Instead of mentioning the FA Appeals Board, It Is more appropriate to mention the "DOE Senior Procurement Executive". (Reference 10 CFR 600.22) If you have any questions, we can discuss at your earliest convenience. Thanks and, again, I apologize for the delay, Brlttley >>> "Buettner, Jennifer M." 10/15/2009 5:48PM >>> HI Brittley, SoCo FOIA Response 001897 Thanks again for your guidance on the applicability of the Buy America Act and Performance of Work obligation as nowdowns In our subcontracts with suppliers. Since this Issue has arisen, we thought it would be prudent to get guidance on the flowdown provisions we are using for commercial procurements on the Kemper County project. With that In mind, I am sending you a copy of what we used for commercial procurements in the Orlando project. This document was prepared before I was in this position, but I am told that there was an understanding between SCS and DOE about this document. I know that you are swamped with Stimulus Act proposal reviews right now, so I don't expect for you to respond quickly -I just wanted to go ahead and get in your queue of things to look at once you get finished with (or a pause in) the stimulus work. We want to be sure that our commercial item procurements for this project are subject to the appropriate DOE regulations. Are you and your team able to take a look at this when you get the time? Thanks very much! Jennifer (b) Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N·8374 Birmingham, Alabama 35203 205·257-6730 (office) (6) (mobile) 205-257·6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary information of Southern Company and/or its affiliates that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the Individual or entity for which It Is Intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e·mal!, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 2 SoCo FOIA Response 001898 EXHIBIT _ __ TO THE AGREEMENT BETWEEN SOUTHERN COMPANY SRRVICES, INC. AND _ _ __ FLOWl>OWN PROVISIONS FROM COOPERATIVE AGREEMENT BETWEEN DOE AND SOUTHEl{N COMPANY SERVICES, INC. Contractot1Supplicr understands that the Agreement is a subcontract under Cooperative Agreement Number DE-FC26-06NT42391 between Southern Company Services, Inc. (SCS) and the U.S. Department of Energy (DOE), and therefore certain contract provisions from the Cooperative Agreement must be flowed down to and included as pnrt of this Agreement. Based on the representations made by Contmctor/Supplier below, the flowdown provisions fi·om the Cooperative Agreement nre those contained in this attachment to the Agreement. In particular, Contractor/Supplier's representations provide a basis for not requiring the Contractor/Supplier to comply with the regulations pertaining to Federal Cost Principles (allowability and allocability) that are locnted nt Section 31 of the Federal Acquisition Regulations nnd to the Federal Cost Accounting Standards. Contractor/Supplier represents thnt the goods nnd/or services fumished under the Agreement nre commercially available goods nnd/or services that are alTered for snle in Contractor/Suppliet·'s rcgulnr course of business. It fm1her represents that the goods and/or sef\•ices provided do not involve the development of intellectual pmperty, the creation of new goods, or research and development activities. 1. Lobbying Rcstl·ictions By entering into the Agreement, Contractor/Supplier agrees that none of the monies it receives under the Agreement will be made available for any activity or the publication or distribution of literature that in any way tends to promote public suppmt or opposition to any legislative proposal on which Congressional action is not complete. This restriction is in addition to those prescribed elsewhere in statute and regulation. 2. Notice Regnrding Unnllownblc Cosls and Lobbyine Activities (Required with Respect to Allowable Costs PcJ·tniuiug to Lobbying) SCS must ensure that that the funds it receives pursuant to the Cooperative Agreement are used in n manner that complies with the federal allowable cost provisions and other similar provisions applicable to expenditures under the Cooperative Agreement. As n result, SCS must require Contractor/Supplier to comply with the provisions prohibiting the expenditure of monies received under this Agreement for lobbying and related activities. Monies paid to Contractor/Supplier under the Agreement may be used to describe and pmmote the understanding of scientific nnd technical aspects of specific enea·gy technologies, but not to encourage or support pol.itical activities such ns the collection and dissemination of infonnntion related to potential, planned or pending legislation. I of4 SoCo FOIA Response 001899 3. Notice Regn•·ding the Pm·chnsc of Ame1·icnn-Mnde Equiument nnd P•·oducts - Sense of Congl'css It is the sense of the Congress that, to the greatest extent practicable, all equipment and products purchased with funds made available under this award should be Americnn-nmde. This clause shall be applicable equally to subcontractors as a now down provision of the Cooperative Agreement. 4. P1·ess Rl!lenscs The DOE policy and procedure on planned press releases or othe•· public statements requires that nil press releases be reviewed and approved by DOE J>rior to issuance. Therefore, Contractor/Supplier shall notify SCS at least thirty (30} days prior to issuance of any press releases or public statements related to this Agreement, and SCS will submit to the DOE Contracting Officer a draft copy of any planned press releases related to work performed under this Agreement. After the Contracting Officer has obtained the neeessaty reviews and clearances, the results of such reviews will be provided to SCS and SCS will provide Contractor/Supplier with infonnation as to whether the proposed press release is npprop1·iate and can be released. 5. Publication of Rcsults/Aclmowledgment Statement To the extent any publications und reports are prepa•·ed under this Agreement by Contractor/Supplier, such publications and reJ)Orts must contnin following acknowledgment statement: "This [dcscl'ibc material] was prepared with the support of the U.S. Depa11ment of Energy, under Award No. DE-FC26-06NT42391. However, any opinions, findings, conclusions, Ol' recommendations expressed herein nrc those of the author(s) nnd do not necessarily renee! I he views of the DOE." 6. Envil·onmentnl. Snfcty & Hcnlth Contractor/Supplier must comply with applicable fedeml, state, and local environmental, safety nnd health laws and regulations for work performed under this award. 7. Hnznrdous Wnstc Manifests and Lnbels Conti'Rctor/Supplier shall not identify, on waste manifests or container labels or otherwise, the DOE or the National Energy Technology Lab (NETL) ns the owner or generator of hazardous wastes without written permission, signed by either the NETL Director or both the NETL Contracting Officer and the NETL Environment, Safety & Health Division Director. 8. Tc•·minntion The Cooperative Agreement, which is the prime contract for the project for which this procurement is made, may be terminated in accordance with I0 C.F.R. § 600.351. In the event of a termination of the Cooperative Agreement in accordance with 10 C.F.R. § 600.351, SCS will be entitled to terminate the agreement for this procurement without fault or penalty. 2 of4 SoCo FOIA Response 001900 9. Records Uctcntion and Access n. Pct'iod of Retention. Contractor/Supplier shall retain nil financinlnnd performance records, supp011ing documents, statistical records, and other records which are required to be retained by the terms of the Cooperative Agreement, and any other records that Contractor/Supplier reasonably considers to be pertinent to this lower tier procurement under the Cooperative Agreement. The period of required retention shall be from the date each such record is created or received by Contractor/Supplier until three (3) years after the latest of the following dates: (i) the expiration date of the Cooperative Agreement, which date is projected to be approximately Mny I, 20 18; (ii) the date Contractor/Supplier's final expenditure rep01t is submitted to SCS and received by DOE; or (iii) if the Cooperative Agreement is terminated in its entirety, the effective date of the termination. If any claim, litigation, negotiation, investigation, audit, or othe•· action involving the records starts before the expiration of the foregoing three-year retention period, Contractor/Supplier shall retain the records until such action is completed and all related issues are resolved, or until the end of the three-year retention period, whichever is later. b. Access to Rec01·ds. Subject to any legitimate claims of Attorney/Client Privilege ns detcnnincd by a court of competent jurisdiction, DOE and the Comptroller General of the United States, or any of their authorized representatives, shall have the right of access to any books, documents, papers, or othe•· records (including those on electronic media) which are pertinent to this lower tier procurement under the Cooperative Agreement. The purpose of such access is limited to the mnking of audits, examinations, excerpts, and transcripts. The 1ight of access described in this pamgraJ>h shall last as long ns Contractor/Sul>plie•· retains records that nre pertinent to this lower tier procurement under the Cooperutive Agreement. 10. Sevcmbility If n court of competent jurisdiction or the DOE Financial Assistance Appeals Board determines that any part of the Cooperative Agreement is invalid, void, unenforceable, o•· inconsistent with any applicable Federal statute or regulation, such part shall be deemed to have been amended or deleted to conform to such determination. II. Egunl Employment Onpot·tunity Contraclor/Supplic•· ngrees to comply with E.O. 11246, "Equal Employment Opportunity," as amended by E.O. 11375, "Amending Executive Order 11246 Relating to Equal Employment Opportunity," and as supplemented by regulations at 41 CFR Jlal1 60, "Office of Federal Contract Compliance Programs, Equal Employment Opportunity, Depa11ment of Labor." 12. Copelnnd 11 Anti-Kiclplier agrees that it is not listed on the non-procurement portion of the General Services Administration's List of pm1ies Excluded fi·mn Federal Procurement or Non-procurement Progmms in accordance with E.G.'s 12549 and 12689, "Debarment and Suspension." This list contains the names of pnt1ies debarred, suspended, or otherwise excluded by agencies, and contmctors declared ineligible under statutory or regulatory authm·ity other than E.O. 12549. Contractors with awards that exceed the small purchase threshold shall provide the required certification regarding its exclusion status and thnt of its principals. 4 of 4 SoCo FOIA Response 001902 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Brittley Robbins Monday, April 26, 2010 9:20 AM Madden, Diane; Johnson, Raymond Fwd: Flowdown Provisions in (b) (4) KemperCounty TEXT.htm; (b) (4) Flowdown Provisions - Comments to DOE (4-22-lO).doc; Cooperative Agreement FIN/\L.doc Depending on everyone's availability, I'll try to schedule a conference call today to discuss these questions with Southern. (b) (4) Regarding first comment on the EHS flowdown, Southern has followed the requirement of the CA (see attached CA page 12 - clauses 2.27 and 2.29) by Including the added sentence about (b) (4) informing SCS of required permits and licenses. I'm not sure how flexible we are on relaxing this requirement but we can discuss Internally before talking with Southern. Regarding the second comment, the requirement for Access to Records comes straight out of 10 CFR 600.21. I don't see how we can limit the scope of the access since such limitation would deviate from the intent of the CFR. let me know your thoughts. Thanks, Brittley >>> "Buettner, Jennifer M." 4/23/2010 10:04 AM >>> Brittley, We are very close to finalizing the (b) (4) with (b) (4) One of the remaining open items is the flowdown provisions. There are 2 provisions that are still causlng concern for (b) (4) . Those 2 provisions are evident in the attached document by my marginal comments, which comments explain what the concerns are. Do you have (6) time to assemble your team and talk with (b) (4), (b)and me about this next week? Monday and Thursday are best because I have Kemper County meetings on Tuesday and Wednesday. If you can make Monday happen, that'd be great- the parties are trying to come to closure on all Issues by May 1. Thank you!!! Jennifer Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205·257·6730 (office) (b) (6) (mobile) 205-257-6381 (fax) jenmorrl@southernco.com This e·mail and any of Its attachments may contain non-public and/or proprietary Information of Southern Company and/or Its affiliates that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e-mail Is Intended solely for the use of the Individual or entity for which It Is intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or Its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 001903 t:XIIIIIITG TO TilE AGREEiiiEl\T DETWEEN OWNER ,\NO _ _ __ FI.OWDOWN I•ROVISIONS FROill COOrERATIVF.AGREE:\IEI\'1' m:·n\'t:t;.-.: llOt: ANil SOliTIIt:UN CO,\II'M~\' SEil\'ICt:S,INC. Supplier und..'!Sinltdi 1/~11 llu: ~~As••'-'fl''''l is a subcontn~~:l und..T Cooperative A~'lnenl Ntunlli.T DE-FC26~1'12391 \lc:l\\\\.'11 Southern Company s,ni~.lnc. (SCS) tvld lite IL'i. D.:pnrbtll.'ltl of Enc:r~y (OOE), and lltcn:fon: cctl.1i11 ronlr.lct provisions fmmlltc Coopemli\'C ~~~11Cnl lltiiSI be no\\\'d domt lo and included ns p;lll of lhis ~~l:l!mlli1ll- IJnscd 011 ll~e tq~~esc:ttL11ions mode by Supplier below, lit<: flowdomt provisions from the COOJtc:rnti\'C '-'•'ltlllilL'tAM~m..,n an: limilcd to !hose contnit:cd in litis allltciUII(lll 10 lite AC1\'C111C1ll. In p;ll1icn)ar, Supplier's rcprcscntnlions provide n basis for not requiring lhc Supplier to romJtly \\idtlhc n.-gulntions pcrtnilting lo l'cdcml Cost l'rinciplcs (nUowabilit)' Md .nllocnMity) llmt an: locnlcd nt Se~:tion J I oflire Fcdcrnl flcqnisilion R•'llulntions rutd to dtc Fcdcrnl Cosl Acrounting Slruldank Supplirr n!p~tts thnt the goods nnd'or SCT\ices fumishcd under diC !?.lfl~~J.!1!~11t<'!ll an: goods rutdlor SCI'\ices 11~11 n~ ofl'cn:d for s:~le in Supplier's n:gular cour.>e of business. II 1iu'II11.T n.~nl~ ll~1t lhc tlrincillill pmposcofdtis O>n!nl~ll\gr.:t"mcnt is not dtc development ofintc:llcctual pm~Mo'll)',tltc tt.:vdo)mll.,ll of new produc! line;, or 11:S4.-vch rvtd development ncti\ilics. I. Lohb1ing Rrslrlctions Ry <'lllcring into ate: Al,llttmcnt, Supplier nJ!II.-cs dtot none oftllC monies it rm:i1'1:! rcnlk.T IIJC Agm:mcnlll'm be made nmilabk for rvty n<:thityortlte 11Ublicali011 ordistnbution ortilrrntun: thnl in rut)' ll':ty talds to promote public suJlllOit or "'lfXISitionto any lcgi~lati\-c llRlJIOS:II onl\1tlch Cougn::><;ionnl nc;tiott i> not romplctc. 11tis restriction is in nddition to dtosc pn:s.:rilx-d elsewhere in sL11UIC rurd n:gularion. 2. Noller llrenrdlng Lol!b\ing .\riM !Is Supplirr sl~1ll, to dtc lroatt applicable to Otis tllr.hltA!!J\~llcnt f(lr Jobb}ing IVtd ~lal<'d nctivitic:;. Monies 1~1id to Supplier wtd..T lite ~tlltlaAsr•-..,n,,n mny be used 10 describe Ntd promOic lite wtdnstllnding ofsci~:~tlific rutd techniroii1SpC'C'IS ofspecific c:tlelllY l«hnologics. but not to rncourngc or support polititnl nctivitics such l\> lltc l'Ollc.-ction nud dls.s•:ntination ofinfonnnlion n:J.1t..-d to potrntinl, plruurcd or p.'nding k:gislation. J. Nnllcr Rrgnrtllng the l'urchnsc orAmrrlcan-~ lndt E11ulpntrn1 null Produtts- Srnsr or Congn:ss It is II!C SC115Cofllt<: Congr-ess t1~11,1o lhc gJ\'lltc::;t C.\t\'111 pr.!Ciicablc, nil cquif1111C.,ll nnd pruduc!s Jliii'CI~15Cd witlt liutds n~1de ovnilablc turdcr'tltis m1mlshould be flmcriC111-madc. 1l1is clause shnll be aJIItlicnblecqunlly to subcuntmclllrs ns n flow do\\lt pM•ision ofdtc Coopc:rnli\-c t\I!J'XIt!CIIl 4. I'm' llrlcnm SoCo FOIA Response 001904 'lltc IJOE polic)' and procedure on p!rutrk.'d pn:ioS n:IL-ascs or oOICT public statcm.,tts n:qnires Otal all press n:lros.:s h.: n:'·icl\\'d and approwd hy DOE priar to i.ISttttncc. llk:n:rim:, SupplM:r shall ootil)· SCS nt lc:tSt Otiny (JO) d.1)s prior to i551tiVICl: of nny press n:!CISCS or public s~'llcmcniS ~~:talcd to this ~llllr.KI.'\elwn~nt. nnd SCS \\1llsubmillo UIC OOE Contracting Officer o drnft copy ofruty plarutcd press n:lmscs n:late~lto work pcrfixm•'d tmtd..T Uti.~ Agr~.'l.'ntcnt Aft,y Otc Coulntcting Onic.:r ha; clltnincd dJC ·~· n:l'iCII~ nnd ciCMU~CCS, d1c n:sulLS ofsnth rtl'icws 11ill h.: (liOI'idcd to SCS nnd SCS 11ill pro,·idc Supplier 11idt infonnntion liS to 11 hc1hcr Ute proj!OS(d J!O:$S retcruc is npproprinte Md CIUI be n:tcasal. S. l'uhlicntitln or Rl'Sulls I At~IIO\\'Irdgmrnl Shllrmrnl ~1•'111 ruty pnbli•-ations Md n.'JUIS nn: (11\'lliV\'d und•T dtis ~llliCI.~'I.'III•,II publicatiOJL~ and I\1XKts must conlnin follolling arkiKlwlcdsntettl stat•'lllrnl. To dtc b)' Suppti<.T, sudt "'lltis (drsrrlbr mntrrinl) ''"-~ pii.')Xlll.'d 11ith Otc support oflllc U.S. O.:p.vtmmt ofEn•"B)', Wld<:r Awanl No. DF.·FC26-06NT42J91. Howc1~. nny opinions, liuding.s, rouciiiSions, or I\WIIIIIIettlL11Klns c~prcslallk.'ldn 1111: dJOSC of Ute nudJOI(s) iVtd do notu=il)• n:Rcct d~e 1·icws ofdtc OOE." Su(llllicr 1111151 comply 11idt npptirablc fcdrral, stall:, nnd !ocnl rmiromncnllll, sotl:l)' nnd health la11s nnd n:gul~lions applicable to il for its work pcrfonncd under this Ill\ani. '11! I iuliMm Sl'S of_ .... nil rn1immnental. h<.':!ld1 nnd S.1~l)~J~nnil:< rn11l licmS§ r.:guired lor l>ut~lli~r I<' J>ertilmt 11ort tunfrr Ut~ ~ 7. lln1Jirdous Wnstr 1\lnnlfrsts nmf Lnbt'ls Supplier shall not idcnti~·. on 1\astc manifests or routnincr labels oroiiiCTIIise, dtc IX>R or Ote National F.nrrgy Tcchnolog)'IJib (NETt.) 115 dtc omtcror g~1mllorofh.171VIllus \\;ISles 11itl10ut wrillrn permission, signC\1 by cidtcr diC NEll Di~~:rtor or bod atlac Nl!ll. ConlnJCting Officc.T Md d1e: Nl!ll. Enl'illlll!liCIII, Safety & I frnl01 Division Dim:tor. 8. Trrmlnn!lon OnmenlldUrrbl)z (b) (4)"J'Sib.ll .-..pl)ioa "~h oh;o rcq11Utmcr.t it imponib!tbC\"~K itl-.nlhouu.nd.•afpo-mil•anJ li:tMnfor &lloftht t".clliliH"-'htrc\ktu.-t.in(pJ.IUuill be .... anurachutJ aAd uwmhlcd (moU oh.hkh nt US loc.lllions) We :tia.cu" 1\ith (b) (4) tht pouibility ol'ch.aaainJihis wlllcnct 11 folio•• Ja addltloa, Sut•11lln must lalorm SCS ar .,,. nrw tA\Itanmrnla1.1lt.Jht. In• urrl)' •ratronh lbll Suvpfirr aunt ebUIA Ia onht to p•l'form t.otSr.i •• tht Ktmpcr Co&Jnt)' Pro) HI t lfr. Undtrlhisnew l~asc (b) (4) "oa1clactlyntN 1a iftr6.lrmu Jof tt.c D..Ll\: ptrml1•and liC'tnwt 1h.U it kat to Bet inordtrto ptffonn onUtrs.nvic:n ·ntc Coopcrnti1-.: Agrmttc~t~ 11ttich is tl~e prime conlmcl for d1c projl'ct for 11iaicltlhis procumnrnl is anildc, may be h."TTTTinnh:d inn<.wrdancc \\itlt 10 C.F.R. § 600.351. In dac cwnt ofa t<.Tntinndon of lhc Coopcrnlii'C Agr~.-..Tn~ltl in ac..'OI'danrc 11itlt 10 C.F.R. § 600.JSI, OI111CT mll be ~,llitk'tllo Kmliunk: the Agn.-..'llt<.'lll in accord:uJCe\\ilh Anicle 18.3, Tmninalion at Olmcr's Option. 9. ltttords, lttlrnlion, t\crcg mad Dlsdosul'l' l'triod of ltrtrn~on. Supplicr sl~1ll n:tnin all financinl rutd pcrfona~vtce m:ords, Sltpponing docutncnLS. slalisticnl n.wrds, nnd otlter n.wn!s whic:lt nn: n.oquin.'d to be n:lllincd by dte trnns of d!e Coopcr:llii'C Agr\-..'11101~ and lUI)' olh•T n.wn!s Owl SUppli•T n."ruOnabl)' •"'lnsidcts to h.: pertinent 10 dais lo\\~T tier proctan:mcntundcr Ute Coopcrntil-.: i\J!II."CCIICIIL 1ltc period of 1\'qUiml n:ll:ntion shall be from the dak: each such n:cord is rrtatt'll or n't"Cil'rd by Snpphcr nnlil dll\'\: (3) )t"lll'.i nncr lhc latest ofdtc follo\\ing dnlcs (i) dtc t~pimtion d.11coftltcCoopcmti\'C AI!=JIICII~ llitich dnr.: is projrclrd lob:eppru.~imatr:l)' May I. 2018; (ii) dac dale St•ltlli<.y's 1in.1l C.\(k.'llditun: 1\11011 i~ subtniuo:d to SCS nnd n:.-..i•..:d h)• DOE: or (iii) if dtc Coopo:rnli1·c t\J!II.'\.'IItL'III is l•nninat<.'tl in iL~ cntill.'l)',lhc cff,-cth-c dateoftllC trnninnrion. lfruayclnitn,liti@-11ion.ttcgatintiot~ i1tl'cstig.1lian, nudit. or otltcr action inl'olling diC m:ords staJU before dte c: 1111: n:sol\'td, onmlil dac end ofUtc lltn:c-)'rnr rctcnlioo period, 11ltiche~~ is later. SoCo FOIA Response 001905 Met» In !lrrords. Subjrc! to ntt)'lq:itinmtc clnims of Altome)•iCiictM Pri\'ilegc ns dctmninetl by n court of COIIIJlCtetM j1trisdiction, DOli 111<1 Otc ComptroUcr Gcncml of the Uniled S~11cs, or M)' of dteir ntrtltori7cd rcpn:sciiUitii'CScl\lttHV~ni~lni~WttUIWIIHt~ sl~1ll ltni'C the righl of IICt'CSS 10 my books, docun~mts. pll)lCIS, or other m:ord; (including diOSe: on ck.:lrullic nt<.'din) \lhidtlll\: p:rtir.attlo dtis Iowa· tier )WCIU\,n,'llltuKI.:r tl~e COO(Iflllwi~Jrjto\ right of ..... .. """"'"'*"' (jnob2)tAh""""' tb< Ws"'" ofiiiH clute io su.alaht ftom tl'.t Coopt~ .athe ,\p-ftnltrJ. (b) (4) ""'"there to be ncccss dcsaibcd inlltis p.Vltgmph shnll ~151 ns Ions IU Supplil:r r.-uins d~1t nre pcrtinclll to this lo\I'Ct"tier 0 •Putrot<" lo tbl proctmno.~ under l!tcCoop:r.llrrc AUC\.'III•'Ill rocffttl'ltt It to dtlltt tl':b cb:u.e Jlroatthtr. bu1 J1~ thtntlhn uu "''OI'di Nnpouib&t 10. Sf\'tflhilih' lfn roun of,'Oinp:tcntjurisdiction or tl1e DOF. Senior l'rocoo.,ncnt F..~•-.:uti,·c dct,'nnincs th.11 Ill)' (lM oftltc Coopcrnth-c Agn:~"'lt,,lt is ill\':tlid, I'Oid, unetl(on;,':\b~. or UICOIISl\t~nt \\itlt any ~pplkab!~ F•'\1•-rnl Statui~ or n'gulation, SUI.it )1311 ~han be deemed to hai'C bc:c11 MIC11dcd or deleted to ronfonn 10 such dcll:nnination, but tltc s.-unc shall110t oRi.-ct the terms tuld conditions oftl1e (:.'onDJo:~. unless the ««Mr~! nrc forw:l'dcd from tier to tier up to U1e ra:ipient. 16. Ptll:lrmtnl ft•ul Susr~tn•lon C!::.O,'s 12!\.19 1111d 126891 Supplier ngm:s Ulo'l! il iu10t ~sled on the: llOil·fii\XUmncrliJIOition oflbe GCiu:rnl Servia::; Adminislmtion'sl.isl ofp.mic:s E"'cludcd lium fcdc!all'ro..·urcmmtorNon·pnxll!l."tlt~:nt Programs innc:cordru1cc \\itb EO.'s 125.;9 ond 12689. '1:l.:b.lrma~ and Suspmsion." 1l1is list contnilS tiiC lliUIICS of p.'lftie:> dclxlm:d, suspended, or OOICT\\isc c:xcluckd by ngcncic:s.ru1d contrnctors dcciOI\"Cl ineligible llldcrSilllutOI)' or n.-gulaloJ)•nutllDrity oUK'I' tiUU1 £;.0. 12549. Snpplicrshall polVidc tliC Rqtlin:d mtiflClltion n:gnnling iU cxciU!ionstlllus nnd t1~1t of its princip.1ls to 0\\llcr. ; SoCo FOIA Response 001907 From: Sent: To: Cc: Subject: Attachments: "Buettner, Jennifer M." Friday, April 23, 2010 9:05 AM Robbins, Brittley Madden, Diane; Pinkston, Tim E. Flowdown Provisions in (b) (4) -- KemperCounty (b) (4) Flowdown Provisions- Comments to DOE (4-22-lO).doc Brittley, We are very close to finalizing the (b) (4) with (b) (4) . One of the remaining open items is the flowdown provisions. There are 2 provisions that are still causing concern for (b) (4) . Those 2 provisions are evident in the attached document by my marginal comments, which comments explain what the (6) me about this next week? concerns are. Do you have time to assemble your team and talk with (b) (4), (b)and Monday and Thursday are best because I have Kemper County meetings on Tuesday and Wednesday. If you can make Monday happen, that'd be great- the parties are trying to come to closure on all issues by May 1. Thank you!!! Jennifer Jennifer M . Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (office) (mobile) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary information of Southern Company and/or its affiliates that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this email and any attachments. Thank you. (b) (6) SoCo FOIA Response 001908 E.XIIIBITG TOniE AGREEi\IE.'T BEn\ EEN OWNER A."';D _ _ __ FlOWDOWN I'RO\'ISIOi"S FROM COOI'ER.\TI\'E AGREEi\IE:\T BEn\'EEN DOE A.-.DSOtmiER.._ C0;\11',\J"\' SERVICES, INC. Supplier understands lh:ll the ~AJ:JS,m;n! is a subc;on1r.ll;t under Coopcrn!ivc Agn:cmcnt Number OC-FC21Hl6NT42391 between Southc:m Company Scrvia:s,lne (SCS) and the US O..'Jlilltl1lCTlt of Er11.:rgy (DOE), and thc:n:fOII.' a:nrun amtrnct proviSions from lhc Coopcr.:lli1·e Agn.'CRlCilt mus1 be no111:1i do1111 10 nnd mchKk:d as pan of !his "'-~· Based on the rqlR.'SCIIIaiiOI\5 made b) Supplier bc:klll, the llowdo1111 pmvl5tons lium thc Coopcr.rlivc: ~~ an: limited 10 those cootainc:d in !his llllachm:nt 10 the Agn:cmcnt In porocular, Suppi~T·s n:pn:scnlalions provide a basis for not n:quinng lhe Supplier 10 cornpl) 111!11 ~IC n:gul:lliOI\5 pcnalmng to Falcral Cost l'rinciplcs (allowabilil) and allocabilrl)) lhat ore loca!Cd at Section 31 ofthc Fedt.Tal Ac:qursrtron lu:gul3tions anrl 10 lhc Federal Cost Accounting Standards Supplier n:pn:scnts ~1:ll thc goods an!Vor services furnished under thc ~~ arc goods and'or services !hat ore offen:d for sale in Supplier's regular ~c of busiocss. It fwtllCI' n:pn:scnl5 !hal the principal purpose of !his ~ is notlhc df.:vclopmcnt of intellectual prnJIL'fl)', thc d~-vclopmcntof ~-.., product lines, or n:scarch nnd de1·elopmcnt activrtic!s. lobb1ing Reslriclions By en~'ring into lhc A@:llX.'IllCnt, Supplier llllfCC5 ~l:ll none oflhc ntonics ll n.urvcs urxkr the Agreement will be made available for :Ill) activity or thc publication or drstnbutron oflrtcralun: !hal in 1111) 11'3) tends 10 promote public suppon or opposiuon to 1111) lcgisla111c proposal on wl11ch Congn:ssronal actron is not romplctc This restriction rs rn nddruon 10 lhosc pn:scnbed elsewhere rn 51alutc nnd n:gula!ton 2. !'~:otic~ Ra:unling lnhh1·ing Acli1·ilies SuppllCr shall,lO~ICCXk.Tll appliclblcto lhrs ~ rompl)' wilh the provisions of federal law prohibiting the cxp.'llllitun: of monrcs n:ccr1·cd undf.Tihis ~ for lobb} ine nnd n:lak:d activities Monies prud 10 Supplier undcr the ~ 11111) be used to dcscnbe nnd promolt: lhc unders1anding ofscientific 1111d ICChnical asp.'ciS ofsp.-cilic cncrg} lechnologJCS but not to encourngc or suppon political acuvitrcs such as ~IC rollcction md di:t~minalion ofinfontllllion n:la!cd 10 poll:ntial, planned or JIL'fldrng lcgrslatimt J. Nnli~ Rn:~~ nli!!!! !l~t r yrthase ofAmmta11-i\bu:k f.ngjnm~nt and Prod ~~en- Ssn~ of Cnngre.1 nlrllct for tllC pro~'CI lOr whk:h this prtlCUR.TOL"'ll is m:Wc, may be tcrmin:do:d in acmnlnncc with 10 CF R. § 600351. In the event of a tcrminalion oftllC Coopcrauvc Agreement sn acmnlancc with 10 C.F.R § 600JS I, Ol1ncr wsll be entitled to tcrminatc tllC Agm:mcnt in acoordance with Artsclc 18.3. TLTmination Ill O.mcr '~> Option 9. Rrcnnls, Retention, Acre~-~ nnd Disclosure: P~ri!!!l of RrttntioiL Supplier shall n:tnin 1111 finuneial nod performance n:cords, supporttng documents, stalistk:al records, IUld other n:cools which nn: n:quired to bc rclllincd by tllC tams of the Cooperative Agrcct111.'1ll, nne.! any other n:cords chat Supplier r=onably considcr5 to be pertinent to tlus lower tier procuremc:nt Wider the Cooperative Agrwmcnl The period of n:quin:d n:ll:nlion shall be 6um the dale l'l!Cb such record is cn::stl:d or IL'OCivcd by Supphcr unu1 thn:e (3) ycnrs nftcr chc latest oftllC following dW:s (1) the cxpir.lliondntcofchc CooPLTativc Agreerlll,L \\hich date is projL'Cil'dto be approximately May I, 2018, (h) tloe dntc SuppliLT's final cxpcnditun: report is submincd to SCS and n:teivcd by DOE: or (iii) ifchc Coopcrot1vc Agn:cmcntiS tcrminalcd in its cnlircl), chc elfccuve dalc ofthe termination. Ifany claim, litigation, ocgoti:dion, investigatson. audiL or other nction involving the TL'COrds statts bcfon: the c:.~pir.uion of the fon:going thn:e-year retention Pl'flod. Supplier shall n:lllin d1e records oolil such action is completed IUld all n:latcd issues an: resol\·o:d, or ootil chc end of the thn:c-ycar n:tention period, whichcvlT is later SoCo FOIA Response 001910 Arct55 to R«ord~ Subject to an} lcgitim:~tc cl:ums of Attomcy/Chcnt Privilege as determined by 11 coon of Wffi)ICC1.'11t jurisdiction, OOE and the Comptroller Gcner.!l of lhe Unill.'tl StileS, or DR) of their authorizA.'tl rcpn:scnt.-n·~n;••t ""'flle)l.'l!j, shall have lhe right of access to DR) bool.s, documents, p;lllCIS. or other n:alltls (includmg those on electronic nlC(ha) 1\fuch are p:ninent to this lower tier JllllCUICmo:nt Wldcr the Coopcrn~•vc Agrcc:mo:nl Tltc purpose ofsud! access is limiiCd to lhe making or wd1ts, cxnmimuions, C.XCL'l)lts, nnd lr.lnscnpts ~1:!\!1. ~~ilool!l~ ef!llli~l?:tThc right Of access described in this pamgrnph shalllnst as long as Supplier relalns reconls lh:u arc p:ni~'llt 10 0115 lower ucr procorcmcnt undL'J' d1c Cooperative Agrcc:mcnt c:antwJted [JrMZ]: AllhouJh !he t..nauaa• ortlw cb""'" llnillht from lhe Coopenll\'c Aareemenr (b) (4) Mnts there lObe a ~c· to t.hc audn th.lt DOE ml&ht perform Thcu 1t1ona Fefermee 11to delete tlus c:busc ah01ether but Jtold ahem. tha1 'llo'U 1mposs•btc 10. Se\'fruhilin· Ira coon of compck.'llt junsd1ct1011 or the OOE Senior Procun:mcnt Ex~'Clllivc d<:ll.'l'mmcs that an} Jl'll'l or UJC Coop:rallvc Agrcc:mo:nt IS mVlllld, vord. uncn!On:eablc. or inconsist~'lll 1\ith any !lfllllicablc Fedcrnl stllutc or lqlUiitiOII, sud! Jl'll'l shall be dccmcd to have ~'II nmcndcd or dck:tcd to conform to sucl1 dctcnnin:uion. but dlC s:mc shall not affect lhe terms and condiuons ofthe ~"to\gm:m.l unless the ~'f!l9ll is an1\.'lldcd pursuant to Aniclc - -· II. ~ 12. F.gual F.mplo\·mcnt Opportunil\· Our contr.act W1th (b) (4) u a fixed pncc annnd, JO ~,qntJ us to ddinc the rollowtnJ Ln thts c:buse (b) (4) (o)Thc purpoteofthcoud• ond tu) Thc recotds tNt DOE wou,ld h.1vc aaz:ss 10 Supplier ogrccs to comply wilh E 0 11246, ..Equal Einplo)mcnt OpponWJil)'," as nmcndcd byE 0 11375, "Amcndmg E.xccut1w OnJcr 11246Rclalmg to Equal Emplo}mcnt Opponunity," and ns wpplcmcntcd by lqlUI:IIlons :II 41 CFR part 60, ''Office of Federal Conlrnct Compliance Progrnms. Equal Emplo)mcnt Opportumty, ()l:partmcnt oflabor " 13. Cons!Knq ",\nli-1\ickhuck" •\r' !!ll t i_<;.C. § 874 nnd 40 tp,S,C, § 276d Supplier agrees to comply wnh thc Copcl:md "Anfi-Kicl..b:Jcl." Act (18 U S.C § 874), as supplcn-ntcd b) IJ.:partment ofLabor regulations (29 CFR !'art 3, "Contractors and SubcxlnlrnctOrS on Publ1c Budd1ng or Puhhc Wort.. Fmanccd in Whole or in part iJ> Loans or Grants liom the Unill.'tl Sla!J:s" ) The Act pmvJdcs thai each a>ntractor or suh-n:CIJII'.'Ill shall be prohiblled from inducing. by 110)' m:ans. 0111} person employed 1n the consll\lction. completion. or rqmir or public work, to g1vc up any part of lhe compcnsafion to which he JS o~'J'\\'lSC cnuOcd TIIC n:cipicnt shall n:port all suspected or reported violations 10 SCS. Cklln c\lr/ul (-12l1S.C.§740! rum.! nnd thr Fa! 31 U S C. § 1352 Elich SoCo FOIA Response 001911 tier shall also disclose any lobbying \\ith non-Federal funds that lakes place in cooncction with obtaining any Fcd:rnl aw:~nl. Such disclosures arc forwarded lium tier to tier up to the rccipicnl 16. Dchannrnt o.nd Sus~nsion IE.O.'s 12..~9 and 1261191 SUpplier ogn:cs ~lill it is not listed on the non-procWI."ITICI1t ponion of the Gcncrnl Services Administraion's List of p Tuesday, April 27, 2010 9:27 AM Madden, Diane Henderson, Charles W.; Eiland, Joseph D. RE: Cooperative Agreement DE-FC26-06NT42391- Updated CostBreakdown for Phase Illb Kemper County IGCC EPC-Startup Cost Breakdown for Phase Illb 04-26-lO.pdf From: Sent: To: Cc: Subject: Attachments: The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. Diane, Attached is a revised cost estimate. Our project team decided to spread the estimated freight costs to the individual line items instead of including it as a separate line item. The attached report reflects this change. Other than a few minor round off changes to the numbers there should be no other differences. Please call me if you would like to discuss. Tim From: Pinkston, Tim E. Sent: Friday, April 09, 2010 3:57PM To: Diane Madden (Diane.Madden@NETL.DOE.GOV) Cc: Henderson, Charles W. (CWHENDER@southernco.com); Rush, Randall E. (RERUSH@southernco.com); Eiland, Joseph D. (JDEILAND@SOUTHERNCO.COM); Graham, M. Steve (MSGRAHAM@southernco.com); Owen, Steve {SOWEN@southernco.com) Subject: Cooperative Agreement DE-FC26-06NT42391 -Updated Cost Breakdown for Phase lllb The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. Diane, An updated cost breakdown for Phase lllb as required by Article 2.38 of the Cooperative Agreement is attached. The cost update is based on the following: • • completion of FEED for a non-C02 capture case selection o as the combustion turbine supplier (b) (4) 1 SoCo FOIA Response 001913 * * addition of 65% C02 capture and compression change of COD date to May 1, 2014 Please let me know if you have questions or need more information. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) «File: Kemper County IGCC EPC-Startup Cost Breakdown for Phase lllb 04-09-lO.pdf » 2 SoCo FOIA Response 001914 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Quantity n:r Workhours Labor Material Subcontract Total (b) (4) Tho Rocipionl ot Coopofalivo AIIIOOMonl DE-FC26-Wfl423g1 consi tho material ILmishenftdenliat t:Jusinesslntonnalion which is to be wiUlheldlrom disclosure outside tho U.S. Govemment lo tho ootonl ponniftepying. dissemination, "'discloSU'll of My ponion is prohibited. Reponoato F~e Dato Pago 04/26110 04123/10 2 SoCo FOIA Response 001916 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Ttw Roeipent o1 Coopetative Ag~eernent DE·F~T42391 a>nslders lhe material furnished herein to contain confiden~al business information which is lo be withheld from disdosunt ouuide lho U.S . Govemmont to 1111 lldenl permiUod Dy ln. ,,_secret Tl'is doalmerll contains proprietary, c:tJnftdenlial, llldiOr information ollhe ..-o,.;u o1 SO<.C/lam Company 01 ot lhild pat1ios. It is intended lot use only Dy employoos ot 01 authorized c:ontra<1on of subtidilries of Southem Company IJnautiiOrized possession, use. distribution, alpying. dissemination. 01 GoldoSIR ot any ponoon Is ptCI\Ibited. Repon O..ta F~o Oato Pago 04126110 04123/10 J I SoCo FOIA Response 001917 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) The ROoperawo Agteement OE·FC26.()6NU2391 a>nsido,. lllo material turrishod hOtein to <:ontain confidential business nfonnation whicll is to be willlheld from disdosuro outsidotllo US Gcvemmont to the ellent pemllltod Dy law. This docunent oontains proprielaty, confidOnblt, IOdiOt ~ soaet lnfcmgfjoo of the subsidia'ies ol s-em Compony or of thirtl partie1. It Is intended for use only Dy employees of or authoriled contta-. o1 IUD.Oatles ol S..-m Compony. llnluiiiOrizod pollellion, use. doltniUion, copying, dissemonation, or disclosure of ony por1ion Is pnli>Ditod Report Illite FUoDato Poge 04126110 04123110 4 SoCo FOIA Response 001918 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient ol Cooper.~live AgnH!menl DE-FC26-ll6NT42391 considers the material fumished heusiness inlonnaUon which is lobe wiltllelcllmm disdosUil! outside the U.S. Govemmenl 10 the ex1en1 permined by law. Report !)ala File Data Page 04126110 04123110 5 Tl>s doa.menl conlains proprietary, <:anfiying. disseminabon. or disdoouno of any portion is prohibilod. SoCo FOIA Response 001919 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE IUb Key Key Quantity UM Workhours Labor Account I Description Material Subcontract Total (b) (4) The ReciPtnt ol Cooperlllive Agreement DE·FC26-06NT42391 a>nslde,. the matonal fum;$hed hetein to contain con11dential blAine•• infcmlation wl'icllls to be withheld 11om disdos11111 outside the U.S. Govemmtnt to the extenl permetted by law. Report Date File Data Page 0412t!IIO 04123110 8 Ttis doc:unenl a~n-. proprietary,~- ondiOt 118dt seaet inlonnalion ollhe subsidoanes ol Southam Company or or lhinl parties. II is inlended lot uoe only by employees o1 or euthorized a>nlraCIOB ol subsidiaries ol Soulllem Company. Unlutnoriled posoeuion, use, dislrillulion, -ying. disseminaliCJn, ot disdosUill or ony po<1ion Is pn>l>biled. SoCo FOIA Response 001920 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K: Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient of Cooperative Agreement OE·FC26-06NT4123~1 cons.idel1 the material Unished herein to CDltlin canfldenti., buSiness information wtictl is to be withheld lrom disdoS4n outside the U.S Gcvei'T'Inent to the extent ptlmlcte at or authorizenSider> the millerial furnished hereon to """lain """ftdentill buSiness lnfonnation which Is to be withheld 1n>m disclosure outside the U S. Govemmtnt to tho extent petmined ~, law. Report Dote Foe Oato Pogo 114126110 041'23110 9 This ~ contains propnetaty, confidtt'Cial, and/c( v.M SIK%1It inlonnation oflho subsidiaries Dl Southem Cornpan, ar of thinl parties. h Is lnlonded lor use only ~, empoyees of ar autllorizod concradOfS or subsidiarin1aon1 pq>riot..., ~. andlor If- secnt informoliOn Ollho ..-cianes 01 SoUnom Company 01 ollllinf parties. Ills tntondtullon. a>pying. dis..mination, 01 disclOsure ol1ny portion •• prohibiled. Repofl oate File Oate Page CW21!110 IW/23110 11 SoCo FOIA Response 001925 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) The Roopenl o1 Cooperalive ~ OE-FC21H16NT42391 c:cnsidetS the matoriallun'Uhed - t o a>ntain CX1nfilted Report Dale File Dale p- 04126110 04123110 12 SoCo FOIA Response 001926 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:¥ Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient ol Coopetative Agy or ollhitd patties ~is intended lor use any by employees o1 or auhcrized contracun o1 . . . . , _ , ol ~Company. IJnaulllon1td possession, usa, dislritJutiorl._copying. dossOI'Bnation. or disclosure ol any portion is prot-..t SoCo FOIA Response 001927 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key KU' Quantity U Workhours Labor Material Subcontract Total Ac:c:ount I Description (b) (4) The Redpienl o1 Coope<-. ~ DE·FC2f1.0610'42391 c:cnsielet11he material~ hen!into contain CXJnlldenlial business inl""""tion wNc:h ioto be Willtlelcl 11om oliSdO...., outside !he U.S. Govemment to lhe ••tent penfidenlial.--- ReponDate File Oate Page turn5110 (1.4/23110 14 T l i s - conlains JlRIPIIolarY, inlormotion ol the $Ubsicloaries oiSoiAhem Company Of ol thinS patHS. • ;. intended lor use only by~-"' Of uhoriled tonraclors"' St.C>-s ol Sou1hem Company. Unauthorized posoession, use, olisllibution, oopying, olisoerrinalion, 01 doSdO...., ol IW1)' portion is prnlibilentain coofidential business inlonnabon whit:n is to be willfleld from disdosUI1J outside llle U.S. Government to 1118 extent penniHed by law. Report Date F~e Dace Page 04126110 04123110 15 This document contains proprietary, coofidential. andintradorS of subsldilrioo o1 Soulhem ~. U'laulhorutd ponesliorl, use. clistnbubon. copying, disseminatian, or disdosUill of...., portion Is prohibited. SoCo FOIA Response 001930 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key KM Quantity U Workhours labor Material Subcontract Total Account I Description (b) (4) The Rtcipiem of Cooperative Agreement OE·FCI6-06NT 423Q1 !Xll\$idero tne material fumisnOCI nOfeln to cant lin conftdentiat business informauon wr>cn Is to be withlleld from disclosure outside tne U.S. Gowmment to tno e•tent pennined by taw. Ttis........,... contains proprietll)'. c:on1klenliol. end/or- II8Ctllt ln1onnatoon ol tne subsidiaries of swnom Company or of thinl pan;es. n is intended lor use only Dy emjlloyees o1 or authOrized ex>mae!ors of subsidiaries ol Southern Company. UrwoutllorizOpying, chSerl'lnaiiOn, or disdoSUI8 a1 ""f portion is~. SoCo FOIA Response 001932 ' KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:r Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient of Cooperalive Agteement OE·FCpying. disse<~Wlation. or dildosutll ol ony portion is prolbbotecl. Report Dale FdeOato Page 04126110 04123110 19 SoCo FOIA Response 001933 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Account I Description Labor Material Subcontract Total (b) (4) The Recipient of CoclpenoliYe A!l"""""f1l DE-Fc:z6.06NT 423Vt conside,. the material fl.mishod herein to COfltain COf11idontial buSiness information which is to be wiWiekl rrom ClisdoSy rew. Roport Date File Dale Page 04126/10 04123/tO 20 This cloa.rnent contains proprietary, c:onlldenliol, llnCIIcr traM semot information of 11\e subsidtaies of Southern C - y c.- of third parties. Ills Intended for use only by en!j>loyeas ol c.- IIUUlonzod ~of subsicliaties tJf Soutnem Ccmpany. lJnau1horizocl possession, use, ClislriiUion,!Xlpying. dissernnation, or clisdo...., of lilY portion is prohibited. SoCo FOIA Response 001934 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:f Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) The fledpienl cl CoaperaNo " - " " " ' DE·FC26-06NT42391 ~ 1M ma1t r1allumished honoin lo contoin conl\denlial business infonnation wNch is to be wi-ln>m closdoSU11 outside the U 5 . Government 10 the ••toni potmMd by ""'Tl"is dol:umenl contains propriotaly, confidonllat. rdlor- seaet information cl.,.oubsidtaries ciSoi.Chom eomp..y 0' cl thin! parties_his intended 10' use orly by OfT1IIoY"s oiO'IIAI>Orized oonttac101$ o1 SUbsidiories of Sou1hom eomp..y_ unauthalizod possession. use, distribution. a>pying. dissemination• ..-disdoSU11 ol..,.,. pol1ion is protDtod. fltpottDate FileDott Page 04/26110 04123110 21 SoCo FOIA Response 001935 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Koy KM Quantity U Workhours Labor Material Subcontract Total Account I Doscrlptlon (b) (4) ThO Rocipienl ol Coopetalive Agreement OE-FC26-06NT42391 aJRSiderJ ll>e !Nleriallumished - n 10 CC>~Uin conldential buoinns information wHch is lobo Wl1lll\eld from disdosunt OUI>ide ll>e U.S. Government IO lhe e-.t penMted by lllw. Repol1 Dace File Dale Page 04126110 04123110 22 Tlis document conlains proprietary, a>nfidential, -lnlde seao1 inlormalion ol !he subSidiaries of Southem Company or ol!hird panies. 11 is inlerded lot use only by employees or or IUIIOfiled contractots or subsidiaries ol Soutllem Company. Unau!hOfited possession, use, dislribullon. Cpying, doSSemination, 01 clisdosuno of any po<1ion iS prohibited. SoCo FOIA Response 001937 KEMPER COUNTY JGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key KM Quantity U Workhours Labor Account I Description Material Subcontract Total (b) (4) Tho Recipient ol Coapenotivo Agroomenl DE·FC26-06NT42391 ~ lhe matoriallumiSI\ed hon!in 10 anain conAclenlill business inlllieliaties af Sout11em Company. t.Mau1horizod possession, use, dis1ributian. copying, dissemination, or discloSure afony portian Is pftlhl>ilod. A~g: Page 04126110 04/23/10 24 SoCo FOIA Response 001938 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:l Quantlty U Work hours Labor Material Subcontract Total Account I Description (b) (4) TIWI Recipient ol Cocpetalivo Agreement DE·FC26-06NT42391 considers 1\o maleriallumished hef1!in lo c:ancllin IXlllfidplietanttadan ol subsidillies o1 5...-n Company. U1autharilod possession, use. · copying. cltssomination. ot dlsdasunt al eny potlion is prohibited. SoCo FOIA Response 001939 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~ QuanUty u Account/ Description Workhours Labor Material Subcontract Total (b) (4) Tho Rocipienl al~e Agroement DE·FC26-06NT42391 c:onoies It Is intended lor use oriy by employees ol « atAIIOrizld c:onttaaors al sub-sal Southem Company. U.Uihorizld poueuion. uso. dis~. copying. d i s s -. ..- disdoSU111 of ony ponion is prohil>illd ReponDale File Date Pagnlains projlllOI8ry, ~.-- oecre1 information ollhe . . - a s o1 SOIAhem eornp.!y "'of ll1ild pa1tes Mis intended'"' use only by employees ol "'~od COI#8doB o1 ol Soulhem Company. I.Jnaulhoflzod possession, use, distribution, copying, dosseminalien, or disclo,... ol eny poriJOn is prohibdod sub-. ---- - - - 1W26110 04123110 27 I SoCo FOIA Response 001941 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Work hours Labor Material Subcontract Total Account/ Description (b) (4) the Redpienl of Cooperalive ~ OE-F~42391 consideqlllll malerialllnlished heany « ollhinl parlin. His inCended rorusaonly by employees ol ot ...-od IDRJacloB ol ..midiaries ot-.n Company. llnM*lortted possession. uso. dislribulion. a>pring, disseminalion, « ollln)' pot1lon Is prohibilod SoCo FOIA Response 001942 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/Description (b) (4) The Recipient or Coopenltive A-ment DE·FC28-0GNT42391 conslderslhe material flomsntnfielenbal Dusiness ln!onnation wl'ich Is to be Withheld from llisdoso,. outside lhe u .s. Govemmenl to tne "'""" permilled by taw. Repotl Date File Dale Page 04126/tO IWZJIIO 29 Tl'i1 doalmlnl contains proprietary, ~. -.,_secret lnlonnation ol tno subsidiarin o l - CGmpany or ollli'd pal1ies. ~ is Intended lor use only by emplOyees o1 or at.tnortztsidiMos ol SOUilem CGmpany. \k\lulhOrized posseuion, .... lliltributiorl, copying. - · or dosctoSlft ol ony poIain oonfidlnbtl business inlorma!ion wtidl is to De "'111\etdlrom disdoSift outside 1he US. GoYenvnenl ReponDate 04126110 04123110 File Dale to 111e extent perminey law. 30 Pogo This .-.mont contains proprietary, <:onlldential, ond/Ot liMe socn~1inlonnalion of tno sullsidilries of Southern Company or ollhinl partios. Ills lntondensidonllle maltlial fumslled hereinlo <:Ontain conlidenCiaJ busiMSt inl0111111ion wl'idl is to be wiiiYleld from dosdosunt outside lila U.S. Gove,.,.,. IO 11\e e•ltnl pennilled by law. Repor1 Dale FileD•• Page Tlisdocumlnl con1ains prnpriel""f, ~. IIIOi'llr lrBde secnt infonnabOn ollhe ..-aries ol Soo.cnem Company or ollhinl patlles. It islnlencledlor use only by empoyeos ol or 11\Ahori:od CXJntrac:lors of sub- oiSoulllem Company. Unaulllori:od po...sslon. use. dis.-ibulion, copying. dossemonation, or dosdoMR olllf'Y portion is prohiblled. 04126110 041231~~ I - SoCo FOIA Response 001945 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:.v Quantity U Workhours Labor Material Subcontract Total (b) (4) The Rlldpienl of ~Avr-n! DE·FC26-06Nf42391 a>nsiders hmll4nsicleri1M matttlal fUrnished heroin 1o c:on11in Cllltllldential business inlonnllticlnwhidl is1o be wilhheld 11om dosdDSUt11 DU1side1he U.S. Goverrvnenl 101M e.,enl pennolltcl by law. T l ' i s - contains prt>pfiotary, Cllllllcltnial. andlo< , _ secntt inlamaUon ollhe - - · o f SoUhom Company or ol1hiltl patlies. His in1tndtcl lor use onl~ by ""1*>Yees oloriinSidoB lhe material fllmished herein lo cmtain conftdelltial business lnfonnation wl'ith is to be Wllhheld from dildolunt outside tilt U.S. Government to 1110 oxtens pennitted by law. Tlis doa.nenl a>num pRip'illl""f, conftdontal. and/Or trade senlidential business infonnaban which is to be withheld l'rDm ntain a>nlldential business inlannation wtach is to be wiW1ekl 1r1>m disclosure outside the u .s . Govemmenl 10..., extenl penniltonlains proprietary, a>nlldonial, ancl'or- sea.t information allhe ..-anes ol Soothem Company or ollhilll panies. "is inlended lor use only by employees ol or 8Uiholized c:oncradors o1 oublidilries or Soutllem ~y. Una-ed possession. use. distribution, copyifl!l. disseminabon. or disclosure ol any portion Is pn>hiboled. Ropott Date File Dale p- 04126/10 04123110 37 SoCo FOIA Response 001951 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE IUb Key K:/ Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho ReciPenl of~· A_.,..,c De.f'C26-06NT42391 c:ansiden lho material furnished hen!in to a>ntain a>nfiden~ business inlormotion wtic/1 Is to be witN>ekl from disclosure ouWde the U.S. Govemmont co lho eortont potmilled by taw. a>nfidenlil.- - Ttis document contaim praprielll)', seaec inlormotion ollie subsidiaries ol ~~or of hll pariiOS. Mis nendedlor use only by employees o1 or a - e e l ali'GaelorS o1 ol Soul>em ~· Unlulnonlod possession. uso. disllibUiiorl, copying. or dl$dosure ol enr portion is prohitloled. out>-• dis-. RopcnDace File Date Page 04126110 04123110 38 I SoCo FOIA Response 001952 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Account I Description Key K:( Quantity u Workhours Labor Material Subcontract Total (b) (4) The Rodpienl ol Cooperalive Agreement DE-FC26-06NT42391 1o "" 81<1801 permit1ad by taw rnMeriallumisne.t hen!in 10 a>n1an conlicMntial buSineSS inlonnalion which 1110 be wiWletd lrDm disdosure outside 1he U 5 . Govelm1enl Report Date Fl eDeta Page 04/26110 04/23110 39 Tin do1Aian. c:apying. dissenW\ation, or disdosunl of any porlion is p!OilltlOted - - - SoCo FOIA Response 001953 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKOOWN FOR PHASE lllb Key K: Quantity U Workhours Labor Material Subcontract Total Account/Oescrlpllon (b) (4) The Rec;pent o1 Cooperative~ DE.f'C26-06HT42391 CXlnSidefs lhe maloriallumis.hed 1\enoin to cont;On conlldenliol busioess inlonnation wi'Ocll is to be --lr<>m c,;sc~osura outsidolhe U.S. Gowmmenl to lle extent pennittod by ..... ...uar Report Oalo Fie Date Page 04/26/10 04123/10 40 Ttws document contains proprietary, IXJI'l!ldenlial, ttade secnt information ol lhe subsidiaries ol SOmpany or or lhiRI parlies. 11 io intended lor use only by employees ol or author1zed contractors or smsidiarios or Southern Company. Un-.orizod posMssion. use. c,;stnbution. copying, Ms..,.na~on. or dosclost.n or any ponion is prollibited. -- - - SoCo FOIA Response 001954 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Account I Description Labor Material Subcontract Total (b) (4) The Recipient or Cooperative Agqemon4 DE-FC26-06NT423G1 considers lho materiaiiUmishad herein to rontain a>nfidtntiol Mintss lnfonnation wtich is lo be w11hheld lrom cisclo,... outside lho U S Government to the extent petmitted by low. Ttis documenl contains proprieuwy, confidential, .-.c11ot tiMe seaet inlonna!ion ollhe subsidiaries ol So!Anem Company or ollhird parties It is intended lor use only by employees ot or auchOnZad a>ntnlclcn o1 SUbsidiaries ot Southern Company. Unauthonf\dential businesslnfonnalian wllth is Ia be wilhheld from disdO...., autsida lho U.S. Government Ia tho extent penronod by law. Repahobiltd. dis-. SoCo FOIA Response 001956 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Account I Description Key K:( Quantity u Workhours Labor Material Subcontract Total (b) (4) The Rodpenl ol Cooperolntt Agreement DE·fC26-06NT42391 c:onsideB the mattnal fumlslled hetoin to Cllll1ain """"denlial bus111ess 1l1lonnalion wtwch i s to be wiWleld lrDm disdoSURI outside 1he U.S Govemmenl to tne extenl pemilloy lew Trn c10a.men1 aJfUins propnetaty, ~ ~ seaet inlonnallon ollhe subsldoMits oiSWhtm c:omp.,y or ol tlwd patlles. HIs intended for use r>Ny by employees ol or IMhorizog. dtssemonation. Of disdo...., of any portion os prohibited --- - - - ---- Rt 1'0'10.ta f ile Dale 04126110 04123110 Page 43 -- -- SoCo FOIA Response 001957 I KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key KNr Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Roc:ipienl ol Cooperalrte Agreement DE-FC26-00NT42391 a>nsideB h!Nierilllumishad hefWIIO Clllnlain ecnidential bUSiness inlonnation wl>c:h l t to be ...ntl\etd from ditdosure outside the U S. Govelm1ent to ""'adenl permined by ' -· Tl'it doaJment contains p!Opltetary, mnidential, ume soaet information o1 the subsidiartes of Southern Company ..- oltllfll parties. ll is intended lot use only by omploy"s or..- eUChorized c:ontrllclon of subsidiartet ol~em Company. UllaUChorized posHttion, use, doslritMion, a>pying, dossemination, or disclosure or any p..-tion is p!OI\ibiled. ---· - - - - - - Rtp011 Data File Dale Page -- ·-- ~10 114123110 1 44 ·- SoCo FOIA Response 001958 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient of Cooperative Agnement DE·FC26-06NT42391 considers lhe materiallumished herein to contain conlidenUal business infolma~on which Is to be W11hhetd rrom disdas...., outside the U.S. Government to the mont permUed by law. Report Date File Date Page 04126110 04123110 45 This doa.mont contains JliOI)I'ietary, confidential, end/or trade ,....,t informalion of the subsidiaries ol Soulhem C0111!'8"Y or ollhitd parties. Ills intended for use only by employees or or authorized a>ntradors ol subsidiaries ol Southem Comj>any. Unauthorized possession, use, distribution, a>pying, dissemina~on. or clisCIOsUfll or any portion Is prohibited. SoCo FOIA Response 001959 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE IHb Key Key Quantity UM Workhours labor Material Subcontract Total Account I Description (b) (4) Tne Redpienl Dl CoopenoiMI Agrwmont OE·FC26-06HT42J91 alOSidorsii'IO mattrial fllmisnenlllin ~business information wtic:h Is to be wi1ltleld from dosdoSUie Olbidelhe U.S. ~ to 11'10 .,_.,. pemitled by """· R~g: Page Gl/26110 04123110 46 This ciOCument ccntam proprieiOfY, ~.--secret information Dl the ..-aries oiSoiAhem ~or Dl third par1ies. Mls int.-dlor use only by employees ol or aiAhofiled comadon Dl subllichries o1 Southern c:crnp.ny. IJnaulnonzed possesllion. use. clstnbulion, copying, dos!lf!mination, or disclosure ol any portion Is pmhibiled. ------ . -- SoCo FOIA Response 001960 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient or Cooperative AgR!8ment OE-FC21Hl6NT4~391 considers 1he malarial lumished herein l o oonlain cr>n!idential bu$iness informalion which is lo be wi1hheld from disdo...., OIJisjde 1he U.S. Govemmenl 1o me ex1en1 pennined Dy taw. Rej>Otl Date F~e Dale Page 04126110 04123/10 47 n .. doculnenl oonlains proprielaty, oonlldentlal, - ~ seae1 inlonnalion cr lhe suDs;diaries cr Southern c.,._,y or of lhird parties. 11 is inlended for use only by employees of or authenZed ccn1t11ctors or subSidiaries Cl Southem Company. lJnaulhOrized possess;on, use, distnbution, ~ng. dissomination, or disdosuno of any portion is prohibited. - SoCo FOIA Response 001961 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:( Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Redpionl ol Coopefalive Aor-nent DE-FC26-0eNT42391 comideB1h8 rnateriallumishecl llefo;n to conloin conftdenltadOIS of - - · o1 ~Company. ~ed possassion, use. a.stlii>Won. copying, <*ssemination. or disdoSift of.., por1ion is prollibitect. SoCo FOIA Response 001962 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKOOWN FOR PHASE lllb Key K=r QuanUty U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Rtdpienlol Cooperaliye ~ DE.fC26-06NT42391 COil1ie,_ from dildo...., outskle lhe u .s. Gowmmenl to the ox11m pennil1ed by'-· Rtp011Dato Fit Dale Page 04126110 0412JI10 49 This ~conlainS pl1)plielllfY, ~. andiOanY orollllinl panies. ll isinlendedforuse orly by employees of or a..chorized a>n11ae1or1 ol IUbsldiaries ol Soulhem Company. U1tuCIIclliltd possession, use. do1~. 1Xlpying, dissemination. or clisdosure of -.y ponion is prollibited. SoCo FOIA Response 001963 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subconll'illct Total Account I Description (b) (4) The Redpent of Cooperative Agnoemonl OE·FC28-06NT42391 considers tho matorial!umished herein to ccnlain con11dential business information wtichlslo be withheld from disclosure ouuidotho U.S. Govemment lo tho ollltnl petmiaed by law. Report Date F~e Date Page Ttis documonl a>ntains fl'OPrielary, ~. ondiDr trade seaetlnforrnatian ol 1ho ouboidiarles of SOUI>em Company..- ofltunl patlros II is inltndod r..- •so only by employees cl..- authorized cont.adcn of SUbsidillries of Soo1hem Company. llnaublfiled possession. uso. distribution, copying, clossemination. ot diSdo...., of any portion Is protilloted. 0<1126110 0<1123/10 50 I SoCo FOIA Response 001964 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb I Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient oiCGoperaliye~ OE-FC26-06111'42391 a>nsiclef1 the material fumished h8nin to c:antlincontldential business~- is to 10.,. extenl permilted by IN. be,.._ lrom disdas~n outside the U.S. Gowmment Repatt Oato File Date P090 This daa.menl contains J)tDprieWy, mnfidential, ~ seaet inlannacion of the r.ui>Sidilllies of Sauthem Company or of tninl patties. It is intended Ia< use only by OmplayHS of ar authonzed contra-. of subsidiaries of Sau1hem Company. Unautharizsd possession, use, distnbution, copying, dissemination, or di1dasura of any panian Is pmllibiled. 04126110 04123110 51 I SoCo FOIA Response 001965 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:¥ Quantity U Workhoura Labor Material Subcontract Total Account I Description (b) (4) Tho Ror«ratlotS of subsidiaries of Soutllem Company. Unaulhotized possession. use, doSinllution, a>pyillg, diSieminalion, ot disdo.... of lWIY portion Is pn>nilliled. SoCo FOIA Response 001966 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~ Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) ThO Recipient ol Cooperative A_...m DE·FC26-06NT42391 a>nsidtnlht material fumishOd hen!in lo conlain conlld«nlains propriolary, COI1IidorWI, . -. . - semt1 information ol lht - - • ol Souhem Company or ollhin:l patllos. n is inlonclodlor use cny by emplOyees ol or et.thorizod a>r1lladorl 01 sub-sol SouMlem Compjlny. Unaulllon%011 possouion. use. dislril>ullon, copying, dossominalion. or disdosure olll'rf ponion is prohibilod SoCo FOIA Response 001967 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:{ Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho llocipilnloiCoopen!liYeAII'"fl*'l OE-FC2fl.a;NT42391 c:onsldets lie material furnished hereiniO arotain c:onliclenbal buSiness inlorrnalicnwl'iell is 10 bewitiNid from disdoSW&OUisido l1e U.S. Government ta lho o"**t pennilled by law. Report 0a1e FlhtOale Page 04126/10 04123110 54 Ttis CIOQJment mntam proprillary, ccnlldential, tr.to seaet infannotion of lho subsinfidontialbusinoss inlomultion wtich islo be Wllltleld""'" dosdoln1ains popriolary, ~• ..--secret RoponDIIo File Dale Poge !IU26/10 04123110 55 inlormalion oiN 5Ubsidoanes ol Sot.Chom Company or ollhiR1 panoes. k is inlended lor use only by employees 01 or aUihorilotl oonlracloro 01 sub-• OISoulhom Company. lJnauiiOrtzllntalnc:anfidentialt>usiness infofmalion wtichls tobewitmeld from disclosure outsidelhe U.S. Gmac10n c1 owsidlllrios cl - . n ~y Unllutnort!ed possesSIOn, use, dls~copyong. dissemination. ar cisdoS11f9~ tw1y poriiOn is poollibited. -·---- -- 041'26110 04/23/10 57 - SoCo FOIA Response 001971 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Malerial Subcontract Total Account I Description (b) (4) The ll.Opionl of Cooperative A9reement DE·FC28-06NU2391 c:onsidenllle mallfilllumished herein lo alnlain a>nfidenlial business inlclmalion which lsi<> be w.tltlald from disdosunt oulside lhe U.S. Government Ia lhe eatenl ponnined by law. lleportOale File Dale Page 04126/10 04123/10 58 This documenl conlains PfOIWietlfY, conlidonlial, and/or 1.- secret inlonnalion of tne subSidiaries Of SOUihom Company or of third parli.._ II is intended lor use only by employees of or IMAAOrizoct conlllldon of subsidiaries ol Soulhem Company. Unaulhonzed possession, use, dislribulion. copying. CkSs8111itlatJon, or CkSdo....., oiMy portion is prohibilad. SoCo FOIA Response 001972 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:f Quantity U Workhours Account I Description Labor Material Subcontract Total (b) (4) The Rtcipienl ol Coopetative Agteement OE·FC26-06NT42J91 aJRSidenlllo rna1et1a1 tumishodhen!itl to ccntain CXJnfidential buSiness information wllcnls to be witlt>eldlrom disclosw1! outside llo U.S. Govemmen1 to ... · - .,..,.mtod by law. RIPOI1 Dale File Dale D4128110 04123/tO Page 59 Ttis doQ.ment aJntains pi'Oflfielaly, confidentral, and/or 1/ado soct11t inlonnaUon or lhe subsidiMies or Southern Company ot or thin! parties. II is intonded ro< use only by employees ol ot aulhorizod ton11Kto, o< disclollnl of any po<1ian Is prmotod. SoCo FOIA Response 001973 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho Rocipienl o1 ~· Ag at - SoCo FOIA Response 001974 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lab Key Key Quantity UM Workhours Labor Material Subcontract Total Account/ Description (b) (4) The Roopenl of CoopeJees ol or a - e d conlradors ol subs4diaries ol Soulhem C'10 04123110 63 Ttas c~oc:une.- conlains proprielaty, ....-ntiol. ondlor .,._ secro1 inlormaliOn ot the subsidiaries Ill 5oulhem Company a- oflhinl parties. Ills inlendod !of use only by employee• of a- MAhorlted <:rJnlnocloB of of Soulhem ~- ~eel posSHuan, use. ells--.. cq>ying, dissemination, Of ilod. subs-• SoCo FOIA Response 001977 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:¥ Quantity U Workhours Labor Material Subcontract Total AecountiDescnpt~n (b) (4) Tte Rodpent o1 Cooperalivo " - " ' OE-FC26-06NT42391 consideD 1110 malerial fumiSI\ed nerein 10 cmtain prietary, ton!iclential, orO'of- secret information of tna subsidieries of SOhibotad. - - . --- --- - --- --- - - - SoCo FOIA Response 001980 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontrac:t Total Ac:c:ount I Desc:rlptlon (b) (4) The Recipient of Coopenolive AgaJmenl a>nlains proplie1al'f, conftderllial. and/or~ sectel inlcnnalion Ollho subsidiaios 01 Soutnom Company or or third ponies. n Is inttneHIsidilllos 01 Southern Company. Unaulhoftrecl possession. use. dislriboJiion, copying, C ) s s -. or cbdosura of any pon.on is pn>tlibilod. SoCo FOIA Response 001981 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb I Key K:f Quantity u Account/Description Workhours Labor Material Subcontract Total (b) (4) The RodpienloiCooperaltveAgteement DE·FC26-06NT42391 considetS the rru~larialfumished herein 10 !Xlntlin a>nficlenljal business inlonnationwtich Is to be wi1ltleldlmm disdo....,OUllide the U.S. Government to the extent pennittecl Dy law. .-s File Dale 04126/10 04123110 Page 68 Repor4tadotS o1 sublidiarin ol Soulhem Company. l.klaUihorized posseuion. use, · a>pying, dissemination, ot disdosunl oiWly poRion Is PfOI>DIIed. SoCo FOIA Response 001982 I KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:( Quantity u Workhours labor Material Subcontract Total Account/Description (b) (4) The Redpienl ot CcopefiiNe A_.,..ne OE -F~42391 considers the malorial..,..shed- to contoin confidential business information wt>ch is to be to the ,.,.,. pennitled by tow. IJOm diselo...., outside !he U.S Go-..-nt RepoemfTutnl IO ll1e extent pemined by'-· -·of Tl'is c1ocurntn1 <:on1a01s proprielllfY, ~. -lr.lda secrelinlormat.ion olllle - · o f SoulhemCompany or oltllird pallies. ll ls ittendtd !or use orty by employees ol or IIIAhariztd cnntrac1ors of Soulnem Compony. ~td possess;on, USO, ells.-. CDp)'ing, CIIUamina1Jon, Of disdoSIR ol_,y ponjon is pn>hbttd. Repor1 Data File Date Page =::gl 10 I SoCo FOIA Response 001984 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Work hours Labor Material Subcontract Total Account/ Description (b) (4) The Redpient o1 Cooperative Agreement DE·FC2&06NT42391 oonsidnfidential, and/or trade seaet intannatian of the sul>sidiaries of Saunem Company or of third patties II is intended 101 use only by empla,ees or or authorized contradOR of subsidiaries Ill Soulllem Company. UnaulllOfiZed possession. use, distribution, copying, dissemination. or disdaSIIll of pof1ian is prohitlited. an, SoCo FOIA Response 001985 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Account I Description Material Subcontract Total (b) (4) (b) (4) Grand Total (b) (4) The Roc;pent o1 Coopefalive Agreemenl OE-FC26-0GNT42391 considers the material fl.lnished - t o contain a>nfldenliall>usiness infonnation wlich is to be Wltltleld ll'tlm diSClosure ou1side the US Govemmen1 10 the O.denl penniled by law. -trade 1,955,637,795 Report Date 04126110 File Date ~10 Poge 72 Thio em Company or ollllinl palties. It is irdenclen1rae1011 of oubsidiarios o1 Sou1hom Company Unau1horized possassion. use, distnbution, copying, dissemination, or disdosunt of ftiY portion is prohit>itecl SoCo FOIA Response 001986 Dunlap. Ann C. From: Sent: To: Cc: Subject: Attachments: "Pinkston, Tim E." Friday, May 28, 2010 9:44 AM Stiegel, Gary Madden, Diane FW: Info for DOE.xlsx Info for DOE.xlsx The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. Gary, The COE information that you requested is attached. The generic lGCC referenced in the spreadsheet is a TRIG(tm) based system. The C02 capture case includes 75% C02 capture. C02 compression is included in the costs, but pipeline and sequestration costs are not included. Also, included in the spreadsheet is a COE analysis for the Kemper plant and a natural gas combined cycle alternative. Please call me if you have questions. Tim Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) ·, From: Brazzell, F. Sherrell Sent: Thursday, May 27,2010 4:21PM To: Pinkston, Tim E. Subject: Info for DOE.xlsx CONFIDENTIALITY NOTICE This e-mail is intended for the sole use of the individual(s) to whom it is addressed, and may contain information that is privileged, confidential and exempt from disclosure under applicable SoCo FOIA Response 001987 law. You are hereby notified that any dissemination, duplication, or distribution of this transmission by someone other than the intended addressee or its designated agent is strictly prohibited. If you receive this e-mail in error, please notify me immediately by replying to this email. =================================================================== ----------- Attached the information we discussed. I did confirm that the IGCC is the TRIG Air-Blown design and that the capture percentage is that assumed in the (b) (4) 2 SoCo FOIA Response 001988 The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnisl Alternative 1: Comparison based on Generic IGCC Fueled by PRB Coal In-service 2016 COE (Levelized cents/KWh beginning 2016) 0 $/Ton IGCC IGCCw/CCS Combined Cycle 25 $/Ton (b) (4) Note: Values shown are midpoints of ranges from SCS Studies. Alternative 2: Comparison based on Kemper IGCC Fueled by Lignite In-service May, 2014 COE (Levelized cents/KWh beginning 2014) 0 $/Ton Kemper w/o Incentives Kemper w/lncentives Combined Cycle 20 $/Ton (b) (4) SoCo FOIA Response 001989 1ed herein to contain confi Friday, June 25, 2010 10:51 AM Robbins, Brittley Henderson, Charles W.; Madden, Diane; Stolzenberg, Merle RE: 42391 - budget increase TEXT.htm; Budget questions - response.docx Brittley, Our response to your questions is attached. Please let us know if you have further questions or need clarification. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Off1ce 205-992-5042 Cell(b) (6) From: Brittley Robbins [mailto:Brlttley.Robblns@NETL.DOE.GOV] Sent: Thursday, June 17, 2010 3:51 PM To: Pinkston, Tim E. Cc: Diane Madden; Merle Stolzenberg Subject: 42391 - budget Increase HI Tim, I have some questions on the cost proposal for the Construction Phase of the Kemper County Project. Please see attached. As an FYI - Merle Stolzenberg has been assigned as the NETL Cost/Price Analyst on the Project. Please respond to the questions as soon as you can and make sure to copy Merle on the response. Thanks, Brlttley Brlttley Robbins Contract Specialist, DOE-NETL Acquisition and Assistance Division (412) 386-5430 SoCo FOIA Response 001992 Southern Company Services DE-FC26-06NT42391 Questions regarding budget for Phase Illb (Construction): Question 1: In general, DOE needs a narrative discussion of the cost proposal that indicates how the cost estimate was developed. A description of how the cost estimate was developed is attached. Question 2: Is the $1,955,637,795 in Phase lib costs considered "equipment" and "contractual" m· are all costs under the "contractual" category? Reference the SF 424A. Ucsponsc: The costs fm· Phase Illb arc equipment, materials and contracts. All of the costs arc included in the contractual category because the costs will be incua·red at Mississippi Powc1' Company which lil < DHWARREN@southernco.com> Monday, June 28, 2010 9:42 AM Madden, Diane; Meling', 'Jeff; Detwiler, Ralph; Hargis, Richard Baldwin, Bryan; Toth, Brian D.; Hobson, Chris M .; Berry, Charles Rick (MPC); (b) (4), (b) (6) (4), (b) (6) Templeton, John D.; Rush, Randall E.; McMillan, Scott; Pinkston, Tim E.; Herrin, Danny {SCSB) KCIP: Sierra Club's intent to challenge NEPA ROD TEXT.htm See highlighted text: Sierra Club's Louis Miller indicates they intend to challenge the DOE ROD, citing the Markowsky letter. The Energy Daily M onday, Jun e 18, 2010 Sierra Club Challenges Mississippi Clean Coal Plant Backed By Chu BY CHRIS HOLLY Taking aim at one of Energy Secretary Steven Chu's pet clean coal projects, the Sierra Club has filed a lawsuit challenging a deci!iion by Mississippi regulators that allows Mississippi Power Co. to build a 582 megawatt gasified coal plant in the state, saying the commission exceeded its authority and that its decision ignored evidence indicating there were cheaper alternatives to the estimated $2.88 billion plant. In a June 17 appeal before the Chancery Court of Harrison County, Miss., the Sierra Club said the Mississippi Public Service Commission's (MPSC) approval of Mississippi Power's integrated gasification combined cycle (IGCC) power plant in Kemper County was "arbitrary, capricious, beyond legal authority and unsupported by substantial evidence." The Sierra Club also has filed separate administrative challenges against air and water quality permits issued by the state for the Kemper plant. The Sierra Club actions are not surprising as the environmental group routinely opposes new coal plants as harmful to the environment . However, the IGCC technology has been supported by some environmentalists as much cleaner than conventional coal plants and well-suited for significant carbon capture-a key point cited by Chu in supporting such projects. The Sierra Club's challenge to the Mississippi plant is also unusual in that it leans heavily on cost arguments that are not typically the mainstay of its legal actions against coal plants. The cost of the plant has been central to MPSC decision-making on the project. The commission in April rejected the utility's proposal to allow cost recovery of up to 33 percent above a base cost cap of $2.4 billion. However, the commission offered to approve the plant if M ississippi Power agreed t o limit cost recovery to $2.4 billion. After receiving additional testimony from the utility and other stakeholders, the commission on May 29 voted 2-1 to allow recovery of up to 20 percent of costs above the $2.4 billion base-for a total allowable cost recovery of $2.88 billion- and to allow Mississippi Power to begin recovering construction work in SoCo FOIA Response 001997 progress costs beginning in 2012 and extending through 2014. The plant will be equipped with proprietary TRIG carbon capture technology developed jointly by Mississippi Power parent Southern Co., Kellogg Brown & Root and the Energy Department, and the utility plans to pipe the captured C02 to nearby oil fields for enhanced oil recovery. The plant will burn lignite-a low-rank coal-from an adjacent coal mine. Chu took the unusual step of lobbying for the plant, saying in a May 19 Jetter to the commission that the Kemper plant "is of national importance because it provides a viable option for using our abundant coal resources in a costeffective and clean manner and for reducing power plant emissions." Chu also endorsed the TRIG carbon-capture technology, saying "the department believes that it is ready for commercial demonstration." Chu also noted in the letter that DOE had set aside $270 million in Clean Coal Power Initiative funding for the project, has certified the project to the Internal Revenue Service for $412 million in investment tax credits and is considering the project as a candidate for a federal loan guarantee. "As you know, the commission's decision on the Kemper County project will impact Mississippi Power Co.'s credit rating and its ability to obtain capital at favorable rates, "Chu said. "Such corporate f inancial conditions are important considerations in the department' s award of loan guarantees.'' In its lawsuit, however, the Sierra Club argued that the IGCC plant promises to be a costly boondoggle that will saddle the utility's ratepayers with exorbitant electricity costs for decades. "When Mississippi Power originally conceived the plan to build the Kemper plant, it believed the cost would be $1.1 billion," the suit states. "When Mississippi Power applied for a certificate for the Kemper County IGCC plant in 2009, it stated that the cost of the plant would be approximately $2.5 billion. In itself this estimate was close to twice the value of the generating facilities owned by Mississippi Power, and would make the Kemper plant by far the most expensive generating facility ever proposed in Mississippi, or just about anywhere else for that matter. However, less than a year later, the cost ballooned again to $2.7 billion.'' The Sierra Club, which had asked the commission to approve the plant only if it also imposed a hard cost cap of $2.4 billion, noted that evidence submitted during the commission proceeding indicated that with a 20 percent cost overrun the Kemper project would be more expensive than if Mississippi Power built a natural gas-fired power plant or purchased gas-fired powerfrom an independent power producer. The Sierra Club also complained that the commission never acted on the group's motion to make public information about the plant' s impact on rates, which the commission previously had designated as confidential. "As a consequence, the very persons who will have to pay for the Kemper plant have never been told the actual rate impacts ofthe plant," the suit said. Louie Miller, the Sierra Club's Mississippi representative, told The Energy Daily that the club also plans to challenge the Energy Department's yet to be released record of decision on the agency's National Environmental Policy Act (NEPA) environmental review of the project. Miller said Friday that James Markowsky, assistant energy secretary for fossil energy, had written the commission letters extolling the plant's virtues prior to the release of DOE's draft and final environmental impact statements on the Kemper project.' "A NEPA EIS is supposed to be an unbiased assessment of a project's environmental impacts," Miller said. "We felt that [Markowsky's letter] really bastardized the whole process and made a mockery of the EIS." 2 SoCo FOIA Response 001998 Please print this email only if absolutely necessary. Daniel H. Warren, Southern Company;205.257.6947; (b) (6) cell; The onfhrmaaion contaoncd on rhos C-maol message IS auumc, prnilegcd and confidentoalonfurmatoon ontendcd only fur the usc of the indl\·idual or cnmy name-d abo' e Ifthe r.:adcr ofthos message IS not the ontendc-d n.-coroc"!lt, or the cmplo) <'<: or agent responsible to delo,·cr otto the intended rccopocnt. you nrc notified that all)' dissemonatoon d" mhutoon or cop) ong of thos coommunocatoon is stroctlr prohibnc-d If you have received rhos communocatoon on error, pkasc immedoatcly nollf) us nt 20S·2S7 b9H Thank )OU 3 SoCo FOIA Response 001999 From: Sent: To: Cc: Subject: Attachments: "Warren, Daniel H! < DHWARREN@southernco.com> Wednesday, July 07, 2010 12:25 PM Detwiler, Ralph; Hargis, Richard (b) (4), (b) (6) McMillan, Scott RE: FW: Draft ROD Rich ver 070210.doc TEXT.htm Rich and Paul, Can we have a quick call at 12:30 PM CDT (1:30PM EDT) to discuss the issues outlined below? Thanks, Dan pp 13-14: Your suggestion to change the condition that "the plant be designed and built to achieve 67 percent carbon capture... verifying the actual capture rate with material balances" with an essentially meaningless condition that "SCS will monitor the plant C02 capture rate in accordance with the MAP." ignores the importance of a key feature of this demonstration. The importance ofthis feature to DOE is evident in the letter to the MS Public Service Commission signed by Secretary Chu stating that the project would "include carbon dioxide (C02) controls that will make the project's carbon emissions essentially equal to natural gas-based power generation." We understand this is an important aspect of the project. This does not mean that CCPI funding must be conditioned on it. Southern and DOE's agreement on carbon capture is already set by the cooperative agreement - which is not based on 67°/o. The FEIS was carefully written, at some effort, to cover a range of capture possibilities. It is not necessary to limit the ROD to only one of these possibilities - even though 67°/o is MPC's intent. p 29: Based on discussions with EPA, they do not believe that DOE has adequately addressed potential air quality impacts without additional modeling. The new NAAQS are set to protect human health. It is likely that failure to adequately demonstrate that SoCo FOIA Response 002000 this project would meet these new NAAQS standards would be perceived as a flaw in DOE's NEPA process. Until all the kinks have been worked out regarding how this modeling should be done, we are very reluctant to undertake it. This modeling would not be a trivial exercise. We believe DOE has adequately considered air impacts to human health. The screening model confirms this and represents a more than adequate response to EPA's written comments on the Final EIS. We understood this was DOE's position also. Lastly, believe DOE's position is more defensible if it responds to EPA's comment with the screening model only. By requiring additional modeling postROD, DOE effectively admits its analysis is incomplete and would then have to defend a decision to issue the ROD in spite of its incomplete analysis. p 7: I think the statement that "Mitigation measures beyond those specified in permit conditions will be addressed in a Mitigation Action Plan (MAP)." adequately addresses our agreement that compliance activities are not to be addressed in the MAP. We will consider adding the additional statements you suggested, but I don't think they are necessary. We believe this language is important. If there is anything inaccurate about the proposed insertion, then let us discuss that. Otherwise, we would be concerned about misunderstandings if it is not included. p 31: The reason for changing "...assistance provided through Mississippi Power's Kemper County Community Plan... " to "" ...assistance provided as described in Mississippi Power's Kemper County Community Plan ... " is not clear. EPA was satisfied with the original language. We do not want to imply that the plan will be continually amended to deal with this issue. p 10: Replacing "reasonable alternatives" with "cost-shared funding options" is not consistent with how DOE views the 10CFR1021.216 prcess. 2 SoCo FOIA Response 002001 We do not understand how this flows from Section 216, but maybe if you forwarded the environmental synopsis, we could better understand your thinking. Again, we are just trying to be helpful on this one. From: Richard Hargis [mallto:Richard.Hargis@NETLDOE.GOV] Sent: Wednesday, July 07, 2010 9:19AM To: Warren, Daniel H. Cc: (b) (4), (b) (6) Joel E. Uoel.trouart@nacoal.com) Trouart; Rebecca (Rebecca.Buell@nacoal.com) Buell; Harry B. lipton (Tres) III (Tres.tlpton@nacoal.com); Diane Madden; Ralph Detwiler; Toth, Brian D.; Berry, Charles Rick (MPC); Templeton, John D.; Benvenuttl, Keith M.; McMillan, Scott Subject: Re: FW: Draft ROD Rich ver 070210.doc (b) (4), (b) (6) Dan, With regard to your suggested changes: p 7: I think the statement that "Mitigation measures beyond those specified in permit conditions will be addressed in a Mitigation Action Plan (MAP)." adequately addresses our agreement that compliance activities are not to be addressed in the MAP. We will consider adding the additional statements you suggested, but I don't think they are necessary. p I 0: Replacing "reasonable alternatives" with "cost-shared funding options" is not consistent with how DOE views the JOCFRI021.216 prcess. pp 13-14: Your suggestion to change the condition that "the plant be designed and built to achieve 67 percent carbon capture... verifying the actual capture rate with material balances" with an essentially meaningless condition that "SCS will monitor the plant C02 capture rate in accordance with the MAP." ignores the importance of a key feature of this demonstration. The importance of this feature to DOE is evident in the letter to the MS Public Service Commission signed by Secretary Chu stating that the project would "include carbon dioxide (C02) controls that will make the project's carbon emissions essentially equal to natural gas-based power generation." p 19: Instead of "materially adverse effects," it may be better to use the phrase "significant adverse effects." 3 SoCo FOIA Response 002002 pp 22-23 and 32: Changes to wording requested by the Corps will need to be discussed with the Corps, as you suggested. p 29: Based on discussions with EPA, they do not believe that DOE has adequately addressed potential air quality impacts without additional modeling. The new NAAQS are set to protect human health. It is likely that failure to adequately demonstrate that this project would meet these new NAAQS standards would be perceived as a flaw in DOE's NEPA process. p 31 : The reason for changing "... assistance provided through Mississippi Power's Kemper County Community Plan ... " to "" ...assistance provided as described in Mississippi Power's Kemper County Community Plan ... " is not clear. EPA was satisfied with the original language. I am available anytime to discuss your suggested changes. Thanks. Rich >>>"Warren, Daniel H." 7/6/2010 11:41 PM>>> Rich, Attached is the version of the draft ROD you sent this morning with some suggested text changes along with comments on most of the changes. Perhaps we can discuss these changes on Wednesday after you have had a chance to look at them. Thanks, Dan 4 SoCo FOIA Response 002003 From: Sent: To: Cc: Subject: Attachments: "Henderson, Charles W." Friday, July 30, 2010 11:54 AM Madden, Diane Pinkston, Tim E. FW: 2005 Incurred Cost Settlement Update TEXT.htm Diane, (b) (4) This update is related to the (approximate) credit that was attributed to the Kemper contract on DOE books but not on SCS books. These credits have all been moved to the correct contract (MC25140) by DOE accounting. This should clear up the difference between SCS's financial records and DOE's financial records on Kemper. Thank you again for bringing this to our attention. Thanks, Charles Henderson Admin & Project Support Manager Gasification Technology 8-824-5844 - Wilsonville (b) (6) 8-992-7313 -Inverness (205) 992-7313 From: cantrell, Heather Benson Sent: Wednesday, July 28, 2010 12:44 PM To: Henderson, Charles W.; Philpot, J. David Subject: 2005 Incurred Cost Settlement Update More good news-The funds should be available in ASAP and it looks like it is the entire amount . Hopefully this will f ix the Kemper discrepancy as well. (b) (4) Heather From: Usa Kuzniar [mailto:Usa.Kuznlar@Nffi.DOE.GOV] Sent: Wednesday, July 28, 2010 12:12 PM To: cantrell, Heather Benson Subject: Re: Fwd: FW: 2005 Incurred Cost Settlement Update SoCo FOIA Response 002004 Heather, Funds are now available In SCS's ASAP account. usa Usa Kuzniar U.S DOE/NEll. PO Box 880 Morgantown, WV 26507-0880 PH: (304) 285-4242 Fax: (304) 285-4683 email: llsa.kuznlar@netl.doe.gov >>>Jason Paupa 7/28/2010 10:41 AM>>> Lisa, The entire deposit of (b) (4) this amount. has been applied to MC25140; the recipient's ASAP account has also been Increased by Thanks, Jason >>> Lisa Kuzniar 7/20/2010 10:07 AM>>> Thanks Jason, Please let me know when this happens. lisa >>>Jason Paupa 7/19/2010 3:34PM >>> Usa, I will have the funds added back to the recipient's ASAP account for MC25140, however I am still waiting for EFASC to adjust entries on the receivable side, which should be done shortly. Thanks, Jason >>> Usa Kuzniar 7/14/2010 3:14PM >>> Jason, Can funds that are credited back as a result of a cost Incurred settlement be put back In SCS's ASAP account? Lisa >>>"Henderson, Charles W." 7/14/2010 11:59 AM >>> Memo concerning the(b) (4) credit. Charles Henderson Admin & Project Support Manager Gasification Technology 2 SoCo FOIA Response 002005 8-824-5844 - Wilsonville (b) (6) 8-992-7313 -Inverness (205) 992-7313 From: cantrell, Heather Benson Sent: Tuesday, July 13, 2010 1:47 PM To: Henderson, Charles W.; Philpot, J. David Cc: Wilson, Debra Lynn Subject: 2005 Incurred Cost Settlement Update (b) (4) I spoke with Andy Ferlic today and he sees no reason why the credits to the Kemper and greements can't be reversed and the total amount of the settlement ( (b) (4) ) credited to the old PSDF agreement. He sent an Inquiry to the financial personnel at DOE but has not heard back yet. He will let me If this can be corrected. On the second question about getting the credited amount back Into ASAP, the adjustment should be applied to the overall paid amounts to SCS. Unless the funds have been deobllgated (which they haven't) then the amount should be available. The contracting specialist on the agreement would be the appropriate contact for getting this amount added back to the ASAP balance. I spoke with Lisa Kuzniar about this a few weeks ago and she was checking Into It with her finance department. I tried to follow up with her today but she is out of the office. I will keep you updated. Thanks, Heather Heather Benson Cantrell Southem Company Services, Inc. Government Contracts Coordinator 600 North 18th Street Birmingham, Alabama 35203 (Office) 205-257-7162 (Fax} 205-257-6381 hbenson@southemco.com 3 SoCo FOIA Response 002006 Dunlap, Ann C. "Kuhr, Reiner" Wednesday, August 04, 2010 11:32 AM Madden, Diane; Mele, Raymond; Nichols, Steven T. Richert, Debra; Chase, Hope; Hannink, Ryan; Vivenzio, Thomas RE: tax credit deadlines TEXT.htm From: Sent: To: Cc: Subject: Attachments: Thanks Steve From: Nichols, Steven T. [mallto:STNICHOL@southernco.com] Sent: Wednesday, August 04, 2010 11:30 AM To: Kuhr, Reiner; Diane Madden; Mele, Raymond Cc: Chase, Hope; Richert, Debra Subject: RE: tax credit deadlines Phase 1: MPC was required to have all federal and state environmental authorizations or reviews necessary to begin construction (which in this case was the air permit) and a binding contract for purchase of the main steam turbine in place two years from 11/29/2006, or 11/29/2006. MPC sent proof of both these requirements on 11/24/2008. On 5/11/2009, the IRS certified the project based on MPC's proof sent on 11/24/2008. MPC has five years from 5/11/2009, or 5/11/2014, to place the facility in·service. Phase II: After receiving notice from the IRS on 4/30/2010 of its allocation of Phase II fTCs, MPC had until6/30/2010 to file a closing agreement with the IRS for the allocation of the credits. MPC has filed that agreement. IRS now has until 8/30/2010 to execute the closing agreement. From that 8/30/2010 date, MPC will have two years to meet the certification requirements that are the same as Phase I. In its application to the IRS for the Phase II credits, MPC stated that it had already met those requirements. The IRS will issue certification for the Phase II credits probably this year. From that point, MPC will have 5 years to place the facility in·service to retain the allocation/award of Phase II credits. Please let me know if you need any other information. Steven Steven Nichols Southern Company Treasury stnlchol@southernco.com 404.506.0776 (b) (4) From: Sent: Wednesday, August 04, 2010 9:40AM To: Diane Madden; Mele, Raymond; Nichols, Steven T. Cc: Chase, Hope; Richert, Debra Subject: tax credit deadlines Can someone summarize the key deadlines for the tax credits for Kemper. We have not reviewed documents related to the award of tax credits or their requirements. We need to address those deadlines relative to project completion target dates. Reiner SoCo FOIA Response 002007 (b) (4), (b) (6) Senior Executive Consultant (b) (4) (b) (4) direct(b) (4), (b) (6) cell (b) (4), (b) (6) (b) (4) (b) (4) ****Internet Email Conlidentiality Footer**** Privileged/Confidential Infmmation may be contained in this message. If you arc not the addressee indicated in this message (or responsible for delivery of the message to such person), you may not copy or deliver this message to anyone. In such case, you should destroy this message and notify the sender by reply email. Please advise immediately if you or your employer do not consent to Internet email for messages of this kind. Opinions, conclusions and other or its inlbrmation in this message that do not relate to the official business of (b) (4) subsidial'ies shall be understood as neither given nor endorsed by it. _________________ (b) (4) 2 SoCo FOIA Response 002008 From: Sent: To: Cc: Subject: Attachments: "Pinkston, Tim E." Friday, August 20, 2010 5:09 PM Madden, Diane Henderson, Charles W.; Eiland, Joseph D.; Graham, M. Steve Cooperative Agreement DE-FC26-06NT42391- Updated CostBreakdown for Phase lllb & SF424A Kemper County IGCC EPC-Startup Cost Breakdown for Phase lllb 08-17-lO.pdf; SF424Aexcel 08-19-2010.xlsx Diane, Attached are an updated cost estimate breakdown for Phase lllb and a completed form SF424A. The differences between the attached cost estimate and the estimate submitted on April 27th are: (b) (4) Please call me if you would like to discuss. Tim From: Pinkston, Tim E. Sent: Tuesday, April 27, 2010 9:26AM To: Diane Madden (Diane.Madden@NETL.DOE.GOV) Cc: Henderson, Charles W.; Eiland, Joseph D. Subject: RE: Cooperative Agreement DE-FC26-06NT42391- Updated Cost Breakdown for Phase lllb The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. Diane, Attached is a revised cost estimate. Our project team decided to spread the estimated freight costs to the individual line items instead of including it as a separate line item. The attached report reflects this change. Other than a few minor round off changes to the numbers there should be no other differences. SoCo FOIA Response 002009 Please call me if you would like to discuss. Tim «File: Kemper County IGCC EPC-Startup Cost Breakdown for Phase lllb 04-26-10.pdf » From : Pinkston, Tim E. Sent: Friday, April 09, 2010 3:57PM To: Diane Madden {Diane.Madden@NETL.DOE.GOV) Cc: Henderson, Charles W. {CWHENDER@southernco.com); Rush, Randall E. {RERUSH@southernco.com); Eiland, Joseph D. (JDEILAND@SOUTHERNCO.COM); Graham, M. Steve (MSGRAHAM@southernco.com); Owen, Steve (SOWEN@southernco.com) Subject: Cooperative Agreement DE-FC26-06NT42391- Updated Cost Breakdown for Phase Ilib The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. Diane, An updated cost breakdown for Phase Ilib as required by Article 2.38 of the Cooperative Agreement is attached. The cost update is based on the following: • • • • completion of FEED for a non-C02 capture case selection of (b) (4) as the combustion turbine supplier addition of 65% C02 capture and compression change of COD date to May 1, 2014 Please let me know if you have questions or need more information. Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) «File: Kemper County IGCC EPC-Startup Cost Breakdown for Phase lllb 04-09-lO.pdf » 2 SoCo FOIA Response 002010 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~ Quantity u Account I Description Workhoul'$ Labor Material Subcontract Total (b) (4) The Redpienl of Cooperalml ~ OE.fC26-06NT42391 c:onsidenlho malenal fUn'iShed- t o contain ariodentiol business inlonnabon wl1dl is to l>e withheld from disdo....., outside the U.S. Go.emment ReportOate 08118110 08/18110 1 File Dato 10 11e extent permiltld Dy law. Page Ttis document contains proprietary, confidential, and/or tnoao oecrot Information of tl18 s\Alsidiarios of Southern Company or of tl1ird parties. Ills intended lor use only Dy employees or or authOrized coniJatlors of aubsidiarios a1 Soulhem Company. UnauthOrized possession, 1110, dislrOOtion. copying, cts..,mination. or ctstlosl.f8 al any portion is prohibited. - -- - - - - -- - - - SoCo FOIA Response 002011 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~ Quantity u Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho RecipientaiCooperabve ~ DE-FC26-06NT42391 tonsidenllhemalerial II.WTishedhonrin1o containnlidentiol. and/or trade seael inlonnation ollhe s - . ol Southem Company or of 1hird parties. Ills intended !of use orly by employees ol or 8Uhcrizad ccn1rac1ors ol SUbSidiaries oiSoulhem Cclm!l&nY U\au1harized possession. use. dlstnbulion. a>pying. disseminalion. or diSdoSift ol any portion is prol\illil ad. - - - - SoCo FOIA Response 002014 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total AccountiDescnpt~n (b) (4) The Recipient of CoopefatMt Agrement DE-FC2!1-06NH2391 amiders the material l..nshentradof1 o1 Unaucnonzod pouessian, tae. dislt'll>u1ion. copying, lissemina-. or mSdO.... atony portJan is pre~-.! - - • at Southem Company. SoCo FOIA Response 002017 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K=r Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) The ReapeniOI~ Agretmen~OE-FC2~~2391 a>nsiden 1he material funHhed hef8into a>nlain c:onfodential buslnesslnfonnallonwm:h ls to be withheld from disclosure cutside1he U.S. Govetm~ent to 1he extont pom-illod by law. Report Date File Date p- Ttis llocul'nenl a>nlains pr1)1Jrietlll)', a>nfidenlial. and/al- seem information ollhe ll.tlsidialies of Soulllm Cem Company Unauthonzod possnsion, use. dislnbution, copying, dissemination. or dlldcsue o! any portion Is prohibited --- 08118110 08118110 8 - SoCo FOIA Response 002018 I KEMPER COUNTY IGCC EPC I STARTUP COST BREAKOOWN FOR PHASE lllb Key K:( Quantity U Workhours Labor Material Subcontract Total Account I Description I (b) (4) Repon Dato The R..ap;.nt ol Cp'O al any ponion Is prohlboled. - - Fie oace Page - - 08118110: 08118110 I 9 - SoCo FOIA Response 002019 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:( Quantity Account I Description u Workhours labor Material Subcontract Total (b) (4) Tho Rocipienl ofC""""""""'Agreemenl DE-FC26-06NT42391 aJnsidtn lhe.,_lllwrishedhenrin toa>nlain conrolentilll businesslniOimationwticlllsiO be"'ll"llelcllrom llisdoSiftOUISintidon~ll. andlor llado HCtOI infonnalion or lho &lbsidiartos or SOU1hem Company ot or third parties. lllslnlen:led lot use only by employtes of ot authorized oontraCIOem Company. UNiulhorizod po&session, use, dislnbution, ~. llisseminalion. Of diSdollft of any pot!ion is pn>111Diled. SoCo FOIA Response 002020 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~ Quantity U Workhours Labor Material Subcontract Total Account/ Description (b) (4) Tho Roapent ol Coopeta!MI A-11\0111 OE-FC2~H2391 considORII\e INIII,tlal furriShed hen!in to contain confoiled. SoCo FOIA Response 002021 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K;.( Quantity U Workhours Labor Material Subcontract Total Account/Descript~n (b) (4) Tho RocipienloiCooperative Agreement DE·FC26.o&NT42391 c:cnsid.s lllemateriollumisl\ed rweiniO conllin CCdodentilll busine.. lnfatmalionwl1ichls1o be wiltoheld 1mm dlsdoSIAoutsicle 118 U.S. Govetmlefll 10 the eJdenl penriaed by law. T t i s - a>n1ains prnptietlry, ~. _ . . _ seaet ~ollhe ...t>.idiaries oiS...-mCornpanyorollhird partifl. ll lslnlondthibilecl. RepottDIIe F"lle Dale p- 08/18/10 08/18110 12 SoCo FOIA Response 002022 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE Ulb I Key Key Quantity UM Workhours labor Material Subcontract Total Account I Description I (b) (4) Tile Rec:ipienl of Coopenllive ~ DE.fC26-06NT42391 amidoB lhe mattrilll turmhed helein to contain conlidentialbuoinass information wtieh is to be withheld 11om Cksdo...., - l h e U.S. Govemnont to lhe a>tont pennitled by taw. Repsidiaries of Southam Company or of tllird patlles It is Intended lor uso only by employees of or aulhorized conttadors of subsidiaries of SOUUlem Company. llnaulhorized possossion. use, Ckslli_bution. copying, dissemination, or ctisdo•o.n of any portion i1 pited. Report Dolt File Date Page 08/18/10 08/18/10 14 SoCo FOIA Response 002024 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~ Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) ReponOato Tho ROQ!Iienl o1 ~ Agreemenl DE-FC26-06NT42391 c:omiciOtS fie maten•lurrill\ed honiniO awuin ..,.,._. butiness inlormatieln wl'id1 is to be Wllhlleld from dosdosure outside lhe U.S. ~ 10 1h8 __, ponni11ed by lllw. Tlis documenl IXIIIIains proptio1ooy, aJnfidontiaJ, ondiSidiaries of Southem C""""'ny Of of third paRies. 11 11 intended fa< UM only by employ" ' ol Of authorized IXIII11BCIOB ol subSidoories o1 Sou1nom Company. lklautnOfiled posMSIIion, use. dlstnbution, copying, dosseminalion, Of disdoS!A o1 ony po<1ion is pnnbi1ed. - -- - - Fila Dale Page 08118/10 08118110 15 - SoCo FOIA Response 002025 KEMPER COUNTY JGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:¥ Quantity u Workhours Labor Material Subcontract Total Account/Descrlpt~n (b) (4) The Recipent oiCooperallve ~nl DE.fC2fMJ6NT42391 considers lhe malerilllurrHhed herein Ia a>nlOIIDato File Date Page 08118110 08118110 16 This tloaJnWot contains fiiOPIIe!IIY. <:onlldenti;ol, anc110r vade sect8l information ollhe soosidiaries ot Soutllem Company or ollhinl p811ies. It is inlendod lor use only by employNs otor authorizenlidetS b! maleriallumisned hontiniO c:ontoin tcnrodential b u -u 1D lhe txtenl permit1ed by law. wtid> lsiObewilllheldlrom nfidential, and/a'lradt Mael inlormalion ol 11'18 slbsidiaries ol Soulhtm Company or ollhinl ponies. II is intended tor use ntradOB ol oubsidiaties ol Southern Company. Unau1hortzed possession, use. dislribubon, copying. ient o1 Coopot3iwe ~ DE.fC2&.06HT42391 COMidetS the to the oxten1 ponniaed by taw. Report Date lun'iShed henlin to contain alllfielemjojlluSinoss informotionwtich is to be witllheld from disclosure OWido the U.S. Go-mmlllf1t ... Date Page This doalmont oontains prop1otary, conftdenbal, an<11or trade 50altt lnrormobon 01 tho U>sidiarias or SOUihem Company"' o!lllinl panies. It lslntenlled rOf use only by employou of Of aut!IOriled CXJnlradOhibilod. - - - - - - - - -- - - 08118110 08118110 18 - SoCo FOIA Response 002028 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~ Quantity U Workhours Labor Material Subcontract Total Account/ Description (b) (4) The Aodpienlol ~ Aweemenl DE-FC26-06NT42J91 considers lhemoeerial furlilhenlr.odarl o1 _!1-Gsidilries ol Southern Company. I.Jnasidlaries o1 Soutnem Company or ollhirU patlles. It is inlondod lor use only by employees of or at.thsidiaries 01 Scutnom Company or 01 11\in! pal1ios. I! is intended lor use only by employees or or authorized conttadors or SUI>sicliaries ol Sou1nem eornp.ny. Ufl8ullorizod po....sion. use. clistriiJutiGn, copying, dissemination, 01 cUdoSIR ol any pottion is prohibotod --- - - - - - Repott Dille FileDa1o Page 06118110 08/18110 22 - SoCo FOIA Response 002032 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Kay Kay Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) The Racipien1 o1 CoopetaiMt Agraemltlt DE·FC25-06H1'42391 tonlldl!fSihe maltflal lurrished herein to CDnCain confocMMIII businessinfonnltionwm:h is lobe wilhhefd flllm dosdosuno OUISidolhe U.S. Govemnenl to ltlo ext«hibillm>aiiOn wticto Is to be .,.;tllheld from disdosure outside l:le U.S. Government tolho extent penrinod by law. ..-trade Ro-;:g:: Page 08/t8/t0 08/18110 24 seaet inlonnltion of the suDsidiaties 01 Southern Company ot 01 thiRI parties. his intended lot untrac1ots o1 This cloCurnenl oontains PfOIIriotlfY. ~al• sui>Sidoaries Ill 5outhom ~- ~ed poooesslon. use. distribt&n, a!pying. dissemination, or disdollft Ill ony portion is prohibited. -· - - - - · SoCo FOIA Response 002034 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKOOWN FOR PHASE lllb Key K: Quantity Account I Description u Workhours Labor Material Subcontract Total (b) (4) The RIIOjienl Dl Cntain ~business infonnation wlich io to be withhold 1n1m disdoSlft OUWde tile U.S. Gcwewmont to lhe ""''"'t petmilled by lew. ReponDace FotaOale Page 08118110 08118110 I 25 Ttis dOeument conW!ls proprietary, confidenbaJ, and/or trade secrotlnlomuotion Ollhe sublidiaries ol Southam Company or Ollhird panies. Ills intended for use only by employees of or aUVIOrized contractors ol subsiliaries rA SOUUM!m Company. lMiaiAAcrized possesiion. use, diolnbutlon. copyilg, dissemination, or disclosure rA 111y portion Is pn>hibiled. SoCo FOIA Response 002035 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Work hours Labor Material Subcontract Total Account I Description (b) (4) The Rocipienl ol Cooperative Agreement DE.fC26-06NT42391 comidefs h to the extont petmiltod by 1-. material furftshad hefeinlo contain confidential business infonnallan wtich is 10 be willllleld from disclosunl outside h U.S. Govemmonl Tlis documenl conlains propnel.-y, ...-~aJ. and/Or trade soaot infonnabon ollhe slbskliarios or Southem Company or of third parties. II is intended lor use e withheld from disclosure outsidelllo U.S. Go-mnment Ropon Date File Date p- oe/18110 oe/111110 27 I Tlis doCument contains propttotory, confidenlial, and/Ot lnldo 10a111 informatiOn ollho s~Sidiarios ol Soucnom Company or of tnitd par11os. n is intended lor use Ol'lly by employees ol o< ai.CIIOii.ted contnltlors ol subsidiaries ot Soutnem Company. UnauthOrized pouosSion, use. disllibulion, copying, dissemination, or disdos..o ot any portion Is pmhibiled. SoCo FOIA Response 002037 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Kay KM Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Redpienl of CooperaiMI.Aili""'Onl DE·FC26-06NT42391 cmoidn Ule malefiallutrished helein 10 cmlain conrodential business infomlation wticllls 10 be wiiMelcl from disdosunt outside lhe U.S. Govtmmonl 10 lhe extenl permiHad by •-· Repon Dale File Dale Page 08118110 08/18110 28 Ttis ~ conlaina proptlelaly, conMontill, ondlot ndo seael inlom1alion ollhe - - o1 SOUihemCom1)111y orolll*nlractors of IUbsidialies ol 5...-n Company. Uneulhorized possession, use, aopying, dissemination, or disdoSin o1 any poRion is pnol\illiled. diS-. - -- SoCo FOIA Response 002038 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE IUb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tt. Roopient ot CoopenliMI AIIe withheld 1rom clisdosuno outside the U S. GoveiTVI\IItlt to IIMI elden! penlidential. and/or ode sactel infonnai!On or 1t1e slmsidia:ies of Sou1hem Company or of third parties. It is intended I« usa only by e""""'ees of« authorized a>ntrac:IDB of IUbsidiari.. of Soutllem Company. UnaulhOrized possession, use. distOOution, copying, dissemination, or disdo...., of any pompany or of lllittl panies. II is imendad lor use only by employees o! or authorized contractors of subsidiaties o1 SOU1Ilem Company. Unauthorized possession, use, dislnbution. copying, dissemination. or dsdo...., of any portion Is prnhiiMiad. SoCo FOIA Response 002041 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Kay KM Quantlly U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient ol Cooperati't8 AgrHtnon1 DE.f'C28.Q6NT42391 considet1 tile materiallumislled - 1 0 contain con1"odontial bu$iness intonnabOn whid\ is 10 be withheld from disclosUill outside tho U.S. c;o.emmen1 to 1llo eldent pe11111Hed by law. Report0&1o 08118/10 08118/10 32 F~oDato Page Tlis doamenlconlaoo'ls propnetary, a>nlidentilll, ondlor nde seael inlonnation of 1ho subsidiaries ol 5...-.n Company ot ot third panies. II is inlonded b use only by emplOyees of ot --.ortzed conlr8Ciors ol &ubsiclo8lies ol Soutllem Company. U1aulhorized possession. use, CloSUIOution, copying, di........,.1ion, ot disdoltn ol ony portion is prohibited. - SoCo FOIA Response 002042 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lib Key Key Quantity UM Account I Description Workhours Labor Material Subcontract Total (b) (4) The Rttdpienl of Coopetalive " - " ' DE·FC2~ 42391 conSidenlhe maleriallumislled neteinla Clll'llain oorlidtmhl business iniOimalian wl'ich lolo be 1lrillliM!kllnlm disdo.... .,.,_ 1IMI U .S. Gc.ernnenl 10 N e>11tm1 ponnil18d by law. Ttis """-"1 contains proprietary, confidomiel. - - - - inlonnotion ol . . - --·or Soulhom Cor1'f>anr. .. oiSoulhom Company"' olll*d parties. ~is inCended '"'use only by IKJ1IIoyeeo Unau1narized possession, use, di5tnb1Aion. a>pyW1g. di$Seminalian, 01 dl$dOSnsld. . tho material ILrTHhed herein to a>ntain conrldsidialles ofSDIAhom Companyorolllinl parties. llisinlendodloruse arty by employees of or IMh<>IIUclconlradcn of lllbsidiaries ol Soul1em Cofnlwly. l.lfiWhDrizod possession. use, distnbuloon, copying, dissenina1ion, or disdoSift ol any portion Is ptDIIibilod. SoCo FOIA Response 002045 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKOOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontn~ct Total Account I Description (b) (4) Tho Retipient of Cooperative Agreement OE·FC2tMI6NT42391 to the edent penll-. -llade HCnll infonnaiiOn or tho slbsidiaJies oiSoothem ~ny or of tniRI parties. Ills intended lor use only by omployees of or autllollzed c:on1radorS or MJb,;diariu or Soulhem Company. Unoutllortles Pf"'I'MM.-y, ""'*'entiol, inlonnaliOfl ol tho Slbsklianos ofS..-mCompeny 0< oftiWII ~s. It Is intended tor usa my by employees of 0< -.oriled contraclor$ of sui>Sidilllies of 5..-m ~. ~eel possession, use. dlstnbulion, aJPP>o, dissemination. 0< diSdOStn of any portion il prollibitod. SoCo FOIA Response 002047 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:( Quantity Account I Description u Workhours Labor Material Subcontract Total (b) (4) The ReciJlient of Coopenltivany or o1 third paniOs. n is intended lor use only by omplayees o1 or IWU1cllzed a>nYactoB o1 14lbsidioriu ol ~ Cc>mponjl. Unaulllorilod possession, use. dtlltDtion, ccpying, dissemination, or Chelollft ol any portion is prohtOiled. --- - 08/18110 08/18/10 39 I SoCo FOIA Response 002049 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/Descrlpt~n (b) (4) The Recipient of Cooperaiiye A~ DE·FC21Hl6N1'42391 a>nsiders tne material fl.mished heroin to conlainc:ont'odential business intormationwt1<11 is tobewittl1etd tnxndlsdoSU111 outside tne U.S. Goverrmenl 10 the extent pennitted by taw. ReJ)OftOete Fi e Date Pogo 08/18/10 08118/10 40 Ttis doa.ment contains pmprietag. dissemination, a diSdoSIA o1 _, portoon is prnlldliled. -session. SoCo FOIA Response 002050 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE IUb Key Kay Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho Reapenl ol Coopera1M1 Agn1em0n1 OE· FC2f>ll6NU2391 aJnW.S the malenal lumishod- ta IXlfltain canrldentiot .,...._ss lniOIII\Ition wtich is to be wi1llhetd from shedhereitiiOCOnlain corCodential business inlor!NIIion wtiehisto bewi1hheld from disdosonoutsidt 1118 U.S. Govenonen1 to 1118 e xtent ponnilled by taw . Reponlidential. andlor .,_secret in1onnalion ol the stbsidiaries ol Southom Company or of liWd parties. It is intonclod tor use crit by employees ol or authorized contradors or suboidiaries or Souchem ~- ~ed possession, use, - · copying, dissemination, or disc:IOswa or any pof1ion is prol\il>itecl. SoCo FOIA Response 002052 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKOOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Account I Description Material Subcontract Total (b) (4) The Recipient of CoopeniiMI Agreement DE-FC26-06NT42391 anY oral tninl patties. His subsidiaries al Sou1hom Company. UniiAhaf1Zed possession, use, dis~. a>pying. disoeminalian. or disdo...., al ony portion is proholli1od Tift~ uslness lnfonnation wl"icll is to be wilhhokllrom dosdosURI outside lhe U.S. GoYII,..,ont to the elllent pennlted by taw. Tl'is doc:umerol contains Jl'Oilriei81Y. confidential, andlof llaCie- infonna~on ollllll s\Jisidiaties ol Soutl\om Company.,.. ollhinl parloes. It is intended IO< use only by emplOyees o1 Of authorized conlnlc:ton o1 oubsidilllios ol Souchem ~. Unau1hcJrUed pooMOiion. use. diotn~Mion, copyong. dissemination. <1 disdoSURI o1 any ponion Is prnnoboled. Ropon Date Fie Date Page 081181t0 081181~ I SoCo FOIA Response 002054 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key KM Quantity U Workhours Labor Material Subcontract Total Account# Description (b) (4) The Redpienl of Cooperaljve ~~~~ DE·FC26-Wrr42391 coonsiclotJ the malen.i fl.omishfld hon!inta contain confodenlial business inlomlation wtich is to be willlheld 11om disdoiUnl outside the US. Go..........,! 1o tho extent petmiltod by law. Tin docunenl oantains proprielar)', cunlldenliol, . . - ndo oecm inlonnation ol tho stbllidiarin ol Sautnetn Company or ol third pallies. H Is intended lor ""'only by omployoos ol or IUChoriZIKI c:onlnlcloB ol so.osicianos o1 5outhom Company. UMutroortzecl possesSion, use, lislribution. a>pying, dissominaeion, or ctsdoSUll ol any ponion Is pronil)iled. -·- - - - Report Date File Date Page - - - 08118110 08118110 45 - - - SoCo FOIA Response 002055 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE tab Key K:r Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) Tile Reciplenl ol ~ AgrHfM111 OE-FC26-a6NT42391 consiclen the materialltnishecl- to contoin pyf>g, dissemination, or disclo.... ol any portiOn is prnhibitecl. IJNull10oizentain ariodtntioll>usineu inlonnacion wl'ich Is to be witnheld 1n>m disdoluno outside tne U S. Go-mrment permottod by law. ROIJOIIData File Date to""- Ttis document a>nfidential business inf011111tion wlith Is to be wi1hlleld 1Iom disdolunt outside lhe U.S. Government to the exlent permi11od by Jew. TlildOalmtnl conlains propri!lary, IXlllfidenlial. andlor- seaetintOIII\Itionotlho ~~~~~- otStnnelcl from CliSCIO....., outside 1he u.S. Government Ia 1he e>denl penniHed by law. Tllis CIOCumenl contains pmpnelary, confidential, and/or trade seaal inlormabon of lhe slbsidlaries ol Southern Company oral lhird partios. Ills inlended for use Oldy by employees of or subsidiaries ol Sou1hem Company. Unautnorized possession, use, ClistllbUtion. copying, nfidential, and/or trade oecnotlntonnalion cllhl s~sid&anes of Southem C<>mpany or of third parties Mis intended for use Drllf Dr emplorees cl or authorized c:onlnlctors of subsidiatiet cl Soulhem Company. ~ed posses lion. use. diSIIibulion. a>pying. ctssemina!ion, or ctscto...-. cl any portion Is prohilloled. Repot!Oate File Date Page 08/18/10 08/18110 so SoCo FOIA Response 002060 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhouns Labor Material Subcontract Total Account I Description (b) (4) Tr. Rtcipienlor Coopeni!MtAgreemenl OE-FC26-06NT42391 considers 11e maleriallumished-lo contain cor1"1dontial business inlonnai>On whk:his to be wi4Nleldl'rDmclosdOsure outside the U.S. Go.,.,.,... to 11e ex~en~ pomilted by law. Ttis ~ cotMains JliOPIIOirt, ~- ancllar . - seaet -.nation or the llbsidiaries or Southern C"""'""y or of third panies. his intendeelforuse orty by omployoes of or Nhntrac:IOR or suboidiaries ol SouChem Company. ~od possession. use. nfodential businosslnfonnation wtadl is to be wilhheld 1n>m disdosunl ouWnlidontlal, Md/ornde saaet inlamlotion ol the llbsicloeries cl Southern Company et ol tl1inl panies. His intmled let use only by employHs ol et IIAhariZed ~Xlfltrac~Qrsol llbsichries ol SoutiiOm Company. ~ed possetSiOn, &ae, distriiMJtion. copying, dissemination. or dildo,... ol any pCirtion is prollillited. ---·- - - - -- - Rej)Otl Date Folfi Date Page 08/18/10 08/18110 52 I SoCo FOIA Response 002062 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lnb Key K:r Quantity U Workhours Labor Material Total Subcontract Account I Description (b) (4) Tho Rodpienl oiCoopenltiveA9111'1"'nl OE-FC26-06NT42391 c:onSOden 1hematefialllmishedhensiden Wle materiallurrished herein to contain~~~ business inlormation wtich Is to be Withheld from disdosunt outside the U.S. Goverrrn..,. to the o- . t pennitllsicbries of Scut11em Company or oflhitd parties. ft Is intended lor use orly DJ employees of or - - · oiSol*lem Company. ~od poiiiSsion, use, diS~. copyilg, dissemination, or dildo...., of atry portion is~- •-odcontra Ropor1 Date File Dale Page 08118110 08118110 5-4 don of SoCo FOIA Response 002064 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho Reapienl ol ~MIA_....,. DE·FC26-06NT42391 nCa1n a>rlodential businesslntniclentlal, ~- -=nionoltho sU>sidiaries of S..-.nCOmpany"' ollhrd p;llties. lt ls lnl- l o r use only byemjlloyoos of or II\AhOnleclcontladors of of Southern COmpany. ~~~~possession, use, dostnbution, a>pying. dissonitlation, Of disdoSIA of any portiOn is pnlhibilld. SoCo FOIA Response 002065 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Kpj Quantity U Workhours Labor Material Subcontract Account I Description Total (b) (4) The Recipient of Coopen!IMI Av-oment OE·FC!fl.06HT423G1 c:onlidesidoaties 01 Southern Company ... ollllird patlios. It lslnlll'dtution, copying. dissorMation. or disdos.... o1 any ponion Is prohbited. - ReponOate FdoOIIO Page 08118110 08118110 56 I SoCo FOIA Response 002066 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description I (b) (4) The Recipienl ol CoopofaiNe Agreemenl OE-1'~42391 considers the maltrill turrished herein to contoinconfidential blninosslnlonnat!onwhCtllo to be Withheld"""' dosc:lo,... outside the U S Govem-Tlont 1o lie extent pemW!ed by law. Reporl Dale File llale Page 08118110 08118110 57 Ttos doa.mtnt conlains proprietlll'f, confi-tial. anc11o< ll8de secntt infonnalion o1 the sl.t>sidiaries o1 Soulhem C<>mpany or ollhirll pa111es. N os ontended lor use ""'Y by employees of or aulllotiZen1111cton ol l l l b - 1 ol Soulhem Company lklaUihonzed possession, use. distribution. ibiled. SoCo FOIA Response 002068 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho Rocipienl of Coopenllive Agreemonl PE·FQ&.O!SNT•2391 ccrosidon 111e maloriol lurrished hen!in 1o contain ariodonCiat business infom>alion which Isla be will1hefd from disdoswe ouCsido lho U.S. Galion oflho si.Csiilod. SoCo FOIA Response 002069 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K:¥ QuanUty U Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient of CooperaiMJ Agreement DE·FC26.-rr4239t cms;d. . the malerial furnished herein lo contain conl'odential bus;nesslnlormation which is to be withheld 11om doSdOSIA'll Onlains propriet.y, aJnlldentill, anc1111< wade secret inlonnlolion ollhe subsidiaries of Saulhem Company or of lhirnlidentialbtninass Wonnai>On whiCh it to be withheld 11om Closdasure outtidelhe U.S. Govemneru to tne e.donl potmilled Dy lew. Repot\Oate File Date Poge 08119/10 09119110 61 This ciOCuNinl contains propriel.y, ~• . . - - semtt inlonnation ollhe Sem ~- \Jnautl1orizod poueuian. use, cblrillu1ian. copying, llsseminalian, or lisda,... cl any pollion is prohiiJitod. -- - SoCo FOIA Response 002071 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb KM Key Quantity U Workhours Labor Material Subcontract Total Account I Description (b) (4) Ttw Rooplflt ol Coopet8liYe Agreemenl DE·FC26-06NT42391 a>Mklors 1118 material furnished twrein to congjn confidential business Information 'Wtich is Ia be v.ilhhold 11om dosdosure outside lho U.S. Govo,.,enl to lho oxtont pem1llled by law. Ropor1 Oa4o FioOato Pli!IO 08118110 08118110 62 Tnis dO<:umenl contaitS pmprielary, confidential, . , _ trade oeaetlnlormation ol 1110 ...,siGiaties 01 Soulhem Company or Ollhird parlies. n is intended lor use only by emplOyees ol or OUihOriZod conlnldDB ol IUbsicliaries cf Soulhem Company. Unauflolizod possession, use. clistnbutlon. mpyi'lg. chsominalion. or disdosure cf ony polloon it pmhibded. SoCo FOIA Response 002072 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description I (b) (4) Tho Rodpienlol Coopera!Mt A~ DE.fC26-06NT42391 considers the malerial1umishod -1ocontain corlodential bulliness inlorlnalion wr>dllsto bewilllheld l'romdilldosunl ou1sido IIMI U.S. Govemnenl lo the •~ pennifted by 1-. the...,_ Repon Dato File OOie Page OB/18110 OB/18/10 63 TtisdOC:Umenleoolains poprielary, ~. - - seo111 ~of ofSOUihemC""-'y «of third partles.llislntondedloruse only by employees of or ~~.Chortled COI11nldon of SUI>Sidi8riH of Soulhem Company. ~ed posSOUiOn, use, dis1ribution, mpying, lliuemination, or disdosdo- ~ ollhe ..midiar\eS Dl $nlnldaulharlzod pouession. use. llistnbution. copying, dissemination, a disctcsure D11111y por1ioo is pilod. - SoCo FOIA Response 002076 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Account I Description Workhours Labor Material Subcontract Total (b) (4) The Recipient of Cooperative Agreement DE·FC:2lHl6NT 42391 considers lho maler1all\mishod hon!in lo conlain a>nfodential business infolmation which is lo 1>e wilhheld from disdoSUo'8 OUisido lho U.S. Government 10 lho exlenl perminod by law. Repon Dale Flle Oate Page 08118110 08118110 67 This dOClJment contains prapnetary. confidential, andfo( ln>de seaat infonnalion of lhe st.t>sidiaries or Soulhem Company or or lhinl pallios. Ills intended lor use only by employees of or authorized contradon or subsidiaries d Soulhem CGmpany. lJnauiiiCri%8<1 possession. use. ctoSinbution, copying. dissemination, 01 dlsdosLnl d any portion is prtlhibilon~ 1he maltliM furnished hen!in to a~nt.ain corl'odontial business inlormatioll wiKh is!o be -lrom disclos..., OU1Sidelhe US. Go...........,. ROf>O'IDalo File Dale Page 08118110 08118110 68 This cloaJmonl nlain conl'ldential business infonnallOn wticllls lobe withheld lnxn disclosure oulsldo lho US. Governnent 10 tho elden! pemocted by law. ReportOalo FUeOale Page 08118110 08118110 89 TIH docunent c:onlaino proprietary. conftdontial. and/Otlnlde seael inlormation ollhe slbsidialies o1 Saulhem Compony or otlhiltl parties. 11 is intended tor use cny by employeos of or ..cllolized a>nlnletDts o1 subsidiaries ol $oulhom Company. Unaulhorized possession, use. dlstnbUion. copy0>g. - · o r disdoslft o1 ony portion Is pn>llibiled. SoCo FOIA Response 002079 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~ Quantity U Workhours Labor Material Subcontract Total Account/Description (b) (4) The Rodponl ol CcopetaliYo Agreement OE·FC26.QBNT42391 considen 1he moteriallumishod llerein to contain confidential business lnlonnation wtich is to be withhokl from disclosure outside 1he U.S. GCMIII'IIIIIrlt to 1ho oxtone petmiHed b1law. Ttis document arntains Jl'DIIriet81'f, confidential, and/or llade secrellnfonnatJon "'""' Stbsidiaries o1 Swlhem Compan1 « ol1hird parlies. It is Intended I« use only b1 emptoyees ol « aL«hooizod contraaors ol SUbSidiaries c1 Sou1hern Company. IJnaub>rized possession. uoe, disttilutlon. copying. dissemination. «disclosure o1 any portion It proNbited. Repon Oate FUe Dale Page 08118/10 08118/10 70 -- ~ SoCo FOIA Response 002080 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE Ulb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) The Recipient ol Cooperative Agreement DE-FC26-06NT42391 considers the ma1ertallumishod herein to contain confidential business inlonnation wtich is to be withheld from disclosure outside tho U.S. Govefm\ent lo the extent pennitted by law. ROfiOII Date Fi e Dale Page 08/18110 08/18/10 71 This CIOCument contains proprietary, conlisid181ies 01 SOUII\em Company or ol thitd patties. It is intended lor use only by employees 01 onuthorizod allltradors 01 IUbsidiarkls o1 SOUII\em Company. Unauthorized possession, use, nf'Kien~al business information wl'ich is to be WltMatd frOm cUdOsute outsidO the U.S. Govemment to the ex1ent permitted by tow. Report Date F~e Dale Pave ~··": 08118110 n This docunenlconlains proplielllfY, sidiaries or Southern Company"' or 1hinl panles. It lslnlo-lor use only by employees of"' I!Uhoriled mntr.H:Iors or subsidiaries oiSoulhem Company. Unauthollled possession, use. dtstnbulion, oopying, dissemination, '"'dlsdo...., olany portion is prohibltecl SoCo FOIA Response 002082 ATIACHMENT C- BUDGET PAGES Budget Information - Non Construction Programs - Budget Period 1 OMB ADDfovBillo._OJ48-0044 Section A - Budaet Summarv • Grant Program Function or Activity (a) 1. Fossil Energy R&D 2. Fossil Energy R&D 3. Fossil Energy R&D 4. Catalog of Federal Domestic Assistance Number (b) New or Revised Budget Federal Non-Federal Federal Non-Federal Total (c) (d) (e) 10 (g) 81.089- BP 1 81 .089 - BP 2a 81 .089 - BP 2b Totals 5. sect10n u- uuoaet {; ateoo nes 6. Object Class Categories - 1 -- Estimated Unobligated Funds - (1) Total- BP 1 (2) $9,285,033 $14,233,607 $270,231 ,360 $9,285,033 $17,396,631 $1,744,581,500 $18,570,066 $31,630,237 $2,014,812,860 $293,750,000 $1,771,263,164 $2,065,013,164 Grant Program, Function or Activity (3) (4) Total (5) $3,769,589 $3,769,589 $159,413 $8,401,694 $159,413 $8,401,694 $6,002,871 $6,002,871 i. Total Direct Charges (sum of 6a-6h) $236,500 $18,570,066 $236,500 $18,570,066 j. Indirect Chalges k. Totals (sum of 6i.oj) $18,570,066 a. Personnel b. Fringe Benefits c. Travel d. Equipment e. Supplies f. Contractual g. Construction h. Other - . - 7. PrOQillllllncome Previous Edition Usable - -~ ---· $18,570,066 SF-424A (Rev. 4-92) Prescribed by OMB Circular A-102 SoCo FOIA Response 002083 ATIACHMENT C • BUDGET PAGES Budget Information - Non Construction Programs - Budget Period 2a §!Cuon A· Buaqet ~ummarv Grant Prog~am Function or Amity (a) 1. Fossil Energy R&D 2. Fossil Energy R&D 3. Fossil Energy R&D 4. 5. Totals sectton H. Huooet ateoones --Calalog of Federal Estinated Unobligated Funds Domestic Assistance NIJnber (b) OMB .A!IIlfllY81No 0348-00« New or Revised Budget Fedefal Non-Fede~al Federal Non-Fedl!lal T~ (c) (d) (e) 10 (q} 81.089 · BP 1 81.089 • BP 2a 81.089 • BP 2b $9,285,033 $14,233,607 $270.231,360 $293,750,000 - $9,285,033 $17,396,631 $1.744,581 ,500 $18,570,066 $31,630,237 $2,014,812,860 $1,771,263,164 $2,065,013,164 Grant Program, Function or Activity 6. Object Class Categories (I)Total - BP2a~ (2) T~- BP 2a PhasetUa (3) Tolai (S) (4) $1,460,591 $1,261,023 $2,721,615 $56,034 $1,377,290 $17.735 $18,362,507 $73,769 $19,739,797 $8,448,269 $285,386 $8,733,656 h. Othe1 i. Total Direct Charges (sum of 6a-6h) j. Indirect Charges $2,919 $11,345,103 $358,482 $20,285,134 $361 ,401 $31,630,237 k. Totals (sum of6i-6j) $11,345,103 $20,285,134 a. Personnel b. Fringe Benefits c. Travel d. Equipment e. Strpplies f. Connctual g. Construction -· -- $31,630,237 7. Program Income Previous Elfilion Usable SF-424A (Rev. 4-921 Prescribed by Ot.IB Circular A-102 SoCo FOIA Response 002084 ATTACHMENT C- BUDGET PAGES Budget Information - Non Construction Programs - Budget Period 2b MD ADIXUVC:n rcu. U.J4CHJU4Ct Section A - Budoet Summarv " Grant Program Function or Catalog of Federal Domestic Activity Assistance Number (b) (a) Fossil Energy R&D Fossil Energy R&D 3. Fossil Energy R&D 1. 2. Eslimaled Unobligated Funds New or Revised Budget Federal Non-Federal Federal Non-Federal Total lc l (d) Ie) (f) (Q) 81.089- BP 1 81.089-BP2a 81.089- BP 2b $9,285,033 $14,233,607 $270,231,360 $9,285,033 $17,396,631 $1,744,581,500 $18,570,066 $31,630,237 $2,014,812,860 4. 5. Totals :sect1on H - HUOOet ateaones 6. Object Class Categories --- (1) Total- BP 2b Phase lib $293,750,000 - $1,771,263,164 - $2,065,013,164 - Grant Program, Function or Activity Total (5) (2) Total- BP 2b Phase lllb (3) Total- BP 2b Phase IV (4) a. Personnel b. Fringe Benefits c. Travel d. Equipment e. Supplies f. Contractual $1,892,700,101 $122,112,759 $2,014,812,860 g. Construction h. Oilier i. Tolal Olrect Chalges (sum of 6a-6h) $1,892,700,101 $122,112,759 $2,014,812,860 $1 ,892,700,101 $122,112,759 j. lnt&ect Charges k. Totals (sum ol6i-6j) 7. Program Income Previous Edition Usable - $2,014,812,860 T T " SF-424A (Rev. 4-92) Prescribed by OMB Circular A-102 SoCo FOIA Response 002085 ATIACHMENT C- BUDGET PAGES Budget Information - Non Construction Programs - Cumulative ~tlon A - BudQet SummaiV 1 Grant Program Function or Activity Catalog of Federal Domestic Assistance Number {a) {b) 1. Fossil Energy R&D 2. 3. Fossil Energy R&D Fossil Energy R&D OMB ----- Aoornval No. 0348-0044 --. ~ - ~ ~ ~ New or Revised Budget Estimated Unobligated Funds Federal Non-Federal Federal Non-Federal Total {C) (d) (e) (I) {Q) 81.089- BP 1 81.089 - BP 2a 81.089 - BP 2b $9,285,033 $14,233,607 $270,231 ,360 $9,285,033 $17,396,631 $1,744,581,500 $18,570,066 $31,630,237 $2,014,812,860 4. 6. Object Class Categories $1,771,263,164 $293,750,000 Totals 5. section B - BUaaet ateoones - Grant Program, Function or Activity (1) Total- BP 1 a. Personnel - (2) Total- BP 2a (3) Total- BP 2b $2,065,013,164 Total (5) (4) $3,769,589 $2,721,615 $6.491,204 $159.413 $8.401,694 $73,769 $19,739,797 $233,182 $28,141.490 $6,002,871 $8,733,656 $2,014,812,860 $2,029,549,387 $236,500 $18,570,066 $361.401 $31,630,237 $2,014,812,860 $597,901 $2,065,013,164 $18,570,066 $31,630,237 $2,014,812,860 b. Fringe Benefits c. Travel d. Equipment e. Supplies I. Conlractual g. Construction h. Other i. Total Direct Charges (sum ol6a-6h) j. Indirect Charges k. Totals (sum ol6i-6j) 7. Programlncome -~ I 1- I - $2,065,013,164 I SF-424A (Rev. 4-92) Prescribed by OMB Circular A-102 Previous Edition Usable Authorized for Local Reproduction SoCo FOIA Response 002086 Section C- Non-Federal Resources ( -- .. .. ~..J (a) Grant Program (b) Applicant (c)State 8. Fossil Energy Resea/Ch & Development-CFDA: 81.089 (d) Olher Sources (e) Totals $1,n1,263,164 $1,n1,263,164 $1,771,263,164 $1,n1,263,164 9. 10. 11. 12. Total(sumoflines 8 -11) Section D - Forecasted asn Needs I ~ Total for 1st Year (2010) 1st Quarter 2nd Quarter 3rd0uarter 4th auarter $40,405,777 13. Federal $28,058,663 14. Non-Federal $49,384,838 $34,293,921 15. Total (sum of lines 13 and 14) $89,790,615 $62,352,584 -- - - Section E • Budget Estimales of Federal Funds Needed for Balance of the Pn:!ject (a) Grant Program (b) First (2010) 16. Fossil Energy Research & Development- CFDA: 81.089 Future Funding Periods (Years) (c ) Second (2011) (d) Third (2012) (e) Fourth (2013) $68,464,440 $167,096,572 $9,670,348 $68,464,440 $167,096,572 $9,670,348 17. 18. 19. 20. Total (sum of Nnes 16-19) Sectlon F - Other Budget Information $2,065,013,164 21. Direct Charges L l 22. Indirect Charges 23. Remarks SF·4Z4A (Rev. 4-92) Prescnbed by OMS Circular A-102 Previous Edition Usable Authorized for Local Reproduction SoCo FOIA Response 002087 Dunlap. Ann C. From: Sent: To: Cc: Subject: Attachments: "Pinkston, Tim E." Friday, August 20, 2010 6:09 PM Madden, Diane Henderson. Charles W.; Eiland, Joseph D.; Graham, M. Steve Cooperative Agreement DE-FC26-06NT42391 • Updated CostBreakdown for Phase lllb & SF424A Kemper County JGCC EPC· Startup Cost Breakdown for Phase lllb 08-17-lO.pdf; SF424Aexcet 08·19· 2010.xlsx Diane, Attached are an updated cost estimate breakdown for Phase Illb and a completed form SF424A. The differences between the attached cost estimate and the estimate submitted on April 27th are: (b) (4) Please call me if you would like to discuss. Tim I From: Pinkston, Tim E. Sent: Tuesday, Apri127, 20 I 0 9:26AM To: Diane Madden (Diane.Madden@NETL.DOE.GOV) Cc: Henderson, Charles W.; Eiland, Joseph D. Subject: RE: Cooperative Agreement DE-FC26-06NT42391 - Updated Cost Breakdown for Phase Illb •I The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. Diane, SoCo FOIA Response 002088 Attached is a revised cost estimate. Our project team decided to spread the estimated freight costs to the individual line items instead of including it as a separate line item. The attached report reflects this change. Other than a few minor round off changes to the numbers there should be no other differences. Please call me if you would like to discuss. Tim <> From: Pinkston, Tim E. Sent: Friday, April 09, 2010 3:57PM To: Diane Madden (Diane.Madden@NETL.DOE.GOV) Cc: Henderson, Charles W. (CWHENDER@southernco.com); Rush, Randall E. (RERUSH@southernco.com); Eiland, Joseph D. (JDEILAND@SOUTHERNCO.COM); Graham, M. Steve (MSGRAHAM@southernco.com); Owen, Steve (SOWEN@southernco.com) Cooperative Agreement DE-FC26-06NT42391- Updated Cost Breakdown for Phase Subject: Illb The Recipient of Cooperative Agreement DE-FC26-06NT42391 considers the material furnished herein to contain confidential business information which is to be withheld from disclosure outside the U.S. Government to the extent permitted by law. Diane, An updated cost breakdown for Phase IIIb as required by Article 2.38 of the Cooperative Agreement is attached. The cost update is based on the following: * * * * completion of FEED for a non-C02 capture case selection of (b) (4), (b) (6) as the combustion turbine supplier addition of 65% C02 capture and compression change of COD date to May 1, 2014 Please let me know if you have questions or need more information. . Tim Pinkston Project Manager Gasification Technology Southern Company Generation Office 205-992-5042 Cell (b) (6) <> 2 SoCo FOIA Response 002089 I. :;. KEMPER COUNlY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho Roc:plonl 01 ~..WOAgnMIIIIOnl DE.fC2(l..OONT42391 10 11>0 ""'""' pomiiiii!CI by bw. COI\s.lCISII\a m,ll,ltlOI 1\onsi'ICCI hereitl la Cllnboncacflden:.olbllslne$S """"""""""'hicll is Ia b0WIIll1old lnom dlsclasrtra<:o_lllf....,._ollhe suosldlal1es d SaurnomCnl !I"'IIOS. It lsrnto..,od tor usa an:, by empto,ees Cf or3UIIIOIIZA>CI~rsof ""'ei:IIIM ol 5......,.. COII Data Filo D::IIo Pogo 08/tB/10 08/18110 1 SoCo FOIA Response 002090 .. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantlty UM Worlchours Labor Material Subcontract I Total Account/Oescriptlon (b) (4) --&ofy. Ro:>«~Ootc Tl\oltoc:pentclc:_......~DE-FC2f;.OCIHT423!11COIUlCOBU'oO.,_.~fllrri>had-IDcontoonconlldcn>:llt>YsW10U""""""IoOt'I.....,. I> IObo_,_lromUOC:"""'owldult10V.S.G"""""""" ,,)0"* IDI!Io-~bylaw. Pogo ~. -~ aocn:tir.lonn:ll.on olllle ...os'c:i:>ncaoiSoo.1Nim C<>mp3nr arolliWll pan;os. tt,. lnlondoctlor usoorly by omc>~oroc>o olar OUII1cnZad CD1Ir:ldorScl -~"!py~ng, d . - o n. d:Sdosutocl ~,porliOIIIS pnoribolecl. r•... c~ocu:non: ,.mowcn. or - --- -- - 08118110 08/UI/10 z - SoCo FOIA Response 002091 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) TM R-iOOI a! CaopetoCrto ~9'"'1*11 DE.fC2Ul6NT42391 consai - - ir.!-on whlch 1:: to bo w.1hholct trDM diSC<......, oUISido 1N1 U.S. o-nm....: ">ll'e-poiiM!aw. Ropor1~ 08/IBMO Filo03to P:lgo CIII/18MO 3 This docuTiont a>ntl'ns pn>pr.al.lty, ...-:.1. llniiiWir.>IIO...,.,. '"""""""'" ol111o SIA>oidCIIIcs cl Saul."""' Ccmp:lny ot aiiMII potlios "IS lotc- for uso oriy l>y ornpleyOO< of or :MI1otllOr> ct . . . -.. o!Soulnom CG0 ~·a '"'"' a.sdos..., autsooo ""u.s.Govommont lOs-lliSoue>em Cnl~. r.i>lr.lenateltot useor.ly b)'om:Jiorvosa!or~~of Unau~nan>aa_.-., ..so. llnlnDuiGn. ClOPYW'I!I. OS!emnlllan. crcuclosuraof Ol'tf pcnonts pl1llll110011. 08/18110 DeltllllD • SoCo FOIA Response 002093 '- KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/DescripUon (b) (4) Tile Rac:;lO..,. Clf ~ ~ DE-FC26-06NT423ll1 a:Jnsccnlllo mol011311utrisnoct ID :ho....., poi1NIIDII bt l:lw. """""to ODr.l.ll1 can!ldomi.>l ,....,.,., '"'""""""""'hlcll ••10 bowi:hllold trcm ,..,.,,.•., 0\.1Sido tno U.S. Go.emmom Tr.iS aacumont c:ant:uns prcpnet3fY. ~~. ;lfldlor 1r.10et soete11r.to~ron a1' t.no ~os e1 S~1norn Company or of ChtCI pQt1kls.. 11 is ftondoCS '"' uso any by anp1oycos or or ::~ue"lo~ c::ontt:zdOno of subsialories cf Souonom Cempany Unoulllo<1Z:Od posoasian,_use·ll_•111:.bc~ft._~ing~cissemon:III0.1 "'d$doSUtO or :~nr I)Cillon •• prohli>IOG. Rcr.;:~: P:lgct 08118/10 08118110 5 SoCo FOIA Response 002094 1 ... : • - 1- KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract TCltal Account/DcscripUon (b) (4) The Rec:lpmt ol Caaper.ltivo Ag_..., DE.f~NT•2391 comlotiS tn0 moter141 ftnU- noroon Ill c:on10in ccnftOC>n:lll buslnoss lnl0o'nll:1x>lw~ 1$ 10 DO Wlf1hold 11l111l ...d.,...., o - tnc U.S. Golnto~ns pn>p~o~ory. co-m. ondlor tr.Jda -=ratJn1om\;lllon <11 tho su!>ol4onos o1 Soo1nom C0fi1>0!1Y or of nru P'ti!JO'- n ,. '""""""' 'or uoo ""'~ 1>y cmpiOJOOO 01 or :r..:nDI'I>OCI ""'IIX10tt or p. Ropotl O:>:e FiloO;r.o 08/IB/\ 0 08118110 6 sui>StdQflOS ol SOUVIDm ~- UIIOU1IlorlZOCI poNOS$1Cn, uso. disulbiA""'- copy;n;, dl.....,;natlon, or !Oscl.,...,._olooy portion a pn>IIJbi- SoCo FOIA Response 002095 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key QuanUty UM Workhours Labor Material Subcontract Total Account/DescripUon (b) (4) T h o R - at Ccopor:ltNo Agroamont DE-I'C26-0SNT-Q391 ...,_,.. 111omo1011:1 1""".,.,., -IOcontl>l e>r>n!ldorniol b"'lnem mlom>OliCIII Wf!dl 1s10 bm dosdc>Wv 10 '"""""""I"""'""'" by ..... """"'"lllo US ~ n.s aaa.cnont ccr=:ns PfO~, corfodOI"COI. :r.t!IOt tmGe sectalln!ormollon Ollno :KbSOOI105 at ScoMom Campony ar a! llltd pon!O>. "as lrt011docl for uso rmy by am:>!ayoco a! or"""""'""' oor:t-otton of I!OPJlfl D:no FII<>Dola ~ 011118110 00118110 7 suos.c.nos or Soulnom Com;>ony u....,.,.,._ possesso>n• ....,_ dlslrnUJon, copp-g. dssc!mlnollon. or diSCIOSura of ony pon;cnll prahlta- SoCo FOIA Response 002096 ,, KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subeonlr.lct Total Account I Description (b) (4) ot- Tho Reeop.ent ol ~MIAgn!OI'IIOtll OE.fC26-00NT42391 ccnsodefO NtnO!erl:ll fln!Moclllflft"IIC """"""cc:\"lll«~loal buslnossonfolm:llicnwh!al is to tlO'I•Illlhelo:Hrcm CI&Sc:l~cutS'ColNI U.S. IOIIIDOIItDI'IIpa!l'l'ltlocll>yl-. '""""'21'"'"'' Trus aocunertaonl:lino FRP"Oiatl. c:oonfclonll:ll, ..-lnldo seo:t111 lhi>Sibsicllo:Los ofSouoncornCcm;ogny crofllin1-. llls ll'ol..-fatUSO oriy t>y~oyca• of .-o~-~. ~ch1ntoL.tootl.ccpyng.~cr-of1Inf-'"I"""""IOcl ...... eo..m....,. R"r./!~ p. 08/1Bna 08/11110 8 conv.>c!D!Saf SoCo FOIA Response 002097 _.. ; ... KEMPER COUNlY IGCC EpC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/Description (b) (4) ol Coopo,_Agroom.,. DE-FC2&Wl!'42391 c:onsl00t1 tni>1113!A!IIOJ furnshod hc:"'ln!Oconl:lmaw'lf-lluSonOSSintoi!NIIo.,whiC!US 10 bowft:>."taa<:TI-OUISICo""' US. GaYamrnat& "'ThelnORoaplonl .....u po!m110CIIIy lOW. Ropano.no Fdo D:l1o P:ogo DIIIIBI10 08118110 9 This"""""""'..,...,.~· c:onloGOnc.-.:ondlorlnldo-onforml!loonolt'>O,__aiSoulnomCcm;>:lnJorcl,.,_.n;.~tor-•rJrllyom:>!-cforo~CDIItr.>CIOr>cf subSiclarles ar SOUIIWn Cclmp;lny. ~.,.,...,...,.use. CllsdiAO'I. ccpytng. dsMrM1alian. ... clsdcsuro c1 anr pci1>0r1 is~ SoCo FOIA Response 002098 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho Reoplont Df ~rawo llgrQOmont DE-FC26-06NT•23111 OOf'Siclots ono mato~l t.r.Y'I.,., nctelnosson!:xm:lticn wtucl! rs 10 1» W11111100C: from lbct....., outs:dO 1110 U.S GOYMlmOI'II 10 1110 ""'""' po~mUOdl>)' law. This -..nont a>nbrns propnoto:y, """"clonli.:lf. ;JIId/:K tr.ldo -lnfonn.>lion Dl the sui!Sidc:lnos al SoWIOm Com1>0:>y cr ot L'linl 1>'1,_, h oslll10ndocl lot uso only bJ Cf11>1orecs of or Oul!'la,_ Ctlna:I""'-'S cl suDpy•ng. I l l . - _ or CIIUIOSura al ony poniCon IS p10111!1111d R~= P~go 08118110 08111!110 10 SoCo FOIA Response 002099 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE Ulb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/ Description (b) (4) The Reopicnt cl ~vuA~ OE-1"~42391 con1l1101> tne rnotoll31...,..._ no.,., .. tne-P"f1"110dbyl:t1V. artCIO~ ......,..lt1fodosi#O o.-1110 U.S. Govommanl RCIIIQrtll:Jio Folo D:l1o P09Q oe/111110 08118110 11 Tllis-axnoons ~. a>nl'clonool, - - • leO"pylng. Oontc! CooperaMIA!If_...,l DE.fC25-06NT42:l91 c:cmidan lllctrnaiOri:lllumis- herontc axl!Oincor(lde:>:i.>J buSinOss inlonn3tlcn wt1d1 iSla bow11111-!r<>m li>c!DSUIO ido1ho U.S. G......,.,.,nl .,.,.,....,..;>OmWttoda>wlow. Rooon~>ato F"olaD:Ito Pogo 08118110 0111\8110 12 Tluo documenl contaons propno!3y. oonl'lllenb:ol. -IIOd:l'.icn 01 1ho SUbsiclr3riCS af Sa""""" c..._, or ol ll>ld ponias. Il lS -!or usc Of'dy Dr Oll'llii>WOOO or or :l:l:llCIC1ZCpying, <1/....,.NIIOn. OIIXI. SoCo FOIA Response 002101 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/ Description (b) (4) Tho Raapionl d Cooper;IIM> A_.,onn OE-I'CJ6.011NT42lll1 CZltllldotS the ..-.13111mo$llocl hOroG> to CD'\1:11• c;lll'l!idOtm.>lbol'"""' 10 lhO Olttont PQIIMIOC by ..... i-- of wllil:hls 1o bo wiVlhO!d!Rlm di>CIOSIR """'""IN! U.S. ~ This docunonl c:an!:ino pn>pnot:lrf, 01>-1101. andlo< a! 01 OUIN>R:IId a>n1t:1C1sidi.1ncs of SouNm CGrr;>ony. UNlUIIICIIUed possession,""'· CIIWIIIUI>an, f:OPI'Ing, dssom:n:Jti.., et 15S<:IO>unl >rtf porU.,.,_IS protu~. ROPOIID:IIe FUOCbiO p~ oanano 08118/10 131 SoCo FOIA Response 002102 ,, KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE Jllb Key Key Qu;~ntity UM Workhours Labor Malarial Subcontract Total Account/DcscripUon (b) (4) TneReq>ienlciCooporaiM> Agn>amont OE·F~091-rs 1nO rnolllflalVn!StiCdhon!in!o CO oiii!O .......,...,es at Soutnem ~r or ol ~ pollloS. Kos lto!ondod I« uso Of'ly bf """""'""' ol ot Wll'- CIWI1r.l=:n o1 " " - ol ScMroam ~. l.lluoult.- pMIOAIOfl. 11>0. CIISllllu- CDPI'Ifl!l. arosc:~oo of is pniNI>oiOd - ,.....,.n:o:.on. R.-D:I!o FoloD:Ilo P.>OO 08118110 08118110 14 SoCo FOIA Response 002103 - I- KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Koy Quantity UM Workhours Labor Material Subcontract Total Account/Dcscnprlon (b) (4) Till> floop...,. o1 ~voA-01\l DE-fC26-06NT42391 mmOnl to tna ""'""' pormneG by t:Jw. . R"'''ftO... F'o!a Colo p~ 08118110 08118110 15 Thl• doGo seaot inlarm:lllon of ""' ..,bsiGiolios ot Souonom Coml>'l'Y "'of tnm ponias. n ,. ttOI$ of -.......of Soutnom Cctmpon,. U"""""'nzed - - uso. GIS,..,..,_ coe>rin;• .,_noi!On, OtCidOSuro ol llrly pcROo RflCipoont of~ A;rooment OE.fC2$.a;HT"2391 cansociOt.S t"" rnoiOflal fumosnoc """""'" cant:litl conroCCni!OI ousiN!ss on~C~~n;Jtoon wlli:ll is 10 1>0 WI!Makl"""' ~ ou:siCIO 1no u.S. Govammom totnoOIIIoni~IIJI'IW TillS coa.mont cant:llno ~tory. o:r:r.~-. ~na/ar lr.lda sacnt1 .-.....oD ol "'O SI..CSidl;lnoo ol Soutrlom Coml>'ll1)' or cl IIWII pa!10IS n is ~ let uso otly by ....,.cyoos of ar Olt.t'alml C011lr.ICU>I> of Ro:>art O:lto Fo10 O:lto Pogo DB11BI10 0811BI10 16 ...-._-_oiSoWlom Cornpanr. un•~~~tnor.....r po..osslon. uso. ~·-"- copplg. ~ orCISdO....., 01 •"Y ponoon is plol1lbotad. SoCo FOIA Response 002105 - ~· • - I • KEMPERCOUNTYIGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key K~y Quantity UM Workhours Labor Material Total Subcontract Aecount I Description (b) (4) Tho ROCJPIQftl Df COGpor:IINO ~~ OE.fC26-06NT42301 c:onsiaors trcJ mserol fumiV\oa NtfD·n \0 cont:~n carfiCIOmlcl bUllnon ent:wnD~cn .,rucn •s to DO Mt"l-"'0!0 from c:tsdcstiO outs:CC 11"10 US GOYOrntTV'JI IDlnOatOI'II,......,.Uod toy I -. TillS .,....,ont cont:llns Pf0911~. •ubso- o1 Southam eor._,y Ropan 0:110 FlloDnct P"91' coni-. on'"'<1r.10o - l f t f - l a n or 111a SUbSidanas al SOUiham Camp:>"f atofl!>nl ~· n I• Int._., 1at use orJy toy employees of at OOMOitoOon..,.. - .... c1 ~ny pcn;on;. ptON!liiOCI. ·- ·- 0811&110 08116110 17 - SoCo FOIA Response 002106 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account 1 Description (b) (4) The R~ Cl Coopo,_A.,.,.....,.t De-F~42391 _..,.,,.. lllC "'"""'OIIumishod hO"'"' uo tno uurc ponmled toy ~>w. to"""""" t>usincss lnfOnn4t c n - IS 10 1>0 Wlti'Jiclcl !""" CIICIOSIR - ! n O U.S. G....,.,.,.,/11 RaoonD:>Io Folo Dalo P:>ge ~~gl 18 Tt'la& dOCument ~M ptOPf'Ot)ty, eot'fldentlaJ, .3ndlar tt:ldo sec:mt ltt'!otm:ltcn af 1ha 5Ubs14:1nos r:l SOlt.t:c!m C~ or ot tf'l.rd pai1:)0S. It is ireon:lad: for ~.:sa cny b~ cmpJoyC!GS ot or ~ot'IZC(I =~"' of sullso43nes of Sou:nem Com;>any U~ possessiatl. uso. - · ~- dWoml-. Of Gisc:lcsllo ol811y ~IS l'fOI!blecl. SoCo FOIA Response 002107 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subeontract Total Aceount/Deseriptlon (b) (4) Tno Rnsldcn !110 rnmcnollllniShod hOroln 10-., 10 thO ponniiiOd by ..... l>usftss 11110mUrton wfloth IS ID bo """"'*'l!ml cSodosuu """'do lhO U S. G"'"""man ~~ POliO OB/IB/10 011118110 19 This dCIClmol'la>nblns ~""~>""""Y· l, ai'Mllarlr:Jdo saartonl!:rm::IIDI'Iaf tllosubold......,. af Sou:t-.em C..._,y"' a f t t l r d - nos lnloCII'dedl<>r uoea~ by~ ol or...,ont$01 """ICIIOriGS af Soulnam ComP"nr Uti.'IUIIIO,._ paasas&tan. uso. GISCJID.-;an, copy~ng, Clo....,.no.an. ot eli-.. d ony porllon IS~- ------------------- - --· SoCo FOIA Response 002108 ... - ... KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantlty UM WorlsidOCpossossocn. uS~>, eiOtllt>t-.. copying. dlssomlnaon, orOoSctcsUtG "'""",.._Is~ T h o s - ..,..,,. pnllllll>lo:y, Rapat03UJ FiloO®I Pogo 08118110 08118110 :!II SoCo FOIA Response 002109 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/Description (b) (4) ThO Rocioicnt of COopoi1IIMJ A!11X>mant CE~C26-06NT4ZI91 Cli>IDidan 1ho mr.enaiUnshod heroin lz> CDf1!oU1 a r i - busnou Info'"'"""" wNch is 11> 1>0-r.ct:t '""" Olsclo•.., o-lllo U.S. G......,..,.nt IOIIlO-"""""""'t>ybw Ti>s clocurroorol canta;ns ~. c:anfidonll:ll, Dndiartr:>dco -~~ ol ono suboocl.....,. of SOU!Ilrcl patlies. ~is on:orGCclloru>o oriy t1y omplsuooklo;Jnoo OISOIROOmCompon,. Un:Jr.oCnonzc~ ROC>CiriD:IcO f olct Dolo P"9" C&l18/10 C8/1B/10 21 cf"' lliJIIIOII%0<1 ccn!niC101S cf SoCo FOIA Response 002110 ,_ KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/DoscripUon (b) (4) TI'IO IIOCIPICI!t al Coq>ooUivo ,._.,,.. DE·FC21Ml6NT42391 a>ns-rs 11'10 "'*''::lllrnisiiOd hDRM lo con~:~n .,.,.._,.J:ll busonou1 -wncn IS DI>O wnmald fnm dsdcn""' OUlsidolho U.S G.....,..,.. pam'i1led Dy law. 10 ,., - ViR!-. Thrsdoamor4"""""" .._b'J, - · - - S8a'Oiin!ofmlnan01111o llb>idiOnas OISoucr.nc...._ oro! ft is ...-.leG r:.rusecnrDy """"-01 .. s - . 0 1 - ~. Unal/.hOI'IZIIII posseuoon. uso, al!rlbUoon. '"'11P'9- ctsscmn:>ton, ....Sde>SI.n of ""fpcntOnOS ptdln of flOS>OrtCal<> Fill>~ P:>gc~ 081111110 08111110 22 · - - SoCo FOIA Response 002111 '. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subconlr.lc:t Total Ac:c:ountJDescnptlon (b) (4) soaot-.. . ,_.. . . .,. -·-·-""Pr"!l·-- Tno ROCJPent cl ' - " ' " " ' A _ . . . OE-FC21>WlT42381 ..,.,..,... tno m:llemol- t>atuinlo tcnUlln ~Oti!IOI-.slnlor!Mtia'l wn·ch is 10 bo .__,..., ctSdOs..., oiiiSiclo 1110 U.S. G"""""""f'1 to l h o - poonlod.., .... TtomCon!pony. Uno~ Rooon Doll! Fllo D>-.o P>go o1 Soutnem eon_, ot of 111111 - 08111!/Ul 081111110 23 · n is...,_ for""' en, bJ ....,._ 01 .,.. ....ocnon:o.: c:cnw:x::rn o1 ototCIOS>n«,.,pohod hoto'n 10 conlllin corti11enU:11 Duslrless~w!lodlls10Do...:ni181G""'" a.......,On!JI'L'1101. ~ ,. ....,...,,.,. ....,.,.,.,ll'f~ ot a ~"'""m=nor SoloperoiiiiOAg"""'""' 0E.Fc:IIKI6N1'42391 c:anuloi111'D,_>I flni!SilOCI~...,..to Cllf\IO:e cortoGnal busi'>ess lnf011113110nwt11Cfli$101)0W11I'Ili>IC!Irom GISCI.....,OUIS:OO 1110 U.S. G0Y0trvnont to 1110- ponntted by l:lw. ....-ntot. This"""'""""' n1 pot1ios. n 1$inl""'"" ror use only by oiTI'k>!IIOS at or--~ Ci' outostdbriesatSouU>emeo.._, u n a - . . s -. uoo, dtSIIll>IAtoi\COIJYII'9.- "'"'sdoounl o!a"Y _ , . prchb!Or:IIMI " ' 9 - l DE.I'~NT42391 ecn$ldo1$1h0 t1131e~ol fl.msned non>in lo cantaln ID'fode!t.l:>l buSUIOSS· -wtodo is 1:1 bo W!lllllOid fran cUdosurv OUI$C:C "'"U.S. GCNOmmorot .,ano 0d01111)(1(111i11Gd Dy low. RaponO;no l'llo 0:>10 P:lge n11s 110cument c:DtU.>ons ~.ID'f-. ondltWtr.>ciO $0CI'OIInformollon of ano· -rJISoo.llncm Compony «or 1nn1 Pot,_ n ,...,..,._ '"'""' otlly Dy Olll'loyac< ol or """"'nzod contr.I<10tS ot .....,.,.,.,. orsou-.roomCom;l:>oly. u~-. uso, a~s~r.-. ""1'1""9. cuominoton, OfdtdosurDCII ony por110n "pra~>~a.ao~. OSI\8110 OSI\8110 211 ---- SoCo FOIA Response 002115 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Worlchours Labor Material Subcontract Total Account/DcscrlpUon (b) (4) oe Tha RecJpent ~MIAgreetl*l DE·F~42391 "',,.., e,c1en1 ponr•aod by t:>w. _ , . , . , ma10natMrisnocl noroon t.oeot1COI.•a>or- t>~~Sinass illfonn3tenWI'CI1 is10 DoWIV'Mtafn>mOiutooure.......to 11\a u .s. G....,..,.,. TM docunonl conblns propri1113ty, c:onfoden,.., ondlor . , _ -ln!am>G1cn of 1!1<> SW.tcli:>,_ a! SGU111om Corrpony <11' of ll>rd p:111<1s. t1 Is lnlonclad lor usa only by orr.playocs o! or~ a>nttoeor> ol SUOSICIOOIS a! Solho,.nzonal kmiS!Iey ""'· 1.., .........,,.. conl3ins propnoc:IIY. - · ...-~r:x~a aoaa onl!lnnOIIon <11""' ..-ar1as"' ci$CioSU111COIISiOO tllO U.S ~ 11.-D.>tc Ale O::.:o ='.1!:0 08rl8110 08/18110 211 SoUINim ~or <111hr.l"""""' n •• inlendea 1oruse any by Dfllllloyoos o1 "'~ a>ntr.>aot'S cr ...-OiriasotSOUihQm~. UIIOUU'oannldpotOOIIIOII, uso,diml>ulian,l:llflYUI!J, Iliuomin:IOOfl.oraJu~oS~noa!onypcr;onts):RIIII>IIMI. --- SoCo FOIA Response 002117 ,;,;; ••• 1 .. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Mawrial Subcontract Total Account/Description (b) (4) Tho Rod!>conl al Coc>;>ar:>IM>A'J'VCirnont 0E~C26-06HT•2391 CONid~ IN INIWlalfumlsnOCI IIOIOUIIO COIII.OIO ....-,al buslnoss infOriNI>On""""" IS K1 l>o - d " " " ' ltSdOIUfll CU!sldo Ina U.S. G~ ............. ~«w. -·-of Repcn 03lo Fole D:l1o P•go 08118110 08/18110 29 T... ~~~.-IIIIOI.III'IdiOrlt:IGOsoaatOniCim\OilonollhO-aiSoulnOniCDII'I'I"'JctOflhn!p:IIIJQS.UISf!IORiod!Dt""'""'tbycmpiOyeoscfOI'aulnOIIlt!CCI>nlr.l_,ol SmmemCcmpar>J. ~~ uoo. - · c:cpyw~g. ~ crdlsdosuntal an,-0. pn>llilnld ---- SoCo FOIA Response 002118 -·· . - 1 ... KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Matorfal Subcontract Total Account/Descripdon (b) (4) -n. ~ R~ent Of Cooper.n:wo Agreement OE-FC26-06NT.Q391 con~ tho matort~ fun'\lshOCI ~to c:at'I&OI~ ccnhe~l busn:rss 1nfcrmoatcn whd\ is ta ba ttnthha:ld I rem OW~ outsldct &no U.S. Go\lr:m:nont ID tho OoiUitll petmi110CI Dy l:lw. RopartOO!l! F1l0 Dolo p~ 08118/10 08/11!110 :lC TM GOc..n'IOnl COIIl3onS popnet:~y. conlidentlal, onci/Dr tr:ldo i n f - . . ot 1110 -..ncs a1 So""'om Co"''>>ny or oltr>td portiO$. It is inlondocl for uso odr Dy Ofl'plo,oes of ar OUI!>onzccl Qlnlr.JCICtJ ct sutlslci;u1os ot Saulnem Compony. Un:lulllarized possmsion. uso, tcpying, lissanit1:1lian, «IIISCiasln porloCn,. proh:!Jied. al""" SoCo FOIA Response 002119 .... ~. r - •a ~ ! KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb I Key Key Quantity UM I Workhours Labor Material Subcontract Total I Account I Description (b) (4) Tllo Roo;>""' a! Coopol:r!M> Agroornom OE~C26.QINT4Z!91 r:on.-,.. 1toe "''"'""'llumished hemin ta da ICCI1llln!""""""" Gl thO S\Si~!Oncs or Sou:necn Comf::onY or olll'ira _ , , os rn:ORlOC 1or...., ~1 sui>Skli:lr.es or SOUihom Comp:ln)l. IJn:luChon Is l'fOhil:l- b)'""'"".,.,.. or Repor1 Dale f •IOO:.!D I':>IJO 08/18110 08/18/10 31 or OUli10f1ZCd coniJ'OCIO<'S or SoCo FOIA Response 002120 .. 1• • - . .. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor ~terial Subi:ontract Total Account/OcscripUon (b) (4) by-- T,., Roaoi..,l ol ~rai!YO -'llfOOIMIII OE.fC26-Il6o'lf42."9\ - r s tre mo!GfUIIutmhc•ll>or"'" 1o """""" a:r.r.,_ol bptai1Ctl""'. of a"""'""""' colllr.ICIOrs R~O.:a FIICill:>lo Pugo Oll/UI/10 08118110 ~ a1 ·----· SoCo FOIA Response 002121 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total AccountfDcscripUon (b) (4) TJ\oROCJp'Grlt otCOapora!JYOA~ llE.fCZ6-Cli!NTCZ1!11mnSIIIers lh! rr1318n;>ll\nlshedll0n>in1o a>nt.lonan'odIS .,....,_ ..,.,.;ns pnltadln cl SUI>&I- of SOUihOm Compony. UtiiW1IIof1ZI>CI d.-...n, COj))'I"'J, dt>...,..na"">. ordlscbslnl ot""" pctlo:cn is pralliblllftlllurmtol hom!n ro nf~ ...,., •• 10 bo WIIMOicl hom 10 ti'C ......... bw """""'""by T.,.dOCUTICII!........., ~. COI'I-. OIJIS\CO "'" u .S . G........,..,. RCIIOOtOa10 Folo0.10 Pas;e 081111110 011/111110 34 onelob'lr.IOO secR!Iontorm:IIDno! INIS&.Csldl:lnaSG! SoulhamCy ~crf "'a...........: conlr.ICIO<'S or pattion Is pnlllot>olod. IU-c/5-~ ~pououion,UM, ......,._ CCII>J"''J ~II.OIGIICIGSUIII olony - SoCo FOIA Response 002123 '· KEMPER COUNTY IGCC EpC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Aeeount/Oesenption (b) (4) ,.,RCCliJ!«TTemolooni>l~notJbw Tlld GOa.mentcon!allls -""Y.a n -. ..,_tr.lde seau!orlcnNIIcn 011110 SU11>1Cior1csol Soulr.etn ~crOIII'Itll ~ II b . , . , _ lar!ManiJ II)' cmployoos CJI"' ..~ -.COORol U"""""""' pos-n. uoo. GISV>DI&.CIIl, ~· al-on. Ol'_dtoCIOS'QilllliUld. Roc>colD:IIe F'tleDIIO P"!JJ 011118/10 011118110 35 ~ cl Soulllom CDmFIIIY- SoCo FOIA Response 002124 I . KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total AceauntfOOScripdan (b) (4) Tlle Ro<:opoentCIICoop«::ING~ OE-I'C25.aii'ITQ.J91 cansiclor51ha rr.alc!!1•11umallallllerlll!\ toCli:I'OIIanclonli:JTir.15n>A in!orm;>te>n Wl'ldl IS ID be Wllllholdlrcm 6sd.....O OU!$1d0111e U.S. GCM:"'"""" lllli'C!--odby~. Tru-conl3!no_..-,, ~~~. """"",_aoc:nnlnlonl13oonol""' ......t.orics of Sou:homC<>mF>ntor GII!wd I>'Jflios.ll1> ml8r1doCI lot use ~oiSOUII>OmCornpeny Unoollhonzod...,._...,._ use,- . ""PJP"9.CII<-. arddclosuroal :nypor.oonos- ..,Dy llf!'Diorooso! Oe/18110 01!1111110 RQIIOI\ODII: FilO Dolo POQe 36 d - -~ -- SoCo FOIA Response 002125 _.•.; *" I- KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE hlb Key Key Quantity UM Workhours Labor Matl!rlal Subcontract Total Account/Description (b) (4) Tho R-ent cfCoaper:JIM>Agnx>manl O!!-FC26-06NT42391 canSiders lho - I funn- homn 10 c:onl:l:o 10 lho ..,..,. poi'II'WIIod Dy l.>w. RCI!)Otlll;Jfo Fllot:bl8 P:u;o Thuo-..montCDn!I:OnS"""""""', - 0 1 . -ltOliO _ lollt>sia::mosCJISou'J>em~. ..,..,.odo,...l>u,...,.. -=oion wn.th 1010 bo "'lt't!cld !ICm CUdos..., OutsoGOIIIO U.S. Gcoicmmoc~~not ~ 1$prollG!ocl lJnau3lOIIZod ............. uso. CllmbUion. CIJPIII'!I.- ....,_......., SoCo FOIA Response 002126 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Matarlal Subcontrac:t Total Account/DescnpUon (b) (4) Tlla Rocp""" al I:Gclpat:l:iYo AgrDOIIIOIII OE.f~q39\ cansiC!or.. INI m310n:lli\Pnlshod ....,.,,. """"'" oo.-t'od....., busincm 111!4tm¥ion Wllch 1>1D bo wie!.'>OJiow R~&:: Pogo 011118110 0111111110 38 Tli&S"""""""'CC1f110:11Sprupriol:lry,c:anl-. -tr:JaO-"*""""""ollnD~ciSauhmComc>o:lrcralt"'td,.._. ni•lti:Ondodloronooo1yi>Jornplgyoo$o1otOUinoRZDl'lM>tocl. SoCo FOIA Response 002127 ,_ I I KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Worllhours Labor Material Subcontr.lct Total AccountiDoscripUon (b) (4) Tnt Fleo;>oent of Cooporocioo Agroomcwu DE.fC2!>Wflol2391 ccruidon to tho """'"'pormi11Dd Ill' l:lw. tho,_,.,, brisi>Od hoft>ln to """'"'na r l - ""'"'"'"'ntarm:nienwllch os 101:10 wilnholal""" tlscl......, OU!SICIOI tna U.S. ec-..mrnon. ,_,.,"'""'....,_of Ro-O;r.o Folc! Do:o P>go Ollt1Bf10 08118110 39 T,..otocun0111""'""'"" propt~eU~y, con!oaon!IOI. llftd/Crlt1>cloSouthomCnY UIIOillllofl:eel possession. usct. d-en. ~no. - " " " " " - ot c1osc1oouto al >ny ponion 11 proloob1ocl. SoCo FOIA Response 002128 I . :... KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Koy Key Quantity UM Workhours Labor Matrrial Subcontract Total Account I Desc:ription I (b) (4) ThoR_,.of~,..Aur-DE-FC25-C6~Q391...,_,.the,.,_.......,..,h....,..to..,..:>!n-!JuSross""armatcnwNtllistobO-fnlmDsdos\.n!......,.lhoU.S. ~ IDII'Oex:cr.lpc:mwtiC>dbytaw. '"'""""',.,of «of"""'-.__ nos..,.,_,""...., en, -·«-...val""'',.,_,.., Tnis doclmonl conlaonS __,...,, - · oncuor-...,., tno _ , . . . . , . c1 SO:nt1·namn~""""lbusinoultllolmo1ianwl1ichiStobew:lllllllldlnmdloc;!OSUV-It"C)U.S . G""""""ont to tho o.lanl pannmad by ,_ P'""'' Roporl~ F'oie D:lto P3go 081111110 011118110 41 TNs oaanont -..s ptapriCKOfy, . . , . . , . _, ondla'lr:>clo socnn in!onnolien 111 l:lO ~ 11 SouNm Company 01 dftNI!I his 11'11ancseG lar use Olfy by omployocs Gf 01 • - ccn:rac:101S at - 0 1 $outnam Ccmpony. U,.....,....., po...tlllon. uoo, ~imbo.tlo1l. copying. cwnside!s 1ha """"""' fumisl10d horon 10 eanlllin con!iclt!nlloll>uSinou ~ w!oic:ft is to ItO - l e i lrom d.sd....,. Oo 010101'111"'"""'"" by low Ropott 0010 FUoO:J1o P.-.go 08/18110 08/18110 42 Thll -....m contlins propnOI.>Iy. co-..., :JIIIJJot"'"'a aacral ll1lannllloon ol !he ...... . - of 5.,..-., ~"Y oto!ln.rcJ p:~.,;os. lltSintondod !:If USO only by "'"""'JOOS ol or~ a:tn1IDCIOIS of sut>sleliOnOS or Soulhem ~ Un.wtl1ori:oct pooseu~on. uso. -:..Aiot1,_<0Prli'G. -..rn:na1i0n. or 01 •"Y penon is~ aisdOiute SoCo FOIA Response 002131 - - I., .... KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho Roapoant d Cooper.IIMI A,.,..._ DE.fC2&06NT42:191 c:amlclor> lt.> m:IIOnaiiUmi>l'al h'""'" ID ccnt:Jln- tluSinCSS '""""""""' w"a. IS ID DO "'IMOICII""" CIISCI...., OU!SidO tno U.S. GOVO'MIO<'¢ ............... - b y b o l. Ro:><>'IC;J:o Fllo D:>:o Pogo 08118110! OBfll/10 43 T M - ..,...,.,... propnotaty, c:antOCIOniiOI. -~ socrot lnlotmalioncllnO SUI>sld::Jrios d Sa&Mcm Cc"-'Y or cl lt>rll p>r1> Dl or :a:rmr.- a>-dln cl subsi~t pomoo;. prl>hil>llld. -·usa. SoCo FOIA Response 002132 '· KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/Description (b) (4) Tho Raa;>ont of~ Agrocmon: OE-FC26.c6NT ol23lll cons"''" tho m3kl!bl furniStlasslnlcrrr.:ll:on wfliCII.S 10 £10 WIWIOIII!tan do...., "'"'"'" tho U.S. Govcmtl'...., 1o lhO exiOtll penM!ecl by 1,.,. TM Gocumcnl conllino pn>prla'JitY. oonQdonl3t. ondlortnlda......,. '~"of IN> suDs"''>'Jny. ·- ""'P'oroa• of"' :IIMOftZOtt ~or Ropart Dolo File Date P."J90 Cl!l111110 081111110 .... ···-- SoCo FOIA Response 002133 .. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/OescripUon (b) (4) Tho RodpGnl of Coopaf:ltM)AIII'OO"'ont CE-FQII.06NT4;z:Jgt c:onoklcnono m3lGrt3l furrnn"""""""'" -In-~ lnf""""~"" wllochos to bo..;o./llloldlrorn r!O,_O.,.ICIO tho U.S. C"""mmont 10 11110 o.tent I>Cfm!IOCI by low. <1- ar ....- Thlsnbl:1s ~ - · , _ . , . , . _ ct -~ O.~ by""""- ct .,.._rrzod_"' FlOI>Crt tla1o CBit8nCI P:lgo .(5 FllCOolo C811811D ~- SoCo FOIA Response 002134 .. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description I (b) (4) Tho R~ d Coopoi;Jiiw ~ oe-FC2fi.O&NT"2391 conslders11'0 rnoteiiOIIumi>had hen> n ta c:on~:>n m~odonti:rl 10 Ire D l e n t - by tow. ondlorttMG--"' t.vs•,.,.. infofln®On wncn .s 10 ~· . . . -'"'"' ltsmmonl ~o- F•lo Oo., P.>go 1)8/11110 Cllllll10 4G Tl1il docum""' """"",. _.,.,ay, canOoldQilOO"' SOUiham Comsr:>oy ot of lltnl p.o,os. n tS onlondod '"'""" mr by omporees of or :llJII10IVDd CllftiiXIOI'l err subsGones llf SoUII'em~. I.Jnaar.l1onze< possos..,, usa, dom.._, ""Pf'119. 1:1~ cr eosdosure d.,, pcr:ion is p!Qhi:.ted. SoCo FOIA Response 002135 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours labor Account I Description Material Subcontract Total (b) (4) ThoR_, of Coapot;IWa Ag1-..n1 CE.fC26-C6NT~23V1 ~ t11o ma!On#l tutnSNll n"""" Ia oont:11t1 canl'-llus:r.O$S1~.., wt11e:1 IS10 D 10 1"" _ , pomliaeOny 01 or tnlft: ""'""· 11os ttUonaoa far u.., OIVf D7 ompl<>yuDI, COPJ"'!!, -IW.......~ wflll:h l• 10 101no_,..,.UOCII>11"" 1>0_,_ flail dl>doouro CIUISide lha US Gc.o11on1 """"""" pro;>nCI!;Iry. a>nfljgntiol,nrldiOC"""" ...aatonDm:Juon ollho SI.C>Oid>:lrios 11 SeuiNm C<>Jil'3'1Y or ollhn;t P alar .>u'.not=d can1r.ICtDrS ol ~~,.,. 01 Sou!hcm ~- IJnoUII!onzDd poSICIUIOII. ""'· aiSIO~>u~ion. - · 11 tJit'f potllon;, pt01lib1ad. R.-o:no F'>la 0.10 Pogc DB/18110 081111110 oC8 -- SoCo FOIA Response 002137 - '· ~ ~ KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subt::ontr.~ct Total Account I Dosc:riplion (b) (4) Tho Roa;>lenl ol ~r:IIMI Agraemenl OE-FC26-06NT42311\ 10 1110 CX1CIII pct'IMIC!lllainS ~.-Ill. -ll'ldo ...... ift'Of!ll:ll:on Oflho --.osOI So-JI!Mim Coii'FI'fOI Of ll>rd p;~nios.IIIJinlonaoc! IOrUSOO~ Dy ompiOyeOS of Of OIJIIIOIIZDd conlr:ICIOI'$ of ...-.as cJSGul!lem Comp:my. UnaAnoltzet.pori>Otl o ptOhlmcl. 081181\0 C811811D ' .g - SoCo FOIA Response 002138 KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) Tho Rocil>lonl ol Coopo'•es.s orll......oon wNch is 10 bo '*lt1111Clcl from Cl....,._ Ou!Siele Ina U.S. c;....,_'I\Ofll 10 1110 o-.. porm~~~oa by IIIW. SOJ- Tt>o• CIOWmOilt ~IRs~. cortlcl""""\ a-lr.llle soaatlnformol.lon ol 11>0 51.C>Sd0nos ol ~ C<>onp:~oy or of 11\1<1 pa,_. It os""""""" 1ar uso only of Ccn>pony Ut\3l:llonzod pauesslan, USD, d:strtbUI!on, copying, OissofrJn:ltOII. or diSdosUnl clony portion IS pttftl>rta4. s.x-n by.,,._ R~O:lto File D:l!O P:lgo of or alltloll20d con:r.a""" of CB/18110 CM811s81 SoCo FOIA Response 002139 - ~.. I - ~ 0. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/ Description (b) (4) ThAgraomontOESCli>-06NTA2391considersii>OII'.aleitiiOCOtl'oOinc:ol'll'ldol'lll3l-.:nfcml.>ton-ISIOI>ewiV'.r>e!di"""OOC!......,outoi'*>lhoU.S. G......,onl 10!111!-"""""""'"' -· T h : o - a>nlains p-opnocary, "'"'''""~·and/Or ln>llo soet01- ot ll'.e - . . s o ! So""om ~ orollhn:t pa~. 111s ...-tor.,. or1r 11y ...,.I'IO)'oos ot or ....,onzed a>ttD-"'Swl..._otSOUIIIOm~. ~-lon.-.llislnbulion.~ng.di-,,..di-....,ctQntpon!OtllspCo - -•iOn. is"""""'""'· SoCo FOIA Response 002141 .;.; I,~ - t. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhoul'$ Labor Material Subcontract Total Account/ Description (b) (4) Tho Reciplcn! af ~ Agoomont OE·fQ!i.()6NT4Z391 consldon lho ,....,nol fumisllod - 1 0 tvnU>n CGnfldcltlliol buslni>SS inl"'""'"o.1wllic.1 is 10 be wn.'>.'lold tnm dixl""""' OWido 1n0 US. eo-nm0f11 10""' """"'' peiiMICld by~- Fl"''CrtD:IIo Fila O:no l'l>go 08118110 0111111110 5J This OOCUMnt CGRtlins propi>O'tli-- SoCo FOIA Response 002142 '. I KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Wotkhours Labor Material Subcontract Total Account/Doscription (b) (4) Tho R._..a ~voA~ DE.fC26-0&N1'42391...-111hom~ lumlshadhl:n>'n ta "'"""" ~"'bus.,.,.. -whoc:h os tabowii:Ule')'IOW Tllos00Ciof!10tl1""""""" P'OPfl--r. - o f Soulham ~ cad'-....-.,_ Rapanll:Jio Fllo Do'.c p~ 081111/10 081111110 54 -lllfonn3:ion c1111e SI.C>Oiai:ltles ol Souwm COI!1P3"Y oro!ttml parties lt ts tniO:ldad forU>8oriy I>)'~"' or o.manzed =ntr.lctOrS aJ ~pos...soon, uso. d o - copyrog. d......,..-,, ctc,.Ciotuntol :my par110nio prol'll>tel0 mal01131 lumlsnect he""" 10 CDII:m CO'Ificton>:II-'OSSIII!t>tm3bon whicll ,. to be wrthnolct trom ctSntiiM-net>ty. - · " " ' " ' " " ' " " " _ ; - . , oltnosubsid=-otsou!hom Companj orot tttrdporllos. nos on!orldodloruso on11 by amptoyoos ot or oo.Mo<'.:ud COinlr:ICIDrS ot ot So1111lemCcmpgny. U - posoossion_._uso. ctisV.:O.tlon. <0Pl"''9._c:isserninatot~. or ctsdosum o! anr pcn;on Is pn:l!i0.1OIII Cll Cool>or.lll"' .._o.--n OE~Q6.C611Tqm consid~ u.. ta.,.,exteniJ"'""'Uetll>ylaw TillS_.,....,...,,.. pn>pn0131Y. """""''furnsllocl t.OfOiniO """""" corf.oon:lol •uoltiOO$ ,,...,.,_whicn;. ID tiOWIInheld !rom cbdosum oonsie!o !ha us. Gavem""'"' :IM/flctr.lllo SOCt<'l •n~ ctf 11>0 sut>SoaiOtiiiS o1 Soutnom Compony OUthor.zcd contr.~e:on of SUIISI- Ol So"""'m Compony. U_,._ possessiOn, USO, Olstn....,.,, copying. ct...,.not01\ C P"90 08118r10 Cl8118110 56 -~~~. SoCo FOIA Response 002145 - ;. J ,;,. I .. KEMPER COUNTY IGCC EPC I STARTtJP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account/ Description (b) (4) Tho ROOJlOI'$ lt'(J mmarbl...,._...,.,.,.,. "'"''"" cartoo~ IIUSorlrss inl. .....-wndlis .,bow-rrom-MUtOOUISICIO 1110 U.S. Go.anmont lDII'GOIIIen1-odDylaw. n.s"""'""""' contoins _...,_ contoonD:II. :nJJottr.ICIO seaulrtrarm:~~lon ar..,-.,.,. Dl SDUI!wn c""'*" or ar 11'1111 polt!OS. ft •• ir'llatdal:l:lt...., oniJ 1:J ~oos a1 or .:r.t1'0tltGd =C1DtS of subSoeloOtiM 01 SCUII!am_(:GmP:InJ Uno~ ,...........,, use. dlllr.I>Uion. copying. "'-'""liOn. or lloK!os:n of •"J portiOn 11 ptDIIolillbCI. RQIXItiD>'.O Fllo 0.:0 P:lge 08118/10 08118/10 ' 57 : ___ _j SoCo FOIA Response 002146 - ·· · _ ... t .. I KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) ThoR- arc_......~~~ OE.fC2e-06HT42391canoldor$1h> ""'""""""""hOd"""''" 10 cont:ancxlt<'- DeOlllenl~bylilw. ,.,. dacl..monl conl:ansi'I'JPnol.:rf. conr.ccr.liol, ondlcttrlxlo """'"''l'lformollon ollle s u - 01 s-n Comc>30J orotll'ltd pot!Jes. ~ IS inlollIIY-~ alssemnotoon. ordlsdosi.ID 01 ~ PQ'IIon is pn:illrllrtod. RopottO.... FdoOoiO P:>go 011118110 08118110 5e ·- SoCo FOIA Response 002147 . ... .;~ l - -- .... KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Koy Quantity UM Workhours Labor Material Subcontract Total Account/Description (b) (4) 1,., RecipiGnlaf CoapotQIMt~OE-F~423~-.,.. •..,.,.,.,..,1 lln'l:ohod- tot:albn c:anfodonlolbuolnO$$ tr.!...,..,on wnch I$ to bow:llll>olatrom CloSe!......, OUISIOOV'oO U.S. G......,mo:'ll tolll08>1«11 potmii!Dcl bylaW. Ropon D.lll> FIIO D.lle P"!!O 0811!110 08118110 5'3 lnts.......,Ofll ~ns pn>pt>OtlfY, COI:IOietiUII. .:rocllarlr.IOO....., on!ann:l:ln:1 po:~~es It'' lft01lded tor uso any by employees ot 0 1 - contratiOIS Cl s.bildcll1es"' Soutnom ~ny. u - _.,n, u s a . -. copying. ds.sernkl:lbor\ Oam..,. DE-I'C211.o6NT42391 amsldors tho """"""1 fumshocl """'" Ia cant.ain ccrftctonii:U bu>cnoss ln!orma'Jc:n- os ID b o - '"'"' dadosun> aul:.,~a lila U S . G"""""""" 10 tt>o e>e~em ponnuac Ill' loW. """""""for""' only by omc>lo,ecs of or ...,.,rizod -lr.lctors c1 Ropanl).llo FUa Dolo Pos• 08118110 08118110 60 Tni$ doct.mont ""'!:>Ins pn>pnellll'f, CCtlfodo,..., ond/of ,,_ SOCIOI on1omlo110n of tho 114>$odQI10S o1 SoUI!lCm Cctr>DO"Y cr of l'>rd !NIIloOS. n ;, SW>slIatan. CC!>Jing, - · any per-..on is pnllliolltld "'"'"*"'""of SoCo FOIA Response 002149 . . .. ...... . . KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb I Koy Key Quantity UM Worlthours Labor Material Subcontract I Total Account I Desc:riptlon (b) (4) an4'0. .t.,_-u--· Tile Reopoenc 01 Cocpefa'M A!l'"fl'*ll Dlt.fC2&-015N1'42391 ......,~,. mr.enll IUtnSI!eyl:lw. 1rws CIOCUnenla>nCoons cropnola:y. contodlnll:ll, ,_.,Sautham~ wtlll:llts 10 co ...,ooa 110m diode>"'"' OUISiclo tne US. G.,..,.,llle!t 01""' ..-..,. ol5ouo1a:n ~ ort11 IMl - · • to .-~or uso Crly t>y """"-Con,~ diSSC>miiWiian, ordiSdOSurl ol•ny-tS prono-- om;>._ Rtpo!IO.IO 08118110 FIIO~IO 08118110 Pogo 61 ol or OU1I'oOIIZOd ......,_, 01 ------------------------------------------------------·----SoCo FOIA Response 002150 - .. --- ' .. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account I Description (b) (4) 'Tbo Roap;arotciCOCpaf:>JM>Ag""""""' O!;.Fc:s.oeN1'423itl consiclms tno rn:mri.>l "'"""'""~....,.,10 """'"'" """"""M.OIIIu>inosslnfOmiO!ICr1wnoen oSIOboWfthtWJidfrcm disdas""' oUISodo 1ho U.S. GcM:mmonl ID lt1o ..-.1 po/'11'111011 bl' bot. Report 031o F.lo Da"' Pogo n .. dOCunanlCGIItllns pmpnO!:Iry, tanlxlono;J~, ondlat11D0a s-of-Co~ 08/18110 08118110 62 inlonn:l!lon of.,. subslciiOtiiiS of Soutnorn Company or c1 !ll'ta pot1ios. 11 is llliO:ldCflilll1od SoCo FOIA Response 002151 --- -- I • KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total Account Description (b) (4) Tho R........ of C - - "groomOtll DE-FC2!5-06NT4l391 eonsiclots 1hO mo:on:!l ,.,......., I>OfOn 10 oont:lr" OOilfoOo~ 1>uS0t10U info'"""""' wniOII i> 10 CO wiL~""'d frotn d.~ oUISiclo ""'U.S. GovommorA " ' " " ' - po!m:lllla byi:Jw Tnos OOCU'nlltl1 c:ontlons ~- c:oniiClCtlliOI. :>tllllotlllldo- infllrlnabOrl or t10 s.I:Sidi:ltlos <1 SOuenom c;or,;oony 01 Cf l!1ltd P'lf1JOS. n i> in10tleod tot use~~ by omplayeos 01 c r - cotllr.>do1$ 01 subsldl3nasO!Sou11wnCompony, U , . _ ~n. uoo, - · COI>Il"!!· ell.-, Otcii-Utoof onrportj011 10 pn:ll"ibolod. R"'m&:: PO>gO 081'111110 08/115f10 53 SoCo FOIA Response 002152 KEMPER COUNlY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Koy Koy Quantity UM Workhours Labor Material Subcontract Total A~countiDoscription (b) (4) The Roc:iplenl o!Coopor;llrvo A!;n>o11D11 DE.FC26-06NT~I cons:oarsllla m3IDn:lllurrishod """""tocor.I:II10Dtlficlontd Cuslnoss in!orrn:l!ianw~ is to bowii!V!old lramdlsdoa.nlcartsldtl IIIOU.S. G"""""""lll IOUIO Oli""IJM1fnlll1eCIDy low. This .,..._,t co,..,. l>fOPnotary•. . . . - - . - tr.>e10 soctellnl....,.oo" of 1110 ~cgnooof So..,..., Compoll'f or of ttinl pries. It a....,..,.., for use Otfy by omp!Oyoos or cr out.,.ntll FdoOotD P"!l• 08111!110 081111110 114 SoCo FOIA Response 002153 _. .... _.. . .. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Worllhours Labor Material Subconti'3Ct Total Account/OescrlpUon (b) (4) Tne ReQIIIOill d Cccpot:IM " - ' OE-I'C28-0iiiiiT42391 cons1110n 1I'C m:otonollumishod l' C D ! o n l - Dtlow. coni'IOitrollolllu!lnMs '"'"""""'"" wlloC> 1S to be wo:1111o1<1 1rtrn ClsdaSI.ni..,..OO 1I'C U S Govommort 1b1S aoo.tnen~QliQins ~. ~- ;ni/Qrlr.IIIQ.......,"""""""' o f l n o - . Gl Scu:nom Cl>mp;onJ crollhnl ~ ~,. o:len1!ocl tor 1110 any 111 em;toyoosd cr ~ Clllr.Inypcnctlis pro1>1111!0d, Rapal101110 f!lo"""' P"90 081111/10 08116110 55 IJ,.,..,_......,......, ""'· SoCo FOIA Response 002154 KEMPER COUNTY IGCC EPC I START\JP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subcontract Total AccounttDcscription (b) (4) Tho Roaplont of ~Agaamar.1 CE-I'C21>06NT423g1 CD1151dcntho m:l1orUII luml3haclhoruin k1 a>ntmn conl'odentJal DuSIIIOSSinl~w~ICn oSIOIIOwltl\holYOmmon: 101110 ""'""' ,.,.,.,._ 1>J tow. Thts aoo.rnan1 o:xtbans. ~. c:anfldanll:t. ::mr:Jor tr.ldD Ropotl 0010 F"iJOD:IID !>ago ~KnJ~tnfanor=ian Df tho sabsidl:ln.os d SaUiham ~at 08118110 08/18110 66 of third p:xtios. l1tS lraDndocl far U$0 aiy by Dmpk:yoo$ of 01 ::.uthonz.od mntr.ldOJS of """'ckl""" cf SOIMOm Ccmi"'IIY· Unoulho!IZCnoo ,.,.,.,...,., calla n ccnlld0<111ol Duslnass on!Otm3bo w.lhhold lrm1 ci>Cos..o ou!Sido 11'1:> U.S. Gowmmoll! to 1l1e C!XIenl pormd!od Dy ...... Ro-O.ID Folo Do1C! ~o;o DBI1BIIO 08t1B/10 57 ThiSOOCIInenl"""""" ~. ~. andiOO rriJ Dy orrn>IOyol subslcl~oos of SOutnam CGmpony u~~ possession. ....... - . ""P'""'J, duc!111111311nsc!on lhO """"".alfulrjsnodnl!fWI Ia ar.bn cartldomotllusinMsln!orm:r:ionwt!CIIIs tobaWIIMoldfrtlm QsdcsuoCUUidOtnoU.S Govomn!ont 10 l l 1 o - potmll!ed bJ - · ...-11:100 -In!"'""'"'" ..-a.... Ccm;>:IIIY -n. capyrog. di....,.,..._, or llosdos&ov cl any TM aoa.m0t11 COIII3oiiS ~. cort.,onllol, . - e t oiSoulhom Compony. UI'CIU1.'10nZDd ............... uoo. ------------··- clllle cl Soul/10m or of llinl pan~es. Ills inlondt Agn>ltlr'.enl OE.FC2S-06NT423111 consldol$ L'>o m•l9n;IIIU!nshod noron Ia c:untrn canl"oclrial bu$1..,.. ontonnall.., *lllc!\ is 1o be wilnholl! lr.rn dosdos'"" au!sodo U... U.S. Gowmtnont 10 1110 o.tcnl ponn"""' DJ""" lhrs ooaaont cont:l•ns prDCM"MtWO,. cor.r~. 3nal0r tt:ldD SOC'Ot lnfotl"t\:U)n or tno ~~..,_ ot So~ Cotnpony ot Gt ~hint pOrtJos n ts. U':Utnd&d fot use aNy by ama!oyeos cl or 31AhenZ0d c:::or.txtots of :Mibsldlo!IOS af50U!I10m Comp3ny. UnauiiDizDd posse...,.,, use. lt4CI. - -- ---- RcpcwtO.>lO Fol Wlllltleldt:an dlsclow.v cutsJdD Ula u.s. c ; ID 1/11! oxtant pormiOOCI by l;lw. F!a:>OI1 Dale Ftlooato Pogo 08118110 08118110 70 Ttu CIOCUnanl""""""" propno~:~ty, canroc~on:.ar. 'llldlor ,,_ sacrat 111formallon of thO swsldoon.,. of SCMncm COmpony or of trvd p:~1tlos. It os orundc< lor uso orly 1>t em~ of or :aMonzooj concr.~=ors a1 .......,.....,. of Southom Compony. UNutnonzed possessoan. use. dstnb&Aion. tDf>Ying. dl.....,nr.ioR, or doSdDSUnl of ony parocn ,. pte>NI>i!OCI. - ~ --------- SoCo FOIA Response 002159 .... t. KEMPER COUNTY IGCC EPC I STARTUP COST BREAKDOWN FOR PHASE lllb Key Key Quantity UM Workhours Labor Material Subconlr.lct Total Account/Description (b) (4) T~olleo,..,.. or Cocpof;rJ"' Agroomcnt De.f~Q391 "'tno 01<1en1 pom>oiiOd by 1.... -1$""' I!IO'.o!o ..m.diOnoool SoulnotnComoony oraf tl'lnlpattteS. It •• ~ forusoOI'Iyby omployoosof«..,.,.,..,.,..,.,...,..... o1 sut>socloonosols-n C..mpony UII:IUI1c>rlzo0 U.S. G...,.,onl IOtho-.,aoc:rllyl;lw 1,892,700,101 Ro1>0110mo 08118110 Pago 72 Fl!oCa!o 08118110 'll>5 doc:umOr.1 canlalns ...,.,-aLllY, CZII"I!Idona!ll. ondllir ln>de saam 1- 0 01 :no suboldl:lnos Ill Saulhcm Com!W'Y ar ot INnl p.:lllies. 11 is lnlllf1CIKS far •so atlly by ampiOII!C!S Ill or IIIJII'oDmDd a>ntmdal> ol Su!:ISOanes of SoiMom Companr ~- - " ' " - USO.. .,..,DilliOn, r:cpy.ng. GIOSOIMOtiort. 01 OISCIOS<.ro poniCII is ptti111Dilccl cl""' SoCo FOIA Response 002161 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: "Buettner, Jennifer M." Monday, September 20, 2010 2:44 PM Robbins, Brittley; Madden, Diane Pinkston, Tim E. Modification 007 to Kemper County Cooperative Agreement CA --Mod 007 (SCS Redline 9-17-10).doc Diane and Brittley, Attached is a redlined version of the proposed Modification 007 to the Kemper County Cooperative Agreement. Many of our proposed changes are clean-ups and/or clarifications. We understand that our changes to Item 7 (among other items) of the attached version of Mod 007 may warrant discussion, and Tim and I are able to talk with you at your convenience. Please let us know if you would like to try to schedule a conference call this week. I will be out of the office on Thursday (for an off-site meeting) and Friday (for travel) and will not have access to e-mail or a computer either of those days. Thanks, Jennifer Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (office) (b) (6) (mobile) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary information of Southern Company and/or its affiliates that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 002162 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Richard Hargis Monday, September 27, 2010 3:04 PM Madden, Diane Fwd: RE: Modification 007 to Kemper County Cooperative Agreement TEXT.htm Diane, Can you send me a file with the new language? Thanks. Rich »>Diane Madden 9/27/2010 2:58PM>>> Brittley, I spoke with Rich Hargis, who Is a NEPA Compliance Officer as well as the NEPA Document Manager for the Kemper Project and he concurred on the wording associated with the NEPA clause and the environmental reports. Diane »> Brlttley Robbins 9/27/2010 2:20PM >» HI Diane, Please check with the NEPA Compliance Officer and confirm that all wording associated with the NEPA clause and environmental reports are okay. Please respond to this email Indicating you have discussed with them and they concur or forward their concurrence to me. I need final concurrence documentation for the file. Thanks, Brittley >>>"Buettner, Jennifer M." 9/27/2010 2:12PM >>> Brlttley and Diane, Here Is the red lined document that we just discussed. Thank you, Jennifer .,! ... ii Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (office) (b) (6) (mobile) 205·257·6381 (fax) jenmorri@southernco.com This e-mail and any of its attachments may contain non-public and/or proprietary Information of Southern Company and/or Its affiliates that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e·mallls intended solely for the use of the Individual or entity for which It Is intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the Intended recipient of this e-mail, please notify the sender Immediately by return e-maJI and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 002163 From:Buettner, Jennifer M. Sent: Monday, September 27, 2010 12:05 PM To: 'Brittiey Robbins'; 'Diane Madden' Cc: Pinkston, Tim E. Subject: RE: Modification 007 to Kemper County Cooperative Agreement Brittfey and Diane I have to retract my last e-mail. We just had a question from MPC. Tim and I will discuss ASAP and call you this afternoon. Thanks! Jennifer (b) Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N·8374 Birmingham, Alabama 35203 205·257-6730 (ofOce) (mobile) (6) 205·257-6381 (fax) jenmorrl@southernco.com This e-mail and any of Its attachments may contain non-public and/or proprietary Information of Southern Company and/or Its affiliates that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the Individual or entity for which It is Intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e-mail Is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From:Buettner, Jennifer M. Sent: Monday, September 27, 2010 11:20 AM To: 'Brittley Robbins'; Diane Madden Cc: Pinkston, Tim E. Subject: RE: Modification 007 to Kemper County Cooperative Agreement Brittley and Diane, .We are comrortable with this change to clarify the language. Do you need for us to do anything else at this time? If so, let us know and well take care of It as quickly as possible. If not, you can go ahead and do what needs to be done on your end to process the Modification. We have already set up a meeting for our EVP to sign the Modification on Wednesday afternoon. Thanks very much, Jennifer Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205· 257-6730 (office) (b) (6) (mobile) 205-257-6381 (fax) jenmorri@southernco.com This e-mail and any of Its attachments may contain non-public and/or proprietary Information of Southern Company and/or Its affiliates that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail Is intended solely for the use of the Individual or entity for which It Is intended. Ir you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail Is contrary to the rights of Southern Company and/or Its affiliates and is prohibited. If 2 SoCo FOIA Response 002164 you are not the Intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From :Brittley Robbins [mallto:Brittley.Robbins@NETL.DOE.GOVJ Sent: Friday, September 24, 2010 4:51 PM To: Diane Madden; Buettner, Jennifer M. Cc: Pinkston, Tim E. Subject: Re: Modification 007 to Kemper County Cooperative Agreement Hi Jennifer, I got to this faster than I had anticipated. Attached please find a few minor edits to your proposed language based on the Contracting OffiCer's review. other than those changes, we've accepted all your edits. Let me know what you think. Have a good weekend! Brittley >>>"Buettner, Jennifer M." 9/20/2010 2:42PM>>> Diane and Brittley, Attached Is a redlined version of the proposed Modification 007 to the Kemper County Cooperative Agreement. Many of our proposed changes are clean-ups and/or clarifications. We understand that our changes to Item 7 (among other Items) of the attached version of Mod 007 may warrant discussion, and Tim and I are able to talk with you at your convenience, Please let us know if you would like to try to schedule a conference call this week. I will be out of the office on Thursday (for an off-site meeting) and Friday (for travel) and will not have access to e-mail or a computer either of those days. Thanks, Jennifer (b) Jennifer M. Buettner Southern Company Services, Inc. 600 North 18th Street, Bin 7N-8374 Birmingham, Alabama 35203 205-257-6730 (office) (6) (mobile) 205-257-6381 (fax) jenmorrl@southernco.com This e-mail and any of Its attachments may contain non-public and/or proprietary Information of Southern Company and/or Its affiliates that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e-mail Is Intended solely for the use of the individual or entity ror which it is Intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and Is prohibited. If you are not the intended recipient of this e-mail, please notify the sender Immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. 3 SoCo FOIA Response 002165 Dunlap, Ann C. From: Sent: To: Subject: Attachments: Richard Hargis Wednesday, November 03, 2010 4:21 PM Madden, Diane Re: Fwd: Kemper MAP - draft SOW contractor support TEXT.htm; Contractor Support draft SOW REV1110310 redline.docx; Contractor Support draft SOW REV1110310 clean.docx Diane, I made some revisions to the draft SOW to address Marty Weber's comments. Attached are two versions: one redllne and one clean. You may want to look at the dates I Inserted In the schedule as 1 am just guessing on start of mine construction, etc. Please Jet me know If you have any questions. Thanks. Rich >>>Diane Madden 10/29/2010 9:50AM»> Rich, I forwarded your SOW to Marty and the following Is his feedback. Diane >>>Martin Webler 10/29/2010 9:31AM>» Diane, I think your document looks pretty good. See the attachment for a few comments. The inclusion of the MAP may answer the timing question. What we would do next Is send this to Keyloglc and ask them for an estimate to complete this work, Including the resources they would Intend to assign or contract for. During this process you should be able to communicate your thoughts that a larger firm with broad experience and more resources might make sense. Once we OK the estimate, they can engage and go forward. Since this project Is all CCPI, this will run through a task that used to be monitored by Wolfe (and now Fred Sudhoff, I think). So we will need to Involve them since the costs will be flowing through their sub-task. But, when you are ready to ask Keyloglc for an estimate, Jet me know and l will submit It to get the ball rolling. Maty >>> Diane Madden 10/29/2010 9:06AM >>> Marty, Can you look at the attached SOW and see if it is sufficient for the site support contractors to issue a RFP fpr environmental firms to bid on the work. This request involves not only environmental monitoring of an IGCC power plant but also of the surface mine. This Is why we feel that it Is not one individual that can support this effort but an environmental firm that has a staff of experts In the various fields needed to perform the required reviews. Diane »>Richard Hargis 10/27/2010 2:08PM »> Diane, SoCo FOIA Response 002166 Attached Is a draft Statement of Work for contractor support In reviewing dellverables from Southern Company under the Mitigation Action Plan for the Kemper Project. Please let me know if you would like me to expand on this draft or if you would like to discuss. Thanks. Rich 2 SoCo FOIA Response 002167 Draft SOW 11/03/2010 Contractor Support Review of Delivcrables under Mitigation Action Plan Kemper County lGCC Project Pmpose: Provide technical support in reviewing deliverables under the Mitigation Action Plan (MAP) for the Kemper County IGCC Project. Task l. Review Existing Documentation The contractor will review all existing documentation including the Draft and Final Environmental Impact Statements (EIS), the Record of Decision (ROD), and the MAP to develop a complete understanding of the environmental issues related to the Kempel' County IGCC Project ("the Project"). The EIS and ROD form the basis for the MAP; by reviewing these documents, as well as the MAP, the contractor is expected to have a thorough understanding of not only the MAP as currently written but the environmental impacts that arc anticipated to be addressed through implementation of the MAP. This will allow the contmctor to provide an independent review of monitoring plans and reports in Tasks 2 and 3 that will be of value to DOE in determining whether the MAP adequately addresses environmental impacts or should be modified in some manner. Deliverable: Contractor will notify DOE when all relevant documentation has been reviewed, not later than January 31, 2011 . Task 2. Review Monitoring Plans for Individual Resource Areas. The contractor will review draft plans addressing individual resource areas as they arc submitted to DOE. These plans include: test plan for emissions of hazardous air pollutants; adaptive management plans for surface water quantity, surface wate•· quality, and aquatic ecology; and monitoring plans for surface water quality and drinking water wells (see MAP for complete list). The contractor will provide comments and recommendations on the monitoring and mitigation plans for DOE consideration. Deliverables: Contractor will provide a written report on each monitoring plan reviewed within two weeks of receipt of each plan from DOE. The current schedule for receipt of monitoring plans is shown in the Task Schedule below. Task 3. Review Reports Delivered to DOE The contractor will review repot1s delivered to DOE to cnsme that the monitoring is consistent with the MAP and the individual monitoring plans reviewed under Task 2. For each plan and report reviewed, the contractor will provide recommendations on additional mitigation and monitoring for DOE consideration, including frequency and duration of planned monitoring activities. Deliverables: Contractor will provide a written evaluation of each monitoring report reviewed within two weeks of receipt of each report from DOE. The evaluation will include a summary of recommendations on additional monitoring for DOE consideration. SoCo FOIA Response 002168 Draft SOW 11/03/2010 Expertise required of contractor: General knowledge and understanding of coal-fired IGCC power plants and surface mines. Specific knowledge and experience in emissions of diesel engines, testing lor hazardous air pollutants, adaptive management plans for smfnce water and aquatic ecology, groundwater monitoring, bioassessment protocols tor macroinvertebrates and fish, invasive SJ>ecies control, noise monitoring, traffic and transportation, and environmental justice. SoCo FOIA Response 002169 Draft SOW 11/03/2010 Task Schedule: Task I: Drafl EIS, Final EIS, ROD and MAP provided to contractor no later than 12/31/2010: Contractor notification to DOE or completion of Task 1 not later than 01/3112011. The expected schedule for providing reports or plans to be reviewed under Tasks 2 and 3 is provided below. The review and evaluation of each report or plan provided to contractor is to be delivered to DOE within two weeks of receipt ofrcpmt or plan by contractor. This schedule is based on the attached MAP. Tasks 2 and 3· Document P1·m•idcd to ContJ·actor Annual report on diesel emissions. Date January 20 12, January 2013, January 2014 Final Report on diesel emissions. Mc_ly2018 Quarterly report on Best Management Practices during lignite mining. January 2014, and quarterly thereafter until May2018. Hazardous air pollutants test plan. May 2017 Hazardous air pollutants lest report. May2018 Summary report of final carbon capture design and performance. february 2014 Quarterly reporting of carbon capture pcrfmmance. June 2014 and qumterly thereafter during mining operations until May 2018. Final report on carbon capture_pct-formance May2018 Adaptive management plan on surface water llows. February 20 II Quarterly monitoring reports on surface watct· flows. Quarterly reports beginning with start of mine construction _(AQril 20 12). Adaptive management and monitoring plan on surface water_guality. Fcbruary201l Quarterly monitoring reports on surface water flows. Quarterly reports beginning with start of mine construction (estimated as April2012). February 2012 Monitoring plan for enects on potable water SUJ>ply. SoCo FOIA Response 002170 Dran sow 11/03/2010 Baseline monitoring report on effects on potable water supply. Annual monitoring reports on effects on potable water supply. Monitot·ing of terrestrial invasive species. Report to DOE if federally listed species may be affected. Rapid bioassessmcnt protocols tor effects on aquatic ecology. Adaptive management plan for aquatic invasive species. Reports on aquatic invasive species. Minimize floodplain impacts from linear facilities. Progress reports on discussions with Army Corps regarding wetland impacts. Reports on wetlands mitigation. Noise monitoring and mitigation. Road damage from lignite delivery ti·om Red Hills Mine. Monitor environmental justice impacts. April2012 January 2013 and annually thereafter. January 2012 and annually thereafter during construction. As necessary. Quarterly for four quartet·s upon initiation of mine construction (April2012); annually thereafter until May2014. February 20 11. Almual reports upon initiation of mine construction (April 2012). Annually beginning January 2012. Quarterly beghming April 2011. TBD, based on Section 404 permit requirements. January 2012 and annually thereafter. Quarterly July 2014 to January 2015. January 2012 and annually thereafter. SoCo FOIA Response 002171 Draft 30W SoCo FOIA Response 002172 Draft SOW 11/03/2010 Contractor Support Review of Delivembles under Mitigation Action Plan Kemper County IGCC Project Purpose: Provide technical support in reviewing delivcrables under the Mitigation Action Plan (MAP) for the Kemper County IGCC Project. Task I. Review Existing Documentation The contractor will review all existing documentation including the Dmfi and Final Environmental Impact Statements (EIS), the Record of Decision (ROD), and the MAP to develop a complete understanding of the environmental issues related to the Kemper County IGCC Project ("the Project"). The ElS and ROD form the basis fi.1r the MAP. By reviewing these documents, as well as the lvlJ\P. the contructor is expected to have a thorough understanding of not pnly the MAP as currently written but the enviromncntal impacts that nrc anticipated to be addressed through implementation of the MAP. This will allow the contractor to provide an independent review of monitoring plans und reports in Tasks 2 and 3 that will be of value to DOE in determining whether the MAP adequately addresses environmental impacts or should be modiiicd in some matmer.+Ae eetttfaetor will also review RAtl-be-familiar with MAPs d~f)ed-fet'-Similar-r:.>OO f)F~eets. [Whe-dt!cides hew many amt-wh-ieh-HAes~ Deliverable: Contractor will notify DOE when all relevant documentation has been reviewed, not later than January 31. 20 II. [how loAg-Weffid..tfley-have to do this in ot=deF ta-meeHile-e~ons that follaWf} Task 2. Review Monitoring Plans for Individual Resource Areas. The contractor will review draft plans addressing individual resource areas as they are submitted to DOE. These plans include: test plan for emissions of hazardous air pollutants; adaptive management plans for surface water quantity, surface water quality, and aquatic ecology; and monitoring plans for surface water quality and drinking water wells (see MAP lot· complete list). The contractor will provide comments and recommendations on the monitoring and mitigation plans for DOE consideration. Deliverables: Contractor will J>rovide a written report on each monitoring plan reviewed within two weeks ofreecipt of each plan from DOE. The current schedule for rccei!>t of monitoring plans is shown in the Task Schedule below. Task 3. Review Reports Delivered to DOE The contractor will review reports delivered to DOE to ensure that the monitoring is consistent with the MAP and the individual monitoring plans reviewed under Task 2. For each plan and report reviewed, the contractor will provide recommendations on additional mitigation and monitoring for DOE consideration, including frequency and duration of planned monitoring activities. SoCo FOIA Response 002173 Draft SOW 11/03/2010 Dclivcrablcs: Contractor will provide a written ~eR-ettevaluation of each monitoring report reviewed within two weeks of receipt of each report from DOE. The~ evaluation will include a summary of recommendations on additional monitoring for DOE consideration. Expertise required of contractor: General knowledC!e and understanding of conl-lired IGCC power plants and smface mines. Specitic knowledge and experience in emissions of diesel engines. testing lor hazardous air pollutants. adaptive management phms tor surface water and aquatic eco)og.y, groundwater monitoring, bioassessment protocols for macroinvertebrates and fish. invasive species control, noise monitorinu. traftic and transportation. and environmental justice. SoCo FOIA Response 002174 Draft SOW 11/03/2010 Task Schedule: See-ffie-mtaeh~-MA~l-ieit>a~effi!J.e for reeeipkt,:.Plans-and repeFts-requiret:l lmElef-ti:l~ Task I: Draft EIS. Final EIS, ROD and MAP provided to contractor no later thnn 12131120 I0: Contractor notitication to DOE of complt:tion of Task I not later than 01131/20 II. The expected schedule for providing reports or plans to be reviewed undc1· Tasks 2 and 3 is provided below. The review and evaluation of each report or plun provided to contractor is to be delivered to DOE within two weeks of receipt ofrcpmt or plan by contmctor. This schedule is based on the attached ivJAP. Tasks, 2 und 3· Document Provided to Contrnctor Annual report on diesel emissions. Final Rcnort on diesel emissions. Quarterly report on Best tvlanagement Practices during lignite mining. Hazardous air oollutants lest nlan. Hazardous air oollutants test reoort. Summarv rcnort of final carbon canturc dcsil!n nnd ncrformancc. Quarterly reporting of ccubon capture performance. final report on carbon caoturc l)ertormance Adaptive management t>lan on smfacc water t1ows. Quarterly monitoring reports on surface water tlows. Adaptive manaucment and monitoring J)!an on surt~1ce water llllality. Quarterly monitoring reports on surface water tlows. Date January 2012, January 20 I 3. Junuarv 2014 Mav 2018 January 2014, and gunrtcrly thereafter until Mar 2018. Mav 2017 Mav 2018 February 2014 June 2014 and guarterly the renner during mining opcmtions until May 2018. Mav 2018 February 2011 QuarterlY repm1s beginning with sta11 of mine construction (April 20121. February 20 II Quarterly reports beginning with start or mine constmction (estimated as SoCo FOIA Response 002175 Draft SOW I l/03/2010 MonitorinJ.! 1>lan for effects on I>Otable water surmlv. llascline monitorinl! r~port on effects orumtable water surmlv. Annual monitoring rcQorts on effects on ~otable water suppl~{. rvlonitoring of terrestiul invasive sgecics. Reuort to DOE if federally listed soecics nuw be aftccted. RnQid bioasscssmcnt protocols for effects on nguntic ecology. Am·il '>0 12). Fehruarv 2012 Am·il 2012 January 2013 and annually thereafter. January 2012 and annually thereafter dming construction. As ncccssarv. Quarterly for four guurters upon initiotion of mine construct ion {A~ri12012}; annually thereafter until M:w2014. Adrmtivc mann11.emcnt nlun ti.w aouatic invasive snccies. Reports on aquatic invnsive species. Minimize tloodplain imQacts ti·om linear !ltcilities. Progress rcpo11s on discussions with Army Corps rcgurding wetland impacts. Reports on wetlands mitigation. Noise monitot·inu and mitigation. Road damage from lignite delivery from Reel Hills Mine. Februnrv 20 11. Annual regorls upon initiation of mine construction (Anril2012). Anmmlly beginning Jnnuarv 2012. Quarterlv beginning April 201 t. TBD. based on Section 404 pemtit reLluireml!nts. January 20 12 and mmually thereafter. Quarterly Julv 2014 to Jmmao' 2015. Monitor environmental justice impacts. January 2012 and annually thereafter. SoCo FOIA Response 002176 Draft saw 1 1:03: 213] ID SoCo FOIA Response 002177 Dunlap, Ann C. From: Sent: Cc: Subject: Attachments: Richard Hargis < Richard.Hargis@NETL.DOE.GOV> Friday, AprillS, 2011 1:39 PM Madden, Diane; Detwiler, Ralph RE: CONFIDENTIAl ATTACHMENT RE: Sierra Club v. DOE (No. 1:11-cv-00514-JDB) 20080429_DOE_Memo to So Co signed by Secretary Bodman.pdf; OGP EIV Part 4.pdf; OGP EIV Part S.pdf; OGP EIV Part 6.pdf; OGP EIV Part l.pdf; OGP EIV Part 2.pdf; OGP EIV Part 3.pdf Rich >>>"Liberatore, Kathryn (ENRD)" 4/15/20111:17 PM»> Hi Paul, bS Thanks, Kate b5 From: Richard Hargis (mailto:Richard.Hargis@NETL.DOE.GOV) Sent: Thursday, Aprll14, 2011 4:08 PM To: Bettina Mumme; Liberatore, Kathryn (ENRD) Cc: Ralph Detwiler Subject: CONFIDENTIAL ATTACHMENT RE: Sierra Club v. DOE (No. 1:11-cv-00514-JDB) bS SoCo FOIA Response 002178 Thanks, Bettina From: Detwiler, Ralph (NETL) Sent: Wednesday, April 13, 2011 3:06 PM To: Mumme, Bettina; Hargis, Richard {NETL); Kathryn (ENRD)' 'Liberatore Subject: RE: Sierra Club v. DOE (No. l:ll·cv-00514-JDB) ··administrative record bS 7(. 'Pt:wAl qjiitw-i~ Chief Counsel National Enet·gy Technology Laboratory Pittsburgh, PA 412-386-4839 (0) 412-651-220 I (C) >>> On 4/13/2011 at 2:50 PM, in message , " SoCo FOIA Response 002179 Bettina SoCo FOIA Response 002180 ·,----------------l '· EXEC-iOOS-004881 Department of Energy Washington, DC 20686 April 29, 2008 MEMORANDUM FOR THE SECRETAR~ THRU: C. H. ALBRIGHT, UNDERSECRETAR . ·E~~RGY FROM: JAMES A. SLUTZ ACTINGPRIN OFFICE OF SUBJECT: Action: Approve a request from Southern Company Services (SCS) for contingent waiver of repayment under its Clean Coal Power Initiative (CCPI) cooperative agreement. ISSUE: SCS has requested DOE's approval to change the project site nom Orlando, Florida to Mississippi Power's Kemper County, Mississippi site; and, a Secretarial waiver of the repayment agreement associated with the Cooperative Agreement. The site change is necessitated by a regulatory policy change in Florida making it impossible to complete pennitting without the addition of carbon capture and sequestration (CCS) technology. CCS is not technically or economically feasible at Orlando. I have approved the site change request ns reasonable and necessary to accomplish program objectives. The waiver is necessitated by an unanticipated change in IRS policy which now subjects DOE funds to Federal taxation, thereby jeopardizing Public Service Commission approval of the project as the least cost alternative for the Mississippi ratepayer. Waiver of repayment permits DOE funds to be treated as non-taxable. BACKGROUND: In February 2006, DOE awarded a cost-shared cooperative agreement to SCS for the full-scale demonstration of the Kellogg Brown and Root (KBR) Transport Reactor Integrated Gasification (TRIGT111) technology at the Orlando Utility Commission (OUC) facility in Florida. In December 2007, SCS announced it was discontinuing the Orlando project due to Florida's new requirement for CCS technology on coal-based power plants. Addition ofCCS at Orlando was not technically or economically feasible. SCS has requested DOE approval to relocate the project to Kemper County, Mississippi, on a site owned by Southern Power subsidiary Mississippi Power. Kemper will usc the same technology as Orlando except that Kemper will have two power trains compared to the single train at Orlando. Although the project cost at Kemper is significantly larger than at Orlando, DOE's absolute contribution will not exceed the amount committed to Orlando and DOE's percentage share will be reduced from 35 to 18 percent During the first phase of the relocated project, DOE will SoCo FOIA Response 002181 2 only contribute funds for NEPA related activities until a NEPA Record of Decision (ROD) is issued. Southern will absorb all engineering costs prior to issuance of a ROD. If a ROD is issued that supports the project, DOE will share in the cost ofthe construction and operation of the facility. Mississippi Power has been granted a tax credit for the Kemper facility pursuant to Section 1307 of the Energy Policy Act of 2005, and also is seeking a loan guarantee from DOE; Mississippi Power has been invited to submit a full Joan guarantee application. SCS and Mississippi Power have expressed a willingness to usc CCS technology at Kemper, however the cost of CCS coupled with the funds lost to federal taxation, creates a significant risk that the project would not be viewed favorably by the Mississippi Public Service Commission when compared to the next likely alternative - natural gas combined cycle technology. Historically, the IRS viewed DOE Clean Coal funds as contingent loans not subject to federal taxation because the funds were subject to a repayment agreement. Not long after DOE made the award of Clean Coal funds for the Orlando facility, SCS and DOE learned that the IRS was changing its position based on its belief that the repayment agreements were too contingent to qualify for loan treatment. Attempts to convince the IRS to follow its past practice were unsuccessful. The IRS also rejected the alternate argument that to the extent the DOE funds did not qualify as a contingent loan, then the funds should be considered a non-taxable contribution to capital. To qualify as a contribution to capital, the funds must be a pennanent part of capital of the recipient. The ms believes the repayment agreement precludes consideration of the funds as non-taxable under this test. If repayment is waived by DOE, the funds would be eligible for tax-free treatment as a contribution to capital. The ffiS's change in tax policy results in the loss of(b) (4) (b) (4) to the project. Earlier, with respect to the Orlando project DOE rejected SCS's request for a waiver of the repayment requirement and instead said it would pursue a legislative proposal which, if passed, would provide for tax free treatment ofCCPl funds. The proposal has been under interagency review at OMB and Treasury for several weeks. We do not know when or if it will be cleared for submission to Congress. To maintain its Section 1307 tax credit and meet its 2013 target for new capacity, Mississippi Power believes it must make a decision on technology choice witltin the next few weeks. Accordingly, DOE has been asked to approve site relocation and repayment waiver by April 30, 2008. SCS and Mississippi Power do not believe they can wait for legislative action to correct the tax problem. Therefore, to provide certainty, they have asked DOE to agree to waive repayment now, with the condition that the waiver is void (and repayment reinstated) if the legislation is passed or the IRS changes its position by January 31, 2009. SCS does not wish to incorporate CCS into the scope ofthe CCPI Round 2 project in order to preserve its right to apply for CCS funds under future solicitations, such as CCPI. However, SCS and Mississippi Power arc willing to void the waiver if they do not present plans to DOE for CCS at Kemper by the January 31, 2009. SoCo FOIA Response 002182 3 OASIS FOR WAIVER: PubIic Law I08-108, which appropriated funds for the CCPI Round 2 solicitation states: " ... the Departme111 may include provisions for repaymellt ofGovemment co11tributimrs to individual projects in an amount up to the Govemment contribution to the project ott terms and cottditions that are acceptable to tire Department includittg repayments from sale and licensing oftechnologies from both domestic attdforeign transactions" For the CCPI Program, DOE used the CCT standard for repayment waiver: Tire repayment agreenre~t may be terminated upon a determination by the Secretary ofEnergy, or designee, tlrat repayment places an Obligor at a competitive disadvantage irr domestic or intematio11al markets. NETL and the Office of Fossil Energy have analyzed the infonnation supplied by SCS and Mississippi Power and have concluded that Mississippi Public Service Commission approval would be at significant risk if the ratepayers must bear the cost that would have been covered by the amount lost to taxes. The assessment is discussed in detail in Attachment 1. )fthe Commission rejects the TRIGTM technology in favor of the next favorable alternative (Natural Gas Combined Cycle), TRIQnf will likely not be demonstrated in the foreseeable future and therefore not commercialized in domestic or international markets. Based on these facts, the Department may rensonably waive repayment wtder the applicable standard. RECOMMENDATION: That you approve SCS's waiver request subject to the tenns outlined above and discussed more fully in Attachment I. SENSITIVITIES: DOE would waive potential recovery of$293 million in repayment so that SCS may avoid a (b) (4) tax burden. This would be the first request for repayment waiver considered and granted by DOE. While the tax policy change is not likely to impact existing or future projects, other CCPI recipients may nonetheless believe they are entitled to a waiver. Attacfunents: 1. Bauer Memo to Slutz dated April 22, 2008 2. Sec the attached Detennination for the Approval Line and Approval Terms and Conditions. SoCo FOIA Response 002183 APPROVAL DETERMINATION The waiver request of Southern Company Services is APPROVED, with the condition that the waiver is void if any of the following occur: (I) On or before the earlier of DOE's issuance of a Record of Decision for Southern's planned Mississippi plant or January I, 2010, the Internal Revenue Service agrees that CCPI II funds are not taxable to the recipient, even ifthe funds are accompanied by a requirement of repayment to DOE. Southern Company agrees to seck a private Jetter ruling from the lRS if DOE advises Southern that the lRS has indicated a willingness to entertain tax-free treatment of DOE CCPI II funds. (2) On or before the earlier of DOE's issuance of a Record of Decision for the Mississippi project or January I, 20 I0, the law is amended to make CCPI funds not taxable to the recipient. (3) Southern Company {and/or its affiliated companies) does not, with respect to the planned coal-fired power plant in Mississippi receiving CCPI II funds: (a) design, build, and operate the facility with the intent to, capture and geologically sequester one million tons per year of C02 (approximately (b) (4) capture rate); and (b) establish, and actively work toward, the goal of capturing and sequestering (b) (4) of C02 emissions from the plant by 2020 and thereafter. Secretary of Energy -- SoCo FOIA Response 002184 Dunlap, Ann C. From: Sent: To: Cc: Subject: Attachments: Richard Hargis Monday. April 18, 2011 9:02 AM Detwiler, Ralph Madden, Diane Fwd: RE: CONFIDENTIAL ATTACHMENT RE: Sierra Club v. DOE (No.l:ll-cv-00514-JDB) TEXT.htm; Environmental Questionnaire.pdf Attached is the EQ submitted by Southern for the Orlando Project with the CCPI Round 2 proposal. There was no EQ submitted for the Kemper Project. >>>Ralph Detwiler 4/15/20111:21 PM >>> Rich - Can you collect this stu IT and send to me? Thanks. >» "Liberntorc, Kathryn (EN RD)" 4/15/20 II I: 17 PM>» Hi Pnul, Would yon also be nble to send me a copy ofthe environmental questionnaire submilled by Southern? lm guessing this doc is confidential. Also, I dont think my version ofthe record has the 4/29/2008 DOE memo signed by Sec. Bodman. Could you send me n copy of that as well? Also, I noticed that there nrc only two environmental record documents (1/J 1/05 and 6/30/05 MDEQ docs) that prcdnte the original EIS/ROD for the Orlando location. I just want to make sure there nrc no other materials from this timerrame that should be part of the record (i.e., were considered directly or indirectly by the agency decision-maker). Thanks, Kate , ~ oi From: Richard Hargis (mnilto:Rjchard.Hurgis@NETL.DOE.GOVJ Sent: Thursday, April 14, 2011 4:08PM To: Bctlina Mumme; Liberatore, Kathryn (ENRD) Cc: Ralph Detwiler Subject CONFIDENTIAL ATTACHMENT RE: Sierrn Club v. DOE (No. 1:11-cv-00514-JDB) Bettina and Kate, Attached is the file containing the "environmental critique" fonns completed for the CCPI Round 2 solicitation. This file is procurement sensitive and may contain confident in! infonnntion. Thnnks. SoCo FOIA Response 002185 Rich >>>"Mumme, Bellina" 4/14/2011 2:52PM>>> Ok. Ill keep that in mind. Do you have a copy oft he critique that you cnn send me? Thanks, Bettina From: Detwiler, Ralph (NET!.) Sent: Wednesday, April13, 201 I 3:06PM To: Mumme, Bettina; Hargis, Richard (NETL); Kathryn (ENRD)' 'Liberatore Subject: llE: Sierrn Club v. DOE (No. I: I 1-cv-005 I 4-JDB) -- administmtive record You can certainly look at it, but it is n fairly limited analysis. That is the nature of the process-- nt the application review stage, we haven limited amount of information about the projects and limited time to review and select. And potential environmental impacts are only one factor that DOE considers in making selection -- technical and financial feasibility are far more important. Keep in mind thnt this approach to NEPA in competitive financial assistance selections is the same one we have used for some time, and used in the selection of Recovery Act projects (although we added more to the critiques in those selections). If we fail to uphold this approach here, it will have dire consequences for DOE's Recovery Act projects. I also believe thnt, assuming it is still good law, we can make arguments analogous to those made in City of Angoon v. Hodel, 803 F.2d I016 (9th Cir. 1986) -- i.e., our section 216 regulation sets out how we deal with purpose and need und nlternntives in procurement matters. I will gel the premnble from the fedeml Register when section 216 was prornulgnted -- may hove some helpful material. ii R. Paul Detwiler Chief Counsel National Energy Technology Lnbomtory Pittsburgh, PA 412-386-4839 (0) 412-651-2201 (C) 2 SoCo FOIA Response 002186 »>On 4/JJ/20llnt2:50 PM, in messngc , "Mumme, Bettinn" wrote: Great. Paul and Rich, hn also wondering ifKnte and I could toke o look at the confidential Environmental Critique to evaluate irit would be to our benefit to still include it in some redacted/protected fonn in the administrntive record. Plnintilfwill wnnt to present n picture ofn very limited environmental review to the court. Being able to point to the Environmentnl Critique that preceded the EIS is likely to strengthen our position. What do you think? Bettina 3 SoCo FOIA Response 002187 Southn oo the •pplicstion CO_n!a.. _(13,~!~.1'?1'!5}. . -~~~gas.. _ .... ....... _ (1_4 millio'!J.~.Sl_., or Use or dlsciOIIItO d... on tbiJ shoot is tubject to the rcnriction on the •pptiution covor sheet for thlsproponl. 9 SoCo FOIA Response 002189 Souohcrn Compony Secvicu, Jnc. June 2001 DE-VS26-04NT42061 Ccrtilint!<'ns ·-·-·r···-·----· i o 1'No".c~ 1-~ .. _!~on~. . . .. Notes: {I} Qualllltics listed abovefor Materials Used a11d Materials Produced are those assrtmedfor the proposed jollr·ycar demorrstratio11 period of2010 to 20/J. B. l'ROPOSED PROJECT AND ITS ALTERNATIVES !.List all 11ltcmativc approaches considered to achieve the objectives described in A.ll and discuss the anticipated environn1cntal effects of each. (Place the selected approach at the top of the Jist.) Proposed Project As noted in A.ll, the proposed project is the design, construction, and operation of an advanced coalbased air-blown Transport Gasifier technology to demonstmte its commercial potential. The project will be a refueling of a full scale, commercial power generation unit. The alternatives arc listed below. The anticipated environmental effects of lhe proposal include air emissions, solid waste management and land disrurbancc activities, although these should be relatively minimal. Tile site or tho proposed project is Orlando Utilities Commi"ion's existing Stanton Energy Center. This 3,280-acre power plant site currently is home to two 42S·MW.coal·fired units, a 633-M\V natural gas/oil-fired combined-cycle unit, and is lhc planned site for a new simple cycle unit which will be modified lo 11 combined-cycle and refueled with coal-derived syngos as part of the demonstration phnsc. The entire site is already zoned for power plant and 11ssociatcd facilities, 11nd approximately 1,100 acres luwe previously been certified under the Florida Electric Power Plant Siting Act (FEPPSA) for power plnnt development. The specific location planned for the project equipment lies between the existing coal-fired units and the existing c:ombined· cycle unit. The land Is relatively flat and has mostly been clenrcd during past constmction efforts. Therefore, only minimal additional impacts arc anticipated in preparing the site for the gasifier. Still, land impacted by project construction will be evaluated for possible culruml resource, wetlands, and threatened nnd endangered spec:ies impacts prior to clearing and construction. Notably, all three of the existing units were licensed via the Florida Electric Power Phmt Siting Act (FEPPSA). The silo certification application (SCA) process has been recognized by federal agencies as generally equivalent to Environmental Assessments when National Environmental Policy Act (NEPA) review was required. The proposed gasifier project will require the existing plnnt's FEPPSA certification to be modified. However, the certification must be modified beforehand for the addition of the planned simple-cycle unit. In addition to typical nir emissions from construction related activities, operations will result in air emissions from the combustion lurbim: and a small amount from the gasifier during startup and shutdown. During startup and shutdown, the emissions from the gasifier will be controlled and vented through a ground flare. Emissions from the combustion turbine will exceed the air emissions from the turbine firing na!Ural gas, but will be less than the air emissions produced from equivalent Btu firing in a conventional coal-fired boiler. Overall, emissions from the proposed project will be significantly lower than those for operation of a similarly sized conventional coal-fired power plant due to the superior energy efficiency of the process and the advanced pollution control systems associated with the process. Refer to Section 2 of the Project Narrative.pdf file within this proposal for comparisons of the environmental perfonnance or the proposed project to conventional coal-based power systems. Gasificntion of coal will produce ash, a solid waste that will be handled and disposed of in an on-site landfill. Alternative management options may include combustion of the ash in an existing pulverized coal boiler or reuse of the ash in other byproduct applications. This solid waste is not expec:ted to be classified as a hazardous waste. A small amount of hazardous waste may be generated as a result of miscellaneous support activities during the demonstration oeriod. This Wlllite will be nronerlv handled and u•• or dliCicnuo: or dsu. on this sbcct iJ subject to the rtmktion on the applicsoon co••cr sheet (ot this pco;>l!n..ion cuvtt th Thursday, June 30, 20111:32 PM Mosser, Morgan H. NCCC Draft Report with (b) (4) (b) (4) Mike, Attached for your review are two draft evaluation reports. (b) (4) (b) (4) (b) (4) Please let me know if there are any questions upon your review. Also, please note the confidentiality statement on the title page - so please do not distribute outside the necessary reviewers within DOE. Thanks, Doug Maxwell Southern Company Services, Inc. National Carbon Capture Center 8-824-5851 (Intercompany) (External) (b) (6) (205)·670-5843 (Fax) jdmaxwel@southernco.com This e-mail and any of its attachments may contain proprietary Southern Company and/or affiliate information that Is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e· mail is Intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and Is prohibited. If you are not the intended recipient of thi s e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 002193 (b) (4) The work under Cooperative Agreement Number DE-NT0000749 may yield patentable inventions and other intellectual property. Data and information associated with any such intellectual property should be afforded secrecy treatment, as it is confidential and must remain confidential pursuant to 18 U.S.C. § 1905 and in order to assist Southern Company Services, Inc. in complying with the statutory and regulatory requirements concerning intellectual property. Given the benefits to the Government and to Southern Company Services, Inc. in protecting such intellectual property, Government personnel involved in or familiar with the work performed under Cooperative Agreement Number DE-NT0000749 and/or involved in the evaluation of this document should observe the confidentiality restrictions to protect these rights. SoCo FOIA Response 002194 SoCo FOIA Response 002195 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. ii SoCo FOIA Response 002196 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. iii SoCo FOIA Response 002197 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. iv SoCo FOIA Response 002198 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. v SoCo FOIA Response 002199 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. vi SoCo FOIA Response 002200 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. SoCo FOIA Response 002201 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 2 SoCo FOIA Response 002202 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 3 SoCo FOIA Response 002203 (b) (4) Use or disclosure o f data on this sheet is subject to the restriction on the title page of this document. 4 SoCo FOIA Response 002204 (b) (4) Use or disclosure of data o n this sheet is subject to the restriction on the title page of this document. S SoCo FOIA Response 002205 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 6 SoCo FOIA Response 002206 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 7 SoCo FOIA Response 002207 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 8 SoCo FOIA Response 002208 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 9 SoCo FOIA Response 002209 (b) (4) Use or disclosure o f data on this sheet is subject to the restriction on the title page of this document. I0 SoCo FOIA Response 002210 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the: title page: of this document. II SoCo FOIA Response 002211 (b) (4) Use or disclosure o f data on this sheet is subject to the restriction on the title page of this document. 12 SoCo FOIA Response 002212 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page ofthis document. 13 SoCo FOIA Response 002213 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 14 SoCo FOIA Response 002214 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page or 15 SoCo FOIA Response 002215 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 16 SoCo FOIA Response 002216 (b) (4) Use or disclosure of data on lhis sheet is subject to the restriction on the title page of this document. 17 SoCo FOIA Response 002217 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of 18 SoCo FOIA Response 002218 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 19 SoCo FOIA Response 002219 (b) (4) Use or disclosure of data on this 5heet is subject to the restriction on the title page of this document. 20 SoCo FOIA Response 002220 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 21 SoCo FOIA Response 002221 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 22 SoCo FOIA Response 002222 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 23 SoCo FOIA Response 002223 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 24 SoCo FOIA Response 002224 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 25 SoCo FOIA Response 002225 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page ofthis document. 26 SoCo FOIA Response 002226 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 27 SoCo FOIA Response 002227 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 28 SoCo FOIA Response 002228 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 29 SoCo FOIA Response 002229 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 30 SoCo FOIA Response 002230 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 31 SoCo FOIA Response 002231 (b) (4) Use or disclosure o f data on this sheet is subject to the restriction on the t itle page of this document. 32 SoCo FOIA Response 002232 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 33 SoCo FOIA Response 002233 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 34 SoCo FOIA Response 002234 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 35 SoCo FOIA Response 002235 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 36 SoCo FOIA Response 002236 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 37 SoCo FOIA Response 002237 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. JS SoCo FOIA Response 002238 (b) (4) Use or disclosure of data on this sheet is subject to the restriction on the title page of this document. 39 SoCo FOIA Response 002239 (b) (4) The work under Cooperative Agreement Number DE-NT0000749 may yield patentable inventions and other intellectual property. Data and information associated with any such intellectual property should be afforded secrecy treatment, as it is confidential and must remain confidential pursuant to I 8 U.S.C. § 1905 and in order to assist Southern Company Services, Inc. in complying with the statutory and regulatory requirements concerning intellectual property. Given the benefits to the Government and to Southern Company Services, Inc. in protecting such intellectual property, Government personnel involved in or familiar with the work performed under Cooperative Agreement Number DE-NT0000749 and/or involved in the evaluation of this document should observe the confidentiality restrictions to protect these rights. SoCo FOIA Response 002240 (b) (4) Use or disclosure of data on this sheet is subject ii to the restriction on the title page of this document. SoCo FOIA Response 002241 (b) (4) Use or disclosure of data on this sheet is subject iii to the restriction on the title page of this document. SoCo FOIA Response 002242 (b) (4) Use or disclosure of data on this sheet is subject iv to the restriction on the title page of this document. SoCo FOIA Response 002243 SoCo FOIA Response 002244 (b) (4) Information is subject to the restricted use notice on the title page SoCo FOIA Response 002245 (b) (4) Information is subject to the restricted use notice on the title page 2 SoCo FOIA Response 002246 (b) (4) Information is subject to the restricted use notice on the liUe page 3 SoCo FOIA Response 002247 (b) (4) Information is subject to lhe restricted use notice on lhe title page 4 SoCo FOIA Response 002248 From: Sent: Wednesday, June 08, 2011 3:49 PM Ciferno, Jared P.; Mosser, Morgan H. Wu, Tony; Figueroa, Jose; Bowers, Kerry W.; Brickett, Lynn A.; Ryan, Nicole RE: AICHE Peer Review 03_PIF_NT0000749_FY11CarbonCapturePR· Final w addtitional comments.docx To: Cc: Subject: Attachments: Jared, Attached is the revised PIF on the NCCC project for the upcoming AICHE Peer Review. The PIF has been slightly expanded to address the questions in your email from the review panel in seeking clarification or more information. We have not changed the presentation file and believe it is adequate for our use in answering and clarifying the items raised by the questions in your email, either during the presentation itself or the following question and answer session. With no changes to the presentation file I am not resending the file with this email but let me know if I need to resend. Please contact me if there are any questions on the attached PI F. Thanks, Doug Maxwell Southern Company Services, Inc. National Carbon Capture Center 8·824-5851 (Intercompany) (b) (6) (External) (205)·670-5843 (Fax) !dmaxwel@southernco.com This e-mail and any of its attachments may contain proprietary Southern Company and/or affiliate information that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e·mall is intended solely for the use of the individual or entity for which it is Intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Jared Clferno [mailto:Jared.Cifemo@NETLDOE.GOV] Sent: Wednesday, May 18, 201111:42 AM To: Morgan Mosser; Maxwell, Doug Cc: Jose Figueroa; Lynn Brickett Subject: AICHE Peer Review Dear Doug, Due to the delay In the AICHE peer review, It all allowed tlme for the AICHE panel to throughly review the project Information forms and presentations for each project slated for review. This 'preliminary review' resulted In a formal panel request to seek more Information and/or recommend clarifications for about half of SoCo FOIA Response 002249 the projects, one of them being the NCCC. Specifically, the review panel is recommending that the Southern Company presentation and PIF be revised to Include a greater discussion on the following: 1. Describing what specific technical or other Issues will be answered by testing at scale proposed at NCCC (or at the new PC4 facility to be built) and their impact on ccs 2. Why are the fadlltles needed and what specific issues will be addressed to advance progress to commercialization 3. How does one know whether the proposed facilities and test programs are appropriate for the critical questions to be answered I'm confident that these types of questions are not new to Southern and anticipate that these could be worked Into the presentation and Project Information Form with minor effort on your end. The answers will actually be helpful to so we all have the same voice when describing the high level programmatic and technical/engineering benefits of the NCCC. Please let me know if there are any issues of addressing this recommendation. I attempted to attach and send the presentation and PIF documents, however, they were returned due to file size. So you can just work off the last version that you submitted to Mike Mosser. Since the review is not until July, we are asking for revised material to be resubmitted by June 10. Thank you, Jared 2 SoCo FOIA Response 002250 DOEINETL Carbon Capture Peer Review Aprilll-15, 201 I 03- Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility PROJECT INFORMATION FORM (Not to Exceed 12 Pages) Project Number Project Title Performer 1. PROJECT IDENT>IFICATION NT0000749 National Carbon Capture Center at Power Systems Development Facility Southern Company Services, Inc. 2. Name Organization Phone E-mail Address PROJECT POINT OF CONTACT INFORMATION DOE I NETL FEDERAL PRINCIPAL INVESTIGATOR PROJECT MANAGER Morgan Mosser Kerry Bowers NETL- Existing Plants Division Southern Company Services, Inc. (b) (4), (b) (6) 304-285-4723 k\vbowers@southemco.com Morl!an.MosserfalNETL.DOE.GOV 3. PROJECT STAGE OF DEVELOPMENT (Check One) Fundamental Proof of Concept • Not relevant to this Peer Review 4. l. 2. 3. 4. PARTNERS (To add additional team partners, press the tab key at the end ofthe last row) (b) (4) (b) (4) Coal Company_(Arch Coal, Peabody, Rio Tinto) 5. PROJECT COST DOE Share Dollars $201,163,318 Percent 80% Non-DOE Share $50,290,830 20% Total Value Expenditure as of 12/31/2010 $251,454,148 $1 I 0,932,274 6. KEY PROJECT DATES Start Date 10/1/2008 End Date 9/30/2013 Elapsed Time (months) 27 (througj1 December 2010) Percent Complete 45% (tlzrou~h December 2010) 44% 7. BUDGET PERIODS (to add additional budget periods, press the tab key at the end of the last row) Period Number Start Date End Date Cost $42,866,917 10/1/2008 11/30/2009 1. $68,603,978 12/1/2009 12/3112010 2. 3. 111/2011 12/31/2011 $51 ,873,571 4. 1/1/2012 12/31/2012 $50,309,913 5. 11112013 9/30/2013 $37,799,769 DO NOT Include Business Sensitive, Proprietary, and/or Unclassified Controlled Information. Page I of 13 SoCo FOIA Response 002251 DOEINETL Carbon Capture Peer Review April 11-15,2011 03- Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility 8. TECHNICAL BACKGROUND In cooperation with Southern Company, the U.S. Department of Energy (DOE) established the National Carbon Capture Center (NCCC) in 2009 at the Power Systems Development Facility (PSDF) in Wilsonville, Alabama. The center will support national efforts to reduce greenhouse gas emissions by collaborating with technology developers in accelerating their col capture technology development for application to coal-fueled power plants. The NCCC offers a flexible test facility which provides commercially representative flue gas and syngas and the necessary infrastructure in which developers' technologies are installed and tested to generate data for performance verification under industrially realistic operating conditions. The PSDF was launched in late 1990 funded by the DOE and industrial partners and managed by Southern Company. Since completion of the facility in 1996, it has been a center for national efforts to develop high efficiency, coal-based power generation technologies that are reliable, environmentally acceptable and cost effective. Two significant achievements in this time period were in (I) hot gas filtration to improve energy efficiency, and (2) a gasifier suitable for use with low rank fuels. These two technologies have progressed to commercialization with integrated gasification combined cycle (IGCC) power plants being built at Kemper County, Mississippi, and DongGuan, China. Building on this success, the PSDF facility has now refocused its mission on supporting the development and scale-up of costeffective, commercially viable carbon capture technologies for coal-fueled power plants through collaboration with the DOE and third party technology developers. Most of the current C02 capture technologies are being developed at laboratory- or bench-scale under ideal conditions. Continued research and development (R&D) under realistic field conditions are needed to validate laboratory results and identify technical issues that are not present under ideal conditions. In collaboration with technology developers, the NCCC makes available coal-derived syngas and flue gas to carry out applied R&D on components or small pilot-scale systems to bridge gaps between fundamental R&D and large-scale commercial demonstration and provides for a seamless transition for promising technologies to migrate from laboratory into commercial applications. The NCCC is a unique test facility that consists of two major sets of infrastructure to support COz capture technology development. One is the existing pilot-scale coal gasification facility that produces syngas for pre-combustion C02capture technology evaluation and the other is the newly constructed PostCombustion Carbon Capture Center (PC4) located at an adjacent pulverized coal power plant, Alabama Power' s E.C. Gaston. Both are readily adapted to test a variety of technologies at multiple scales, providing data for scale-up to commercial applications. This flexibility in conjunction with real-world operating conditions, allows the NCCC to support developers in advancing the C02 capture technologies that are critical to continued use of coal for power generation. The NCCC is also evaluating the potential benefits of oxy-combustion C01 capture approach using the pressurized transport reactor operating in oxygen combustion mode. Preliminary screening studies have been conducted with favorable results. Detailed system studies, modeling and additional economic analysis will be used to evaluate the commercial feasibility of the technology. 9. PRIMARY PROJECT GOAL To support developers in accelerating development and commercialization of cost-effective C02 capture technologies by building and operating flexible test facilities for post- and pre-combustion capture from coal-derived flue gas and syngas. DO NOT Include Business Sensitive, Proprietary, and/or Unclassified Controlled Information. Page 2 of 13 SoCo FOIA Response 002252 DOEINETL Carbon Capture Peer Review April 11-15,2011 03 - Project # NT0000749, National Carbon Capture Center at Power Systems Development Facility 10. •PROJECT OBJECTIVES a) Modify the existing gasification infrastructure to increase the facility's ability to accommodate testing of a wide-range of capture technologies at different syngas flow rates, temperatures, pressures and composition. A portion of particulate-free syngas produced in the gasifier is piped to a syngas slipstream test facility (SSTF) to be processed and conditioned for downstream technology testing. With anticipation of more technologies to come and future scale-up tests, SSTF was upgraded with a new syngas header to increase the syngas tlowrate available to the SSTF. Three fixed bed pressurized reactors are available to process syngas for testing technologies such as water-gas-shift (WGS) and hydrocarbon cracker catalysts and high temperature sulfur and mercury sorbents. Depending on the requirements for syngas conditioning by technology developers, a wide range of additional gas processing equipment can be installed in order to meet testing objectives. For example, in recent tests a syngas cooling system and water knockout tank were installed to deliver syngas at close to I 00 °F for a polymeric C02-selective membrane test. In another test, sulfur will be removed to deliver near-zero sulfur syngas to a metallic hydrogen-selective membrane test that operates at 750 °F. Larger slipstream facilities have been conceptually designed, but will be implemented in the future if justified by demand. b) Build a new test facility, fost-£ombustion £arbon £apture £enter (PC4), at adjacent Alabama Power's Gaston pulverized coal power plant to accommodate tests of a wide-range of capture technologies from flue gas. PC4 was designed to provide several parallel paths to test candidate technologies at appropriate scales. A flue gas slipstream is extracted downstream of Plant Gaston's UnitS flue gas desulfurization process. A little over half of the flue gas is used for testing and the remainder helps maintain the flue gas temperature and limit the condensation in the delivery duct. The test facility includes three major test areas: (I) a pilot solvent test unit (PSTU) to test developers' next generation C02 absorption solvents; (2) a second test bay to support evaluation of fully integrated test systems supplied by technology developers; and (3) a bench-scale test area to accommodate up to four small test skids of emerging, advanced technologies such as sorbents or membrane systems. The facility has been designed and constructed so that multiple tests can proceed simultaneously. Design and construction of the PSTU is one major endeavor at the PC4. It is a conventional packedbed absorption column designed for solvent-based capture technology evaluation. It consists of a prescrubber for deep removal of sulfur, a condenser for water removal, an absorber for gas-liquid contacting of solvents with flue gas, a stripper to regenerate the solvent, reboilers, heat exchangers, pumps, gas analyzers, and associated piping, instrumentation. It was designed to be highly flexible to allow rapid modification of absorption and regeneration systems to match the physical and chemical properties of emerging solvents as they are developed and brought to the site by development entities. The unit was designed to achieve a 90 percent overall COz removal efficiency using a 30 percent monoethanolamine (MEA) aqueous solution which is being used as a reference solvent to obtain baseline performance against which other solvents will be compared. The PSTU is designed and built to be flexible in testing various advanced solvents such as hindered amines, amino acid salts, and ionic liquids, as well as any additives that enhance C02 capture performances such as enzymes. All vessels are spaced to allow for modifications to existing equipment or installation of additional equipment. The absorber and regenerator design allows alternative packing and other gas-liquid contacting arrangements to be readily installed. The DO NOT 111clude Business Se11sitive, Proprietary, and/or Ut~classijied Coiltrolled Information. Page 3 of 13 SoCo FOIA Response 002253 DOEINETL Carbon Capture Peer Review April Il-l 5, 20 II 03 -Project # NT0000749, National Carbon Capture Center at Power Systems Development Facility 10. PROJECT OBJECTIVES regenerator is designed for a maximum of200 psig to allow solvents to be regenerated at elevated pressure. Appropriate instruments and controllers are provided to control and maintain system process conditions. Data collected are verified through appropriate QA/QC procedures, cross-checks using alternative test and calculation procedures, and achieving good heat and mass balance closures. PC4 was designed and constructed on an accelerated pace so that evaluation of capture technologies could proceed as quickly as possible. It took about 18 months from the beginning of the design phase to construction completion. Commissioning of the PSTU is currently underway. Planned tests at PC4 for 20 II include chemical solvents, C02 membrane and C02 sorbent technologies. Contracts are either in place or in progress with technology developers to carry out the above tests. c) Support developers in testing advanced co, capture technologies that provide improved efficiency and cost effectiveness over those currently considered commercially available. In addition to individual component testing, components of the col capture process will be integrated and optimized to provide data needed for scale-up. For pre-combustion C02 capture, a portfolio of emerging technologies is being tested or plans to be tested. Those include chemical and physical solvents, WGS catalysts, various hydrogen and C02 membranes and C0 2 sorbents. Scale of these technologies ranges from I lb/hr to 80 lb/hr ofsyngas. Tests have produced valuable information for technology developers to make further improvements on materials and process configurations. Based on the promising test results obtained at the NCCC, one technology vendor is planning to scale up the design from 50 lb/hr to 500 lb/hr syngas capacity. In another test, WGS catalyst test results reveal that steam-to-CO ratio could be reduced, which in turn increases the net power output of an IGCC plant and reduces cost of electricity (COE) with C02 capture. This finding is being implemented at the Mississippi Power's Plant Ratcliffe IGCC plant currently under construction at Kemper County, Mississippi. The results have been supplied to WGS catalyst vendors and are available for use by other IGCC technologies that may be considering adding C02 capture to their plants. For post-combustion C02 capture, tests of advanced technologies will commence in 20 II. These include two to three chemical solvents to be tested in the PSTU, one solvent skid from a developer, one C02 membrane test and one solid sorbent test in the bench-scale area. The scale of these tests ranges from I kW to 0.5 MW equivalent of electric output. To effectively utilize the NCCC facility and bring the most promising technologies to the market as quickly as possible, a systematic process is necessary to identify the best candidate technologies based on a set of appropriate criteria including cost reduction, technology competency, and organizational strength. Jointly with the DOE, NCCC has developed a Technology Screening Process (TSP) which is a key evaluation tool to assess and prioritize technologies for testing. The TSP also ensures that final technology selection will form a balanced portfolio that promotes the advancement of both near-term and long-term candidate technologies. Key elements of the TSP include a comprehensive inventory of candidate technologies, quantitative scoring criteria and a qualitative best value assessment. The TSP inventory currently has over 300 technologies related to C02 capture in the area of pre-combustion, post-combustion, oxy-combustion, gas treatment and purification, C02 compression, power generation, etc. Four confidential TSP reports on candidate technologies have been completed with two more in progress. d) Test develoo. and ootimize comoonents to enable the deployment of carbon capture with minimal DO NOT llrclude Busi11ess Seusitive, Proprietary, ami/or U11classijied Coutrolled lllfornratioll. Page 4 of 13 SoCo FOIA Response 002254 DOEINETL Carbon Capture Peer Review April 11-15,2011 03 - Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility 10. PROJECT OBJECTIVES increase in the cost of electricity. These components include gas contaminant cleanup, gas separations, coal/biomass gasification or combustion technologies, fuel cell technology, materials, sensor technology, and others. Although the NCCC's primary focus is on C02 capture technologies, other power plant components could influence the design and performance of these technologies. For example, a warm-gas clean-up process coupled with high temperature C02 capture processes (e.g. hydrogen membrane or solid sorbents) may enable a more efficient process configuration that achieves higher overall plant generating efficiency and lower COE. One of the warm-gas cleanup technologies, high temperature mercury capture sorbents, is currently being tested at the NCCC with excellent results. The NCCC also supports solid oxide fuel cell testing that evaluates the impact of various contaminants in the coal-derived gas on fuel cell degradation. Another area of interest is fuel flexibility for coal-fueled power plant; specifically, gasification of coal and biomass co-feed. Current commercial systems are high-cost with low reliability and have never been demonstrated using biomass as a portion of the total feed to an advanced coal-generation system. Ongoing development of high pressure feed systems will identify ways to decrease capital and operating cost, and improve reliability and controllability of feed systems and address the added challenges of feeding different types of fuel mixes into a pressurized environment. Milestones Mar 2010 Mar 2010 Jan 2010 Jan 2010 Dec 2010 Dec 2010 DO NOT Include Business Sensitive, Proprietary, and/or Unclassified Controlled lliformation. Page 5 of 13 SoCo FOIA Response 002255 DOEINETL Carbon Capture Peer Review April II-IS. 2011 03 - Project # NT0000749, National Carbon Capture Center at Power Systems Development Facility Mar, 2011 June 2011 June 2011 Jun 2011 Sep2011 DO NOT Include Business Sensitive, Proprietary, and/or Unclassified Controlled Information. Page 6 of 13 SoCo FOIA Response 002256 DOE/NETL Carbon Capture Peer Review April 11-15, 20 II 03- Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility 12. COST TA:RGETS AND/OR BRIEF ECONOMIC ANALYSIS The DOE has established a cost target for coal-fueled power plant with 90 percent COz capture at no more than I 0 percent increase in COE for an IGCC plant or no more than 35 percent increase for a pulverized coal plant. Technologies selected and tested at the NCCC are those that could have a positive impact towards helping to achieve these cost targets. NCCC's role is to collaborate with technology developers to facilitate the progression of such technical development by providing a testing facility with realistic industrial conditions. Once technologies are proven under the requirements and rigors of real plant operating conditions, they could be scaled-up with confidence for commercial demonstration. Such value is exemplified below. WGS reaction, conversion of CO/H 20 to C02/H 2, is widely used in petroleum and chemical industries where process requirements are to maximize hydrogen production while minimizing methane formation and residual CO (which could either dilute the product or poison downstream catalysts). Steam-to-CO molar ratios as high as 3.0 are often recommended by catalyst vendors to achieve maximum CO conversion. However, in a power production cycle, process steam is a critical production commodity being converted into saleable electricity. Moreover, since the desired degree ofCOz capture establishes process targets for CO conversion and since syngas in an IGCC application is intended to supply fuel to the gas turbine, some residual CO levels after WGS would be acceptable, where they may be unacceptable in chemical plant applications. Thus, high steam-to-CO ratios are not required for power applications. Southern Company's studies suggest that, for a 500-MW IGCC plant, a 0.1 reduction in steam-to-CO ratio corresponds to a gain of roughly 4 MW equivalent of electricity capacity output or gain of$30 million dollars net present value over the life of the plant. Unfortunately, prior to testing at the NCCC, WGS catalyst vendors lacked sufficient experience and data in WGS reactor design for power production cycles in order to provide commercial catalysts with process guaranteed performance. In view of potential steam savings by operating at reduced steam-to-CO ratios, NCCC took the initiative to conduct testing, jointly with catalyst vendors, across a range of steam-to-CO ratios to understand how performance is affected, based on observed carbon conversion and formation of deleterious side reactions. The results verify that lowering the ratio from commercial standard practice does not impact CO conversion significantly. The same tests demonstrated that no methane formation or carbon deposition on catalysts occurred. Based on these positive findings, Mississippi's Plant Ratcliffe IGCC project designed its WGS reactor based on a lower steam-to-CO ratio than what is typically offered commercially. Catalyst vendors also endorse the findings and offer commercial guarantees on the WGS catalysts under these modified design conditions. This translates to an operational savings of over $200 million over the life of the plant. 13. BENEFITS Due to their commercially-focused operation, gaining access to commercial operating facilities for R&D purposes has been difficult for technology developers. Few test facilities in existence today have the scale, test duration, flexibility and/or operational expertise to fully test emerging technologies. Lack of such a flexible test facility results in a gap between laboratory works and commercial scale demonstrations and therefore hinders technology progression. NCCC addresses these issues by providing a flexible test facility to match individual technology testing requirements (gas quality, temperature, pressure, test duration, etc.) at various scales. Such flexibility cannot be matched by any other facilities in the US or the world. Data collected at the NCCC will be used to support technology scale-up and possible commercial demonstration. Success in these demonstrations eventually paves the way for commercial deployment for cost-effective C02 capture. Such economic benefits will preserve the continuous use of domestic, DO NOT l11clude Busi11ess Se11sitive, Proprietary, and/or Unclassified Controlled Information. Page 7 of 13 SoCo FOIA Response 002257 DOEINETL Carbon Capture Peer Review April 11-15,2011 03- Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility 13. BENEFili'S abundant coal in an environmentally responsible manner. NCCC plays a crucial role in facilitating and accelerating such technology progression and streamlining the commercialization efforts. NCCC's flexibility in carrying out various scales of testing offers different degrees of benefits to technology development and produces engineering data about technology performance and integration issues at different stages in the R&D process under realistic conditions. Such technical data are needed before one can move technologies from laboratory into commercial deployment. For example: • A simple exposure test of technology components in real gas conditions for extended test duration allows developers to refine their search for better and more robust materials and chemistry earlier in the developmental cycle (e.g., Palladium-based hydrogen membranes from several developers). • Testing of technology components or integrated systems at small bench scale generates performance data that helps developers to redesign their processes for scale-up assessments (e.g., Membrane Technology & Research's polymeric C02 membranes). • Testing scale-up of technology proves technologies' readiness for commercial-scale demonstration (e.g., PSTU solvent evaluation). The NCCC serves as a central test facility for third-party technology developers. This avoids the need for multiple test sites that each technology developer may have to pursue were the NCCC not available. Significant benefits are realized from cost and schedule perspectives. Since its establishment in 2008, NCCC, in the pre-combustion COz capture area, has worked with three chemical solvents, two physical solvents, three membrane technologies, three WGS catalysts, one fuel cell technology, and will be working with two C02 sorbents, a new membrane, a new WGS catalyst and a physical solvent in the near future. In addition, three technologies are being scaled up based on the results and findings from their initial demonstration scales and one has successfully deployed into commercial use. These demonstrate NCCC's capability to streamline and facilitate technology testing and advance technologies in an accelerated pace for scale-up and eventually to commercialization. It is anticipated that similar progression will be realized in the post-combustion COz capture area once test results are available. The NCCC provides not only a test facility that makes available realistic syngas and flue gas to multiple technology developers for performance verification, but also an infrastructure sufficiently flexible to interface with various advanced technologies with short turnaround time. Staff members at the NCCC are highly trained and experienced in process integration, design, operation and maintenance areas and offer testing and data analysis expertise to help technology developers validate their test results. Since multiple technology tests are carried out in the same environment, comparison of performance results between different technologies are more direct and effective. To accelerate the development of the carbon capture technologies from inception to full-scale deployment, the DOE has launched the Carbon Capture Simulation Initiative (CCSI). Its goal is to develop advanced modeling and simulation tools based on basic science. However, to validate the model and gain confidence in the simulation, actual field test data will be needed. The NCCC will play a key role in providing such needed field test data from testing of multiple technologies. NCCC will collaborate with the CCSI to design experiments based on key parameters identified in the simulation and feed the test results back to the model for validation. Initial discussions are underway for a solvent-based and a solid sorbent-based technology. NCCC's industrial sponsors include utility and coal companies as well as EPRl (Electric Power Research Institute). These sponsors have direct access to performance and cost information generated through the test program and provide feedback to the technology developers from the end-users' point of view. Such collaboration allows interactions between the technology developers and end users early in the DO NOT lllclude Busi11ess Se11sitive, Proprietary, ami/or U11classijied Co11trol/ed l11formatio11. Page 8 of 13 SoCo FOIA Response 002258 DOE/NETL Carbon Capture Peer Review April 11-15,2011 03- Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility 13. BENEFITS development stage, which will streamline commercial demonstration once it is proven at the NCCC. 14. POTENTIAL PROJECT RISKS The risks associated with the NCCC 5-Year Plan were evaluated using the DOE Project Risk Assessment (DE-08NT0000749) and was scored relatively low (113) based on six different categories; i.e. financial risk, cost and schedule risk, technical/scope risk, management, planning & oversight risk, environmental, safety and health risk and external factor risk. The primary risks going forward that could jeopardize the realization of project milestones and objectives are three folds. They are discussed below with risk mitigation. Risk #I: Risk associated with cost and schedule to build and upgrade the facility to accommodate testing of different technologies at various scales. Risk #I Mitigation The management team and technical staff at the PSDF are experienced and qualified in engineering, procurement and construction management activities as demonstrated in the past performance of constructing the original gasification pilot facility, testing and ultimately moving technologies from small bench scale to large engineering scale demonstration. The NCCC draws on this experience base of design engineering, operations and process engineering expertise to minimize any cost and schedule risk to build, upgrade and operate the NCCC. During the Continuation application period, details of proposed scope of work, budget, schedule and milestones to accomplish for the following budget period will be outlined in the Project Management Plan and Statement of Project Objective. It is comprehensively reviewed prior to any commitments to upgrade test facility to accommodate testing of potential candidate technologies, and hence minimize any risks associated with cost and schedule. Risk #2: Risk associated with the possibilities that the NCCC could not be inclusive in identifying promising technologies for testing and scale-up demonstration. Risk 2 mitigation To effectively use the funds and identify the most promising technologies, the NCCC has established a technology screening process (TSP) to catalog candidate technologies and consistently assess and select technologies based on established selection criteria. Currently, over three hundred technologies are in the inventory which is continuously updated to include new advanced technologies as they emerge from laboratory. TSP follows a two-prong technology selection approach to identity technologies that have near term potential for stepchange in cost reduction as well as those that are emerging from laboratory with leapfrog potential for cost reduction. Technologies identified through this process are vetted through technical staff and management at the NCCC and DOE's review and approval are obtained prior to proceeding with testing. The NCCC's strong fundamental process engineering knowledge is also a key component to succeed in steering R&D scale technologies through process engineering and system integration development into commercialization. Coupling the TSP with NCCC 's in-house engineering expertise significantly reduces the risk of not being inclusive in technology choices and scales them up to commercial demonstration. Moreover, NCCC anticipates evaluation of multiple technologies annually. which increases the knowledge base of DO NOT Include Business Sensitive, Proprietary, am/lor Unclassified Controlled Information. Page 9 of 13 SoCo FOIA Response 002259 DOEINETL Carbon Capture Peer Review April 11-15.2011 03- Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility 14. POTENTIAL PROJECT RISKS available technologies moving through the development cycle. This field-generated knowledge will strengthen our technology evaluation and selection process in identifying the most promising technologies for further development. Risk #3 : Risk associated with safe operation of the NCCC considering that variety of technologies requires different integration and operation schemes. Risk 3 mitigation The NCCC at PSDF has an outstanding safety record. As part of the Southern Company's corporate commitment to Safety, the facility has worked 5,684 days without a lost-time accident and over I ,07 4 days without a recordable incident -demonstrating a serious approach to safe operations, even in a R&D setting working with new and unfamiliar technologies. This is accomplished through the procedures implemented at the NCCC such as safety training, safety procedures and Design Hazard Review (DHR) process. The DHR process is extremely important in identifying the potential risk areas associated with testing and operation of each candidate technology. As these risks are identified, corrective actions will be explored and implemented prior to the beginning of the testing. Given the nature of variety of technologies to be tested at the NCCC, proper training and adhering to the established safety review process will ensure safe operation of the NCCC. Through the rigorous project selection and testing programs and coupled with engineering knowledge of the power plant system, the NCCC is well positioned to successfully produce a portfolio of technology options, within budget and schedule, that could meet NETL's established goal ofless than 10 percent increase in COE for an IGCC plant and less than 35 percent increase for a pulverized coal plant. DO NOT lllc/11de B11si11ess Se11sitive, Proprietary, and/or U11classijied Co11trolled Ill/ormation. Page 10 of 13 SoCo FOIA Response 002260 1-*~ 0 f'l ...; 0 ' ~ g ~g = ·;:; ~ 2 1 5 ~ fool roil _ ro 12 > Cl 15 -.; .. :: >. ·-> ..... .. til .. :: 0:: 0 .... -..... .. ~a. a. .. ~ :;;: C .. u u f.! c :s ]E. c ~ ·- .s:::: ~ c ;:J 0 ~ u ~ 38 » ~ '-' 411 ~ fool U a: = -!1 _ . .. : Assess Candidate Tochnolograslor Test Consrderabons fslabl11~ t. Bollin 1Ttlomentiftg TSP f- AnAua1 TSP Data Up~ato & P•lo11tiu Funtoor Tottho, 1 --!- ___ ___. I _ __ - ·' s.. ~t"\ :::- 0 _ ~ _ _ 0 0 I.__ _ + + j 1:::1 ..... _ ~ !===""' " I .. "'" .~ .. • J. . _ _ i ~ :! ~ t:l 'U .5 . _ 1 ~=========:t:;:::;:i~~::;::~~ Procell DeveloE_ent ..._ • ........, ,.., ... - Clo ........ 0 ........... ............... 0 1 . -.. + + - -· - J ~ Q:l .. ~ 6 .::: (j + + lrn,.,...,...,,.. - -- - (., i 00 oo 0 ~ 7J 74 80 01 02 03 + + + ConductTostrngofC02Sorbtnll ConductTtstinLofC02Mernbrane ~ ~slflcallon 52 S4 oo 0 .. _ _ Co11d11ct Tu111!9 of C02 C"fiUie Solvents .., roil 0 01 a2 a:1 1 Gasilicalron Process D...,lopmont GHillcalloiiTOIIRIIns ·+ Determone Coai/Bromass AcC'flable Blendong Ranga ----:+ Identify ~mg E""'lopo lor booman & Braman/Coal Co-reed + Perform OIJ.Iine tesl with Dillarent Biomass/Coal _ Complete Phase II SCU Infrastructure Oj!grede __ Con1onue ~~Ill PDAC Coal Feeder Continuo Automotoc To J7 ro-1 t: f- ll f;il -;; 32 ~ llj OL 02 _Ql: ~ I 27 - .. '!a ~ ..cau.. i'-io u _g 'ij e= :s c oo 1 Post-eonobonrti;;;-C02 Toclmolo!IYOovolopmo111 Post-combustiOn C02 CIJ'IurO_DMiopment Select Location for PC.C at Gaston Plant ~ate PSTV Z lnstan Modular PSTV 0 _ 24 Complete PSTV & Continua BOP Construction fool "' 25 B!9on PSTV Commissi1>1111>9 ~ ~ - lli ~STV ~uhno Solvvnt Oferahon e8 01 02 _02 I :lll 21 22 23 Q] - tB ..5! .. oo ~~~~f~ ~~~~~~~3~~~~3~~~~~E~~~~E~~~F1 U,grado SCU Tettlnlrlltllucturo 011 Hooded Conduct Tottlnt_Q& Techllolotltl Becenro AvQIIablo 19 riJ u ro-1 .D ~ ~ az Conducl Vendot'a H2 Membtane T!_lli"R SCU !J9gradoto Su!j>GII N..., Hif' h"t Membtano & Sorbont Tesll ~ 0 "'E ------~;~~==~==~~==~~t~~XH~o~==~~3H~~~===y===;3~H2==~~~xn~J~~~4 ~I-- SCU lnfrlltlructtuoup,.~dn to Souort Tech11olosy Tutln2 9 SCU l.Jirg_radato S!'flport Low Temp H2/C02 Membrane Tesl Q. 1ii Bench Scale C02 Co;llure Solvvnt Evaluatron WGS Catolrst Test Sli£J!ort Membrane Test~ 4 ..E C § .. = li:1 ~ c 1 Pro-combuot•on C02 Clljl!ure DMI!:fmont Pre -ean•l••.,:tie n COl Technolo9Y D_!velo, ment J roil =:-=--:-:-===--=--- _ ~ !-.. ~ + 0 • c -::~~;;0 ;;;--:~:~~;;;;' ....,.,.,..,. Goo.o>lr&.mN~ 4 4 ............. • • - - ~ - SoCo FOIA Response 002261 DOEINETL Carbon Capture Peer Review April I 1-15, 201 I 03- Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility 16. ADDITIONAL PROJECT INFORMATION Effective technology assessment at the NCCC begins with a screening process to ensure that the technologies to be tested and developed have strong potential for commercial success. After the technology is tested, data analysis and public reporting provide industry with key information for improving technology development strategies. (Read Section 2.0 in attached document #I for more detail about the screening process.) In the post-combustion C02 capture area, establishing the PC4 is one major effort at the NCCC. It is located at adjacent Alabama Power E.C. Gaston plant site, near the flue gas outlet of the Gaston Unit 5, an 880 MW supercritical pulverized coal unit. PC4 is designed to provide several parallel paths to test candidate processes at appropriate scales. The facility will include a PSTU and a slipstream or multiple, small-scale tests, and it will support integration of test skids developed by outside technology developers. (Read Section 2.3 in attached document #2 for more detail about PC4.) In the pre-combustion C02 capture research areas, NCCC has collaborated with many technology developers to integrate their technology with our syngas slipstream test facility to carry out multiple tests. Current technology portfolio includes University of Pittsburgh/NETL 's physical solvent, Membrane Technology and Research's polymeric hydrogen and C02 membranes, Media Process and Technology's carbon molecular sieve hydrogen membrane, Johnson-Matthey's high temperature mercury capture sorbents and various WGS catalysts. (Read Section 2.2 in attached document #3 for more detail.) Current oxy-combustion concepts for both pulverized coal boilers and circulating fluidized-bed combustors use oxygen mixed with recycled COz to replace air as the oxidant for combustion. In both concepts, operations are at near atmospheric pressure which presents two challenging issues: air ingress and large volume ofC01 recycle. A pressurized oxy-combustion design would resolve both issues. Researchers at the NCCC conducted a screening level engineering and economic study to estimate the performance and cost for a proposed advanced power generation system using the transport reactor in a pressurized oxy-combustion mode to produce electric power and sequestration-ready C02• (Read Section 2.2 in attached document# I for more detail.) Based on the positive results of the screening study, the NCCC has conducted an engineering study that compared repowering a 250 MW pulverized coal unit with a pressurized Transport Oxy-Combustion process (TROCTM) versus the retrofitting of the same unit with conventional emissions control equipment along with post-combustion C01 capture. A report, "Engineering Assessment of Retrofit and Repowering Options for C01 Capture at a Pulverized Coal Plant", containing the study results was drafted and sent to DOE for review. The study included preliminary process designs, site layouts and vendor supplied estimates of capex and O&M costs. Based on findings to-date, TROCTM warrants further analysis and current plans are to continue to evaluate the economic merits through planned dispatch modeling of various TROCn' alternatives. Attached documents: #I National Carbon Capture Center Topical Report Budget Period I, DOE Cooperative Agreement DE - NT0000749, October I, 2008 to November 20, 2009. #2 National Carbon Capture Center Project Progress Report, DOE Cooperative Agreement DE- NT0000749, January I, 2010 to March 31,2010. #3 National Carbon Project Progress Report, DOE Cooperative Agreement DE- NT0000749, July I, 2010 to September 30, 2010. DO NOT Include Business Sensitive, Proprietary, and/or Unclassified Controlled Information. Page 12 of 13 SoCo FOIA Response 002262 DOE/NETL Carbon Capture Peer Review April 11·15, 2011 03- Project# NT0000749, National Carbon Capture Center at Power Systems Development Facility 17. PROJECT BIBLIOGRAPHY Tony Wu, Subhash Datta, Robert C. Lambrecht, John Wheeldon, Hugh Hamilton, Liz Rowsell, Stephen Poulston, Andrew Smith, Evan J. Granite and Henry W. Pennline, Field Tests of Palladium Sorbents for High Temperature Capture of Mercury, Arsenic. Selenium From Syngas, AIChE Spring Meeting, March 15,201 I Tony Wu, Alex Bonsu, RobertS. Dahlin, E. Carl Landham and John Wheeldon, Evaluation of Advanced Solvents for COz Caoture From Syngas, AlChE Spring Meeting, March 16, 201 I John Wheeldon, National Carbon Capture Center: Pre-Combustion Focus, NETL 2010 COz Capture Technology Meeting, September 16,2010 Doug Maxwell, National Carbon Capture Center: Post-Combustion Focus, NETL 2010 COz Capture Technology Meeting, September 15,2010 Morton, Frank; Bowers, Kerry; Doug Maxwell; Mosser, Mike; National Carbon Capture Center Status, Ninth Annual Conference on Carbon Capture and Sequestration, May 10,2010 Dorminey, Johnny; Northington, John; Leonard, Roxann; Yongue Ruth Ann; Lignite Gasification Testing at the Power System Development Facility, 34th International Technical Conference on Clean Coal and Fuel Systems May 31- June 4, 2009 Morton, Frank; Bowers, Kerry; Monroe, Larry; Mosser, Mike; PSDF COz Capture Technology Development, Eighth Annual Conference on Carbon Capture and Sequestration, May 4, 2009 Vimalchand, P.; Morton, Frank C.; Datta, Subhash; Lambrecht, Robert C.; Granite, Evan J.; Pennline, Henry W.; Stanko, Dennis C.; Hamilton, Hugh; Rowsell, Liz; Poulston, Stephen; Smith, Andrew; llkenhans, Thomas; Chu, Wilson; Slipstream Tests of Palladium Sorbents for High Temperature Capture of Mercury. Arsenic. Selenium and Phosphorus from Fuel Gas, AIChE Spring Meeting, April 30, 2009 DO NOT Inclllde Business Sensitive, Proprietary, antVor Unclassified Controlled Information, Page 13 of 13 SoCo FOIA Response 002263 From: Sent: To: Cc: Subject: Attachments: Approvai_FITS Tuesday, July OS, 20111:40 PM Mosser, Morgan H. Dvorscak, Mark Award: DEFC2608NT0000749, Topical Report Period Ending: 5/l/2011 (00749TOR_A050111) 00749TOR_A05011l.pdf Subject: Review of Final Technical Report on ContracUGranUCooperative Agreement No. DEFC2608NT0000749 with Southern Company Services Inc Period Ending 5/1/2011 Morgan Mosser and Patent, The attached technical/topical report has been submitted by the contractor/recipient and requires your review and approval. Review should be completed within 30 calendar days of the date of this e-mail. Please provide the contractor/recipient with approval or notification of changes required prior to approval, and obtain and approve these changes. A copy of your correspondence concerning the report should be provided to the Contract Specialist. After reviewing the report, please provide an e-mail approval. All Technical Reports are provided to OSTI for public access in accordance with DOE Order 241.1A. In addition to sending this report to OSTI, would public distribution of this report at the FE Headquarters' website be beneficial. Yes No Please indicate with a checkmark below all items that relate to the report: General Energy Policy _Clean Coal Technology (must also include one of the following). Coal- Fuels Coal • Industrial Processes Coal • Environmental Processes _ Electricity • General _ Electricity • Coal Combustion _ Electricity - Gasification _Electricity- Fuel Cells _ Electricity - Turbines _ _ Electricity - Regulatory Oil/Gas - Regulatory Oil/Gas - General _Oil/Gas- Supply Technologies (must also include at least one of the following) _ Oil/Gas - Drilling/Completion, Stimulation _Oil/Gas - Diagnostics/Imaging Oil/Gas - Reservoir Life Extension Oil/Gas - Gas Storage _ Oil/Gas - Processing = SoCo FOIA Response 002264 _ Oil/Gas - Environmental Oil/Gas - Modeling/Analysis _ Materials/Components/1 nstrumentation _ International Analysis After reviewing the attached report, please e-mail me your approval or a copy of your letter requesting a revision. Thank you, Colleen McDonald 2 SoCo FOIA Response 002265 THE NATIONAL CARBON CAPTURE CENTER AT THE POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO DECEMBER 1, 2009- DECEMBER 31,2010 DOE Cooperative Agreement ./ DE-NT0000749 Prepared tly: Southern Company Services, Inc. Power Systems Development Facility P.O. Box 1069 Wilsonville, AL 35186 Phone: 205-670-5840 Fax: 205-670-5843 htto://www.NationaiCarbonCaptureCenter.com SoCo FOIA Response 002266 DISCLAIMER This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, nor Southern Company Services, Inc., nor any of its employees, nor any of its subcontractors, nor any of its sponsors or cofunders, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer or otherwise, does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. This report is available to the public from the National Technical Information Service, U.S. Department of Commerce, 5285 Port Royal Road, Springfield, VA 22161. Phone orders are accepted at (703) 487-4650. SoCo FOIA Response 002267 ABSTRACT The Power Systems Development Facility (PSDF) is a state-of-the-art test center sponsored by the U.S. Department of Energy and dedicated to the advancement of clean coal technology. In addition to the development of advanced coal gasification processes, the PSDF features the National Carbon Capture Center (NCCC) to study C02 capture from coal-derived syngas and flue gas. The NCCC includes multiple, adaptable test skids that allow technology development of C02 capture concepts using coal-derived syngas and flue gas in industrial settings. Because of the ability to operate under a wide range of flow rates and process conditions, research at the NCCC can effectively evaluate technologies at various levels of maturity. During the Budget Period Two reporting period, efforts at the PSDF/NCCC focused on new technology assessment and test planning; designing and constructing post-combustion C02 capture facilities; testing of pre-combustion C02 capture and related processes; and operating the gasification process to develop gasification related technologies and for syngas generation to test syngas conditioning technologies. SoCo FOIA Response 002268 ACKNOWLEDGEMENT The authors wish to acknowledge the contributions and support provided by various project managers, including Morgan "Mike" Mosser of the Department of Energy and John Wheeldon of the Electric Power Research Institute. The project is sponsored by the U.S. Department of Energy National Energy Technology Laboratory under cooperative agreement DE-NT0000749. SoCo FOIA Response 003314 SoCo FOIA Response 002269 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO TABLE OF CONTENTS Section........................................................................................................................................ Page Inside Cover Disclaimer Abstract Acknowledgement List of Figures ................................................................................................................................ iii List ofTables ................................................................................................................................... v Glossary of Abbreviations and Engineering Units ........................................................................ vi 1.0 Executive Summary ............................................................................................................. 1 2.0 Technology Assessment. ..................................................................................................... .4 2.1 Technology Screening ............................................................................................ .4 2.2 2.1.1 Technology Screening Process .................................................................. .4 2.1 .2 Technology Screening Results .................................................................... 5 Economic and Engineering Studies ......................................................................... 6 2.2.1 Study Basis..................................................................................................6 2.2.2 Method of Study ......................................................................................... 7 2.2.3 Description of Post-Combustion Capture Case ..........................................8 2.2.4 Description of the TROC Cases..................................................................8 2.2.5 Results .........................................................................................................9 2.2.6 Costs of C02 Capture and Avoidance ....................................................... l2 2.2.7 3.0 Conclusions ............................................................................................... 12 Pre-Combustion C02 Capture ............................................................................................ l4 3.1 Syngas Conditioning Unit. ..................................................................................... l4 3.2 3.3 3.4 Water-Gas Shift Catalyst Testing .......................................................................... 15 C02 Capture Testing ..............................................................................................20 3.3 .1 Ammonia Chemistry .................................................................................20 3.3.2 Polydimethylsiloxane ................................................................................26 3.3.3 Potassium Carbonate and Potassium Prolinate .........................................30 Gas Separation Membranes ...................................................................................32 3.4.1 Membrane Technology & Research Hydrogen and C02 Membranes ......32 3.4.2 Media & Process Technology H2 Membrane ...........................................36 3.4.3 Membrane Material Coupon Testing ........................................................ 37 SoCo FOIA Response 002270 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Section........................................................................................................................................ Page 4.0 Post-Combustion C02 Capture ..........................................................................................39 4.1 PC4 Design and Construction ..................................................................................40 4.2 Pilot Solvent Test Unit .............................................................................................45 4.2.1 PSTU Test Planning ..................................................................................47 4.2.2 PSTU Commissioning ..............................,............................................... 53 4.3 Planned Testing in 20 11 ........................................................................................... 55 5.0 Gasification Process ...........................................................................................................56 5.1 Developmental Coal Feeder.....................................................................................56 5.2 Biomass Evaluation .................................................................................................51 5.2.1 Biomass Fuel Handling and Feeding ........................................................59 5.2.2 Gasifier Operation .....................................................................................60 5.2.3 Effect of Biomass Co-Gasification on Ash Characteristics ......................62 5.3 Sensor Development ................................................................................................ 64 5.3.1 Sapphire Therrnovvell ................................................................................ 64 5.3.2 Densflow Coal Flow Meter.......................................................................65 5.3.3 Coal Feeder Level Probes .........................................................................66 5.4 Gasifier Performance Evaluation .............................................................................67 5.5 Hot Gas Filter Element Evaluation .......................................................................... 68 5.6 Johnson Matthey Mercury Sorbent ..........................................................................69 6.0 Conclusions and Lessons Learned ..................................................................................... 72 6.1 Technology Assessment ...........................................................................................72 6.2 Pre-Combustion C02 Capture and Separation ......................................................... 72 6.3 Post-Combustion C02 Capture ................................................................................74 6.4 Gasification Process ................................................................................................. 74 li SoCo FOIA Response 002271 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO LIST OF FIGURES Figure ......................................................................................................................................... Page NCCC/PSDF Facilities ........................................................................................................ 2 2 Levelized Cost of Electricity at 75 Percent Capacity Factor for All Study Cases............. l1 3 LCOE Sensitivity to Capacity Factor ................................................................................ 12 4 Flow Diagram of the Syngas Conditioning Unit ............................................................... 14 5 Gas Analyzer Building for the Syngas Conditioning Unit ................................................ 15 6 Temperature Profile in the Fixed Bed Reactor during R05 ............................................... 17 7 Amount of C02 Produced Compared to Amount of CO Shifted ....................................... 18 8 Amount ofH2 Produced Compared to Amount ofCO Shifted ......................................... 18 9 Comparison of Methane Content Entering and Exiting the WGS Reactor ....................... 19 10 Comparison of Actual and Equilibrium WGS Conversions .............................................. 19 II Output Signal from NMR Ana1yzer ...................................................................................21 12 Comparison of Measured and Predicted Concentrations of Ammonia Compounds .........21 13 Comparison of Measured and Predicted C02 Capture Efficiencies ..................................22 14 Comparison of Measured and Predicted Ammonia Slip....................................................23 15 Change in Ammonia Liquor Composition with Reactor Temperature ..............................23 16 Example of a Raman Spectrum ..........................................................................................24 17 Comparison of Predicted Values for Ammonia Solution ..................................................25 18 C02 Concentration Profile during Absorption Following Flash Regeneration ................. 27 19 Effectiveness of C02 Regeneration at Different Flash Pressures ......................................27 20 H2S Concentration Profile during Absorption Following Flash Regeneration .................. 28 21 H2S concentration Profile during Absorption Following Thermal Regeneration ..............29 22 Effectiveness of H2S Regeneration at Various Flash Pressures.........................................29 23 Effect of Water Addition to DEPG and PDMS on C02 Absorption .................................30 24 C02 Capture Efficiencies for Potassium Prolinate and Potassium Carbonate...................31 25 Pressure Increase during Regeneration ofThree C02 Capture Solvents ...........................32 26 Schematic ofMTR's Thin-Film Composite Membrane ....................................................32 27 Schematic ofMTR's Spiral-Wound Membrane Assembly .............................................. .33 28 MTR Membrane Test Equipment ......................................................................................34 29 MTR C02 Membrane Performance during R03 ................................................................35 iii SoCo FOIA Response 002272 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Figure ......................................................................................................................................... Page 30 MTR H2 Membrane Performance during R04 .................................................................. .35 31 Media & Process Technology Hydrogen Membrane Assembly ........................................ 37 32 X-Ray Diffraction Analyses of Membrane Material Coupons Exposed to Filtered Syngas ..............................................................................................................................38 33 PC4 Site at the E.C.Gaston Plant. ......................................................................................39 34 PC4 Site Layout .................................................................................................................39 35 PC4 Site Preparation Work ................................................................................................40 36 BOP Area Foundation with Chemical Storage Tank and Pump Pads .............................. .41 37 Installation of PC4 Utility Bridge ......................................................................................41 38 Installed PSTU Structure ...................................................................................................42 39 PSTU 3-D Model and Construction ...................................................................................43 40 Schematic of PSTU ............................................................................................................45 41 Total C02 Analysis Apparatus ...........................................................................................52 42 Flow Diagram of PSDF Gasification Process .................................................................... 56 43 Wood Pellet Biomass Used as Gasification Feedstock in R03 and R04 ...........................58 44 Modifications to the Dense Phase Transfer Line for Biomass Conveying ........................60 45 Gasifier Ash Samples during Coal-Only Feed and during Biomass Co-Feed in R04 ....... 61 46 Post-Run Inspection of Primary Gas Cooler Tubes ...........................................................61 47 Particle-Size Distributions of Ash Measured at PCD lnlet ................................................62 48 Transient PCD Drag as a Function of Carbon Content...................................................... 63 49 Effect of Biomass Addition on Laboratory Drag Measurements ...................................... 64 50 Comparison of Temperature Readings for Sapphire and HR-160 Thermowells ............... 65 51 Comparison of Flow Rates from DensFiow Meter and from Weigh Cell Indications ......66 52 Gasifier Solids Circulation Rate versus Fluidization Rate to Bottom of Standpipe ..........67 53 Gasifier Temperature Response to Set Point Change ........................................................ 68 54 Gasifier Temperature Control Steady State Performance ..................................................68 55 Reactor Inlet and Outlet Mercury Concentrations during Sorbent Testing ....................... 70 56 GC-ICP/MS at DOE-NETL Laboratory ............................................................................ 71 iv SoCo FOIA Response 002273 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO LIST OF TABLES Table .......................................................................................................................................... Page Major Project Milestones for Budget Period Two ............................................................... 3 2 Quantitative Technology Screening Criteria ...................................................................... .4 3 Format for the NCCC Technology Evaluation Report ........................................................ 5 4 Technology Screening Team ...............................................................................................5 5 Retrofit and Repo\vering Study Cases ................................................................................. 7 6 Performance and Major Flows With and Without C02 Capture ......................................... 9 7 C02 Recovery and Product Purity for Study Cases ........................................................... ! 0 8 Levelized Cost of Electricity for All Study Cases ............................................................. 10 9 Costs of C02 Capture and Emissions Avoided for All Study Cases ................................. 12 10 Water-Gas Shift Catalyst Test Conditions ......................................................................... l6 II Mean Syngas Compositions at Water-Gas Shift Reactor Inlet and Outlet ........................ 17 12 Properties of DEPG and PDMS Solvents ..........................................................................26 13 Nominal Test Conditions for OfT-Line C02 Capture Testing with PDMS and DEPG ..... 26 14 Properties of Potassium Carbonate and Potassium Prolinate Solvents ..............................30 15 MTR Membrane Test Conditions ...................................................................................... 34 16 Pure Gas Permeance Measurements of the MPT Hydrogen Membrane ........................... 37 17 Design Characteristics of PSTU Columns .........................................................................46 18 Draft Test Matrix for 30 Percent MEA Testing ................................................................ .48 19 PSTU Gas Analysis Techniques ........................................................................................49 20 PSTU Liquid Analysis Techniques ....................................................................................50 21 PSTU Quality Assurance Procedures ................................................................................51 22 Proposed Techniques for Assessing Analytical Accuracy and Precision .......................... 52 23 PC4 Tests Planned for 20 I I ............................................................................................... 55 24 Biomass Properties before and after Milling ..................................................................... 59 25 Steady State Carbon Conversions for R03 and R04 .......................................................... 60 26 Effect of Biomass Co-Gasification on Ash Characteristics ............................................... 62 27 Hot Gas Filter Elements Tested During BP2 .....................................................................69 28 Operating Conditions for Mercury Sorbent ....................................................................... 70 v SoCo FOIA Response 002274 TOPICAL REPORT BUDGET PERIOD TWO NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY GLOSSARY OF ABBREVIATIONS AND ENGINEERING UNITS Abbreviations ABC-Ammonium Bicarbonate ASU-Air Separation Unit B& W-Babcock & Wilcox BOP-Balance of Plant BPI-Budget Period One BP2-Budget Period Two CH~-Methane CO-Carbon Monoxide COz-Carbon Dioxide CPU-C02 Purification and Compression Unit Des-Distributed Control System DEPG-Dimethyl Ether of Polyethylene Glycol DOE-Department of Energy EPA-Environmental Protection Agency EPRI-Eiectric Power Research Institute FEAL-Iron Aluminide FGD-Fiue Gas Desulfurization FRP-Fiberglass Reinforced Plastic FTIR-Fourier Transform Infrared GC-Gas Chromatograph Hz-Hydrogen H2S-Hydrogen Sulfide HCI-Hydrochloric acid HHV-Higher Heating Value HMI-Human Machine Interface ICP-MS-Inductively Coupled Plasma-Mass Spectrometer ID-Induced Draft IGCC-Integrated Gasification Combined Cycle KF-Potassium Flouride KOH-Potassium Hydroxide L/G-Liquid-to-Gas Ratio LCOE-Levelized Cost of Electricity MCC-Motor Control Center MEA-Monoethano\amine MMD-Mass Median Diameter MPT-Media & Process Technology MTR-Membrane Technology & Research 2NH~HCOJ-Ammonium Carbonate (NHJ)zCOJ-Ammonium Carbamate NCCC-National Carbon Capture Center NDIR-Non-Dispersive Infrared NHJ-Ammonia NMR-Nuclear Magnetic Resonance NOx-Nitrogen Oxides O&M-Operations and Maintenance PC-Pulverized Coal PC4-Post-Combustion Carbon Capture Center PCC-Post-Combustion Capture PCD-Particulate Control Device PDAC-Pressure Decoupled Advanced Coal PDMS-Polydimethylsiloxane PLC-Programmable Logic Controller PRB-Powder River Basin PSDF-Power Systems Development Facility PSTU-Pilot Solvent Test Unit RO I through R05-Test Runs I through 5 R&D-Research and Development S/L-Steam-to-Liquid Ratio SCR-Selective Catalytic Reduction SCS-Southern Company Services SCU-Syngas Conditioning Unit SEM-Scanning Electron Microscope S02-Sulfur Dioxide SOx-Sulfur Oxides SRI-Southern Research Institute TCA-Total C02 Analysis TROC-Transport Oxy-Combustion TSP-Technology Screening Process WGS-Water-Gas Shift vi SoCo FOIA Response 002275 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY Engineering Units Btu-British thermal units °C-degrees Celcius cm2-square centimeters cm 3-cubic centimeters cmHg-centimeters of mercury °F-degrees Fahrenheit ftls-feet per second g/cm3-grams per cubic centimeter g-mol-gram-mole gpu-gas permeation unit hr-hours kcal--kilocalorie k llr-kilo pound KVA-kilovolt amps kW-kilowatts kWhr-kilowatt hours TOPICAL REPORT BUDGET PERIOD TWO kW-yr-kilowatt years llr-pounds lb-mol-pound-mole lb/hr-pounds per hour m2-square meters m3-cubic meters MM-million molo/ct-mole percent MW-megawatts ppmv-parts per million by volume psi-pounds per square inch psia-pounds per square inch absolute rpm-revolution per minute s or sec-seconds volo/ct-volume percent \vto/ct-weight percent vii SoCo FOIA Response 002276 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY E ECUTIVE SU TOPICAL REPORT BUDGET PERIOD TWO ARY The Power Systems Development Facility (PSDF) is a key national asset for ensuring continued, cost-effective, environmentally acceptable energy production from coal. Sponsored by the U.S. Department of Energy (DOE), the PSDF is an engineering scale test center located in Wilsonville, Alabama. The PSDF staff has effectively developed advanced power systems to meet the national need for cleaner, more efficient power production from coal. Building on its previous success, PSDF now houses the National Carbon Capture Center (NCCC), established in 2009 to address the nation's need for cost-effective, commercially viable C0 2 capture options for flue gas from pulverized coal power plants and syngas from coal gasification power plants. The NCCC is leading the way to lower-cost C02 capture technologies and to enable coal-based power generation to remain a key contributor to providing affordable, reliable, and clean power generation. The facilities accommodate a range of equipment sizes and provide commercially representative test conditions that allow results to be scaled confidently to commercial application, a crucial element in shortening development times. Project Partnership with DOE. The DOE conceived the PSDF as the premier advanced coal power generation research and development (R&D) facility of the world, to "serve as the proving ground for many new advanced power systems." Since operations began in 1996, the PSDF has been a center for national efforts to develop high efficiency, coal-based power generation technologies that are reliable, environmentally acceptable and cost effective. Two significant achievements-in addition to many secondary goals that were met-were the development of hot gas filtration to improve energy efficiency and the development of a gasifier suitable for use with low-rank coals. These two technologies have progressed to commercialization with integrated gasification combined cycle (IGCC) power plants under construction in Kemper County, Mississippi, and Dong Guan, China. ProjectMissionandApproach. The mission of the NCCC/PSDF is to develop advanced power generation technologies to allow the continued use of coal in an efficient and environmentally clean manner, thereby supporting national, economic, and energy security. The work to be undertaken will support the next stages of coal-fired power technologies and the continued operation of conventional coal-tired power plants under C02 emission constraints. In undertaking its mission, the NCCC/PSDF is involved in a range of activities to develop the most promising technologies for future commercial deployment, thereby maximizing the impact of project funds. The test facilities, shown in Figure I, include the original PSDF site, which houses the gasification process and pre-combustion C02 capture test site, and the PostCombustion Carbon Capture Center (PC4), located at a major power plant on the same Alabama Power (Southern Company) property. SoCo FOIA Response 002277 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Figure 1. NCCC/PSDF Facilities. Pre-combustion C02 capture is vital for the advancement of efficient gasification processes needed for state-of-the-art coal-fired power plants. The backbone of the NCCCIPSDF precombustion C02 capture technology development is a high-pressure, flexible facility designed to test an array of solvents, contactors, membranes, sorbents, and water-gas shift processes. Slipstreams are available with a range of gas flow rates and process conditions using coalderived syngas for verification and scale-up of fundamental R&D C02 capture projects. The NCCC/PSDF is also exploring post-combustion capture technology development. For both new and existing power plants, post-combustion C02 capture must be made more efficient and cost-effective by developing alternative technologies, such as solvents with lower heats of regeneration and lower cost equipment compared with the current technically viable options. The PC4 provides a wide range of process conditions for testing with coal-derived flue gas. Further, the NCCC/PSDF staff will evaluate oxy-combustion as a way to significantly reduce C02 emissions from coal-fired power generation. Researchers at the NCCC will build on their previous operational experience with the Transport Reactor to investigate the economic feasibility of operating it as an oxygen-blown, pressurized, circulating fluid bed combustor. The research to be completed includes engineering studies to compare the Transport Reactor oxycombustion process to other power plant options. Finally, work will continue in developing technologies specifically related to coal gasification processes. While the previous successful testing of the PSDF gasification process has led to commercialization of several processes (e.g., the Transport Gasifier and continuous fine ash removal systems), important work remains to make IGCC processes more reliable. efficient, and 2 SoCo FOIA Response 002278 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO commercially viable. Including COz capture in advanced coal power plants will increase the plant cost of electricity, so opportunities to reduce cost in every part of the gasification process will be pursued. The considerable on-site expertise in gasification processes as well as the unique testing opportunities afforded by the existing PSDF gasification process make continued gasification process development a logical and cost-effective undertaking. In partnership with the DOE, the NCCC/PSDF established and met the milestones listed in Table I during Budget Period Two (BP2). Table 1. Major Project Milestones for Budget Period Two. Resear Area Gasification Pre-Combustion Oxy-Combustion Post-Combustion Pre-Combustion Fuel Flexibility Gasification Fuel Flexibility Support Post-Combustion Pre-Combustion GasifiCation Pre-Combustion Post-Combustion Post-Combustion Fuel Flexibility Oxy-Combustion Post-Combustion I estone Conduct qasif!Cation test run R03 Support membrane testinq Evaluate commercial feasibility ofTransport Reactor in oxycombustion mode in preliminary screeninq Complete design of Pilot Solvent Test Unit (PSTU) and associated BOP infrastructure Complete first phase of SCU infrastructure upgrades Perform off-line test with different biomass/coal Conduct R04 test run Co-feed biomass with coal for 100 hours test Complete annual technology screening and set BP3 priorities Receive and install modular PC4 utility pipe bridge and begin receivinq modular PSTU Complete second phase of SCU infrastructure upqrades Conduct R05 test run Perform tests with new water-gas shift catalysts to lower steam-toCO ratios Instan modular PSTU Complete PSTU and continue post-combustion BOP construction Continue improvements in PDAC coal feeder performance, including reducing feed perturbations and increasing solid-to-gas ratios Evaluate commercial feasibility of Transport Reactor in oxycombustion mode by completing detailed system studies and economic analvsis Beqin PSTU commissioning anne eUon Date Nov2009 Dec2009 At a Co eUon Date Dec2009 Dec2009 Re ort Reeren e Se lion 5.0 3.4 Jan 2010 Jan 2010 2.2 Mar2010 Mar2010 4.2 Mar2010 Mar2010 Apr2010 Jun 2010 Jun 2010 Mar2010 Mar2010 Apr2010 Apr2010 Jun 2010 3.1 5.2.1 5.0 5.2 2.1 Jun 2010 Jun 2010 4.1 Jun 2010 Aug 2010 Jun 2010 Aug 2010 3.1 5.0 Co Sep 2010 Sep2010 3.2 Sep2010 Nov 2010 July 2010 Nov2010 4.1 4.1 Dec2010 Sept2010 5.1 Dec2010 Dec2010 2.2 Oec2010 Dec2010 4.22 Project Partners. Southern Company Services manages and operates the facility, and other project participants include the Electric Power Research Institute and leaders in the power and coal industries, including American Electric Power, Luminant, NRG Energy, Arch Coal, Peabody Energy, and Rio Tinto. 3 SoCo FOIA Response 002279 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO TEC NOLOGY ASSESS ENT Effective technology assessment begins with a screening process to ensure that the technologies to be tested and developed have strong potential for commercial deployment. This is accompanied by preliminary economic analysis of integrated plant configurations to assess the overall process economic feasibility. After the technology is tested, data analysis and public reporting provide industry with key information for improving technology development strategies. TEC NOLOGY SCREENING In order to identify technologies for inclusion in the NCCC test plan, the technology screening process was developed in collaboration with DOE's National Energy Technology Laboratory (NETL). TEC NOLOGY SCREENING ROCESS Candidate technologies are evaluated using both quantitative screening criteria shown in Table 2 and qualitative screening criteria related to shared DOE and NCCC objectives and budget considerations. The factors influencing DOE/NCCC objectives include cost reduction, fuel flexibility, short-term commercial implementation, and long-term potential. Budget considerations affecting qualitative screening criteria include project funding level, cost of testing, cost of developing, and ease of accommodation. Table 2. Quantitative Technology Screening Criteria. Ran ing Categor an 5 oring Criteria I. Projected Benefits • Impact on total cost of electricity • Impact on energy consumption • Impact on capital cost • Impact on power plant efficiency • C02 emission reduc~on II. Technology Strength • Scientific soundness of concept • Current status of the technology • Simplicity and robustness • • eig ling Fa tor 60% 30% Commercializa~on Environmental soundness Ill. Organization StrenQth • Intellectual propertynicense of the technoloqy Capability of further development • Technical and manaqementteam 10% • The DOE NETL and the NCCC communicate throughout the screening process, which involves: 4 SoCo FOIA Response 002280 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY • • • • • TOPICAL REPORT BUDGET PERIOD TWO Selection of a technology developer from a technology pool Evaluation of the selected technology developer with due diligence using criteria agreed upon by the DOE/NCCC screening team Establishment of non-disclosure agreements with the selected developer in order to receive detailed information Recommendation by the DOE and NCCC screening team after review of a technology evaluation report written by the NCCC staff Finalization of legal and engineering documentation for the projects and testing of the selected technology The technology evaluation reports follow the format given in Table 3 and include a scoring system. After reviewing the report, the screening team (see Table 4) decides whether to include it in the NCCC test plan. Since the information in the technology evaluation reports is confidential, the reports are held at the NCCC site and are available for DOE review. Table 3. Format for the NCCC Technology Evaluation Report. 1. Introduction 2. Technology Summary 3. Technology History 3.1. Test Results 3.2. Future Test Plans 3.3. Pathway to Commerciafizalion 4. Proiected Benefits 5. TechnologySrren~h 6. OrQanizational StrenQth 7. Summary Table 4. Technology Screening Team. DOENETL Jared Cifemo John Litynski Michael Matuszewski Moman "Mike" Mosser NCCC SDF Doug Maxwell Frank Morton John Wheeldon TonyWu ~ge"Geo"R~aros TEC NOLOGY SCREENING RESULTS In December 20 I0, the technology screening team met to discuss the evaluations of technologies from Babcock & Wilcox (B&W), Aker Solutions, and Chiyoda Corporation. After presentation of the evaluations by the NCCC and discussion among the group, NETL agreed with the NCCC proposal to incorporate testing by B&W, Aker, and Chiyoda into the NCCC test plan. Babcock & Wilcox. B& W is developing a post-combustion C02 capture process based on amine solvents. The group has screened many solvents at a lab scale at the company's R&D center in Barberton, Ohio, and has verified the lab results on five amine solvents at its 0.3 MW pilot plant. 5 SoCo FOIA Response 002281 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO B&W proposes to test its best perfonning solvent at the NCCC. The selected solvent will be provided by the University of Texas. Aker Solutions. Aker is developing a post-combustion C02 capture process based on amine solvents. Aker has refined its process in progressively larger tests from lab scale up to a 1.0 MW, self-contained mobile test unit that includes process equipment and controls. Aker proposes to test its best performing solvent in the test unit with flue gas from the PC4 in 20 I I. Chiyoda Corporation. Chiyoda is developing a post-combustion C02 capture process based on amine solvents. Chiyoda has screened many solvents and proposes to test its best performing solvent in the PC4 in late 20 I I or early 20 12. ECONO IC AND ENGINEERING STUDIES In 2009, researchers at the NCCC conducted a screening level engineering and economic study to estimate the performance and cost for a proposed advanced power generation system using the Transport Reactor in a pressurized oxy-combustion system to produce electric power and sequestration-ready C02. Results of this screening-level analysis of the Transport OxyCombustion (TROC™) system were described in the Budget Period One Topical Report and showed that the technology holds considerable promise and warrants further development and study. Because of these positive preliminary results from the screening study, a more detailed engineering economic evaluation was performed in BP2. During the BP2 reporting period, staff compiled a study entitled "Engineering Assessment of Retrofit and Repowering Options for C02 Capture at a Pulverized Coal Plant." The purpose of the study was to evaluate the economic prospects of C02 capture from an existing mid-size coaltired power plant by either retrofitting the plant with post-combustion C02 capture or by repowering the plant with the TROC technology . The results of the study will guide research and development of C02 capture technologies at the NCCC. STUDY BASIS Two technologies were evaluated for C02 capture repowering and retrofit of a sub-critical 250 MW pulverized coal (PC) unit: post-combustion capture and oxy-combustion. The base case in the study adds the following post-combustion technologies to the PC unit: • • • • Selective catalytic reduction (SCR) to reduce NOx to less than 0.03 lb/MMBtu on a higher heating value (HHV) basis Baghouse to capture mercury and aerosols while reducing particulates below 0.01 lb/MMBtu Flue gas desulfurization (FGD) to capture more than 98 percent of the flue gas S02 C02 capture, drying, and compression systems to capture 90 percent of the C02 and produce 99.99 percent pure product C02 Five cases ofTROC, a pressurized oxy-combustion process being evaluated at the NCCC, were investigated. This technology inherently controls particulate, NOx, SOx, and C02 without the addition of pollution control equipment such as SCR or FGD systems. Four cases were 6 SoCo FOIA Response 002282 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO examined in this study to investigate different C02 purification options delivering varying levels of product C02 purity. A fifth case investigated the financial effects ofrepowering at a more compact site, i.e., one with a smaller footprint. Table 5 summarizes the six study cases. Table 5. Retrofit and Repowering Study Cases. Base Case (PCCl Case 1 Case2 Case3 Case4 CaseS Te noog Post-combustion capture TROC with no CCh puriftcation TROC with 02 scavenoino TROC with partial condensation TROC with distillation Case 4 at a compact site ET 00 OF STUDY A representative site for repowering and retrofit was selected from among the Southern Company generating plants as the basis for this study. It holds two nominal 250 MW coal units with low-NOx burners, over-fire air, and precipitators that burn bituminous coal to drive a 2,400 psia /I ,000°F I I ,000°F steam cycle. Capital costs for the post-combustion capture case SCR, baghouse, FGD, and C02 capture systems were estimated building on vendor quotes, while estimates for the required interconnections and added balance of plant systems were developed by Southern Company Services. Operating costs were calculated based on existing plant costs and adding the additional personnel, capital repairs, and consumables required for the new systems, or by using a factor of capital supplied by a system vendor. For the TROC cases, the air separation unit (ASU) and C02 compression and purification unit (CPU) capital costs were supplied by a vendor (on a turnkey basis), the TROC island costs were scaled from Southern Company data on similar systems, and the interconnections and new balance of plant systems were estimated by Southern Company Services. Operating costs were estimated in the same manner as for the post-combustion capture case. The expected error band on the capital costs is ±25 percent based on the level of engineering work completed. Since a large majority of the equipment is common to all cases, comparative costs are more accurate than the error band given above. All costs are presented in January 20 I 0 dollars. Detailed heat and material balances were completed for all cases utilizing original equipment performance data from the PC unit steam cycle. These include compressing the product C02 to 2,200 psia at the plant boundary. Different options for integrating the new technologies with the existing steam cycle were investigated, and each case was optimized for cost and perfonnance. Preliminary site layouts were also completed to ensure that all systems fit in the available space. For Case 5, it was assumed that expansion space was not available at the site, so costs were 7 SoCo FOIA Response 002283 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO added for boiler and precipitator demolition to make room for the TROC island and CPU. For this case, costs were also added to reflect locating the ASU at a stand-alone site one mile away. DESCRI TION OF OST CO BUSTION CA TURE CASE The SCR system is integrated into the existing boiler between the precipitators and the air heater. An economizer bypass was included to maintain SCR temperatures during partial load operation. After the air heater, the flue gas flows through the existing induced draft (ID) fans, which were modified to accommodate the increased system pressure drop. Downstream of the ID fans is a new baghouse that includes an activated carbon injection system for mercury control. Axial booster fans were added downstream of the baghouse to compensate for the added pressure drop. The FGD system is located downstream of the booster fans and discharges into the C0 2 capture system. A wastewater treatment facility is included to condition the scrubber effluent. The postcombustion C02 capture process utilizes an advanced solvent to recover the C02 from the flue gas. C02 is stripped from the solvent using low pressure steam, is dried, and then compressed. The steam cycle provides low pressure steam to the amine stripper reboilers, medium pressure steam to the amine reclaimers, and low pressure feedwater to the desorber condensers, bypassing the first low-pressure feedwater heater. Low pressure steam for the amine stripper reboilers is taken from the steam turbine crossover and sent through a let-down turbine to recover energy before reaching the C02 capture system. Since about 40 percent of the total steam flow is required for the amine stripper, the existing low pressure steam turbine is replaced by a new one that is designed to maintain the crossover pressure with the smaller remaining steam flow. DESCRI TION OF T E TROC CASES Unlike the base case of post-combustion capture, Transport Oxy-Combustion repowers the existing steam turbine by replacing the existing boiler and emission control systems (e.g. precipitator) thereby avoiding the need for retrofit of conventional emissions control technologies. Similar to the base case, the steam cycle along with other existing auxiliary systems continue operation with some modifications. The air separation unit (ASU) uses cryogenic distillation to deliver 96 percent pure oxygen at the required pressure for use in the TROC unit. The ASU includes liquid storage to maintain the supply of oxygen and nitrogen during upset and outage conditions. The TROC system combusts the bituminous coal currently processed at the existing plant under pressure in the presence of oxygen, producing a gas stream of mostly C02 and H20 from which heat is recovered into the steam cycle. A proprietary fluidized-bed solids cooler maintains the moderate combustion temperature by efficiently removing approximately two thirds of the heat of combustion into the steam cycle. The resulting large flow of recycled sol ids promotes complete combustion and allows a much lower excess oxygen level in the combustor, decreasing the oxygen in the products of combustion. Another advantage of the TROC technology is that combustion is at a pressure sufficient to allow useful heat to be recovered from the condensation of water as the products of combustion are cooled. 8 SoCo FOIA Response 002284 TOPICAL REPORT BUDGET PERIOD TWO NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY Emissions are largely controlled within the TROC system without the need for large postcombustion cleanup systems. Thermal NOx is limited by combusting with oxygen rather than air and at moderate temperatures. Fuel NOx formation is mitigated by the C02 which is recycled for fluidization. Limestone is introduced in the combustor to reduce SOx emissions, and trona is used to capture chlorine and fluorine. A fixed bed of activated carbon is used to capture any mercury. Case 2 includes the injection of coke breeze in the combustor to reduce the oxygen level in the product C02, while Cases 3 and 4 include downstream C02 purification by partial condensation and distillation, respectively, and Case I has no means for 02 reduction. The steam cycle provides small amounts of low pressure steam to the ASU and CPU and also to the coal preparation system for drying, but the main integration with the TROC system is through heat recovery and feedwater heater bypass. Low pressure feedwater is used in cooling the low-temperature products of combustion, partially bypassing all three low pressure feed water heaters. In addition, part of the high pressure feed water is sent from the deaerator to the hightemperature products of combustion cooler in which superheated steam is generated. RESULTS The data presented below are all for one nominal 250 MW PC unit. Table 6 compares the performance and major flows for the unmodified PC unit, a post-combustion carbon capture (PCC) retrofit, and TROC repowering. Table 6. Performance and Major Flows With and Without C02 Capture. CUnit cc Base Case TROC Case TROC case TROC Case TROC Cases 279.8 +2% 85.1 194.6 -24% 2,262 11,620 +23% 29.4 280.0 +2% 84.5 195.4 -23% 2,264 11,580 +22% 29.5 279.3 +2% 84.0 195.3 -23% 2,262 11,580 +22% 29.5 279.5 +2% 85.0 194.5 -24% 2.269 11,660 +23% 29.3 174.9 0 423.7 7.2 0.15 363.7 18.1 496.1 5.3 27.6 0 173.1 2.0 420.5 7.1 0.15 363.6 18.1 493. 9 5.2 27.5 0 174.9 0 423.7 7.2 0.15 359.6 18.1 439.0 62.4 27.6 0 175.5 0 425.2 7.2 0.15 364.8 18.1 428.6 75.1 27.6 0 Gross Power, ~ 274.0 Auxiliary Load, MW Net Power, MW 19.6 254.4 HHV Heat Input. MMBtu/hr HHV Heal Rate, Btu/kWh 2,406 9,460 HHV Net Efficiency, % 36.1 246.9 -10% 59.5 187.4 -26°k 2.409 12,860 +36% 26.5 Coal, k lblhr Coke Breeze. k lblhr O_xygen, k lblhr Limestone. k lblhr Trona. k lblhr Makeup Water, k lblhr Demineralized Water. k lblhr C02 Product. k lblhr Stack Gas/Off Gas, k lblhr Ash. k lblhr Gypsum•, k lblhr • 21% solids, by weight 186.1 0 0 0 0 0 18.2 0 2,784 18.5 0 186.3 0 0 5.9 0 763.8 18.1 458.6 2,264 22.1 49.7 - - - 9 SoCo FOIA Response 002285 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Both PCC and TROC negatively affect the net capacity and efficiency of the unit, with the TROC cases having about a third less impact. The performance and flows of the different TROC cases are almost identical. The PCC case requires significantly more makeup water to the cooling tower because of the cooling loads in the post-combustion C02 capture system. The other major difference is that the TROC cases have almost no stack gas or off gas compared with the PC unit and PCC case. COz Recovery and Product PuritY. The C02 capture percentage and C02 product purity for the technologies evaluated in this study are summarized in Table 7. Table 7. C02Recovery and Product Purity for Study Cases. Base Case cc TROC Case TROC Case TROC Case TROC Cases 90.0 99.99 <0.004 < 0.01 0.00 < 0.01 < 10 < 10 99.0 93.55 1.01 1.42 4.00 0.00 1 100 99.0 94.50 0.05 1.42 4.00 0.00 1 20 90.0 96.65 0.49 0.59 2.24 0.00 2 114 90.0 99.99 0.00 0.00 0.01 0.00 0 11 C02 Capture. % Vol %C02 in Product C02 Vol % 02 in Product COz Vol % of Nz in Product COz Vol % of Ar in Product C02 Vol % of HzO in Product COz ppmv of SOx in Product COz ppmv of NOx in Product C02 The PCC case and TROC Cases 4 and 5 give a high purity that meet published C02 purity specifications and should be suitable for any use, although at only 90 percent C0 2 capture. A range of lower purities (which may be suitable for sequestration) and higher C02 capture levels are available in TROC Cases I through 3. Cost ofElectricity. Table 8 shows the levelized costs of electricity (LCOE) for a nominal250 MW plant and summarize other major results for PCC and TROC. These cases use a capacity factor of 75 percent. Table B. Levelized Cost of Electricity for All Study Cases. Plant Output, MW Heat Rate, Btu/kWhr, HHV Total Plant Cost, MMS Total Plant Cost, $/kW Fixed O&M, SlkW-yr Variable O&M, mills/kWh Capital, mills/kWh O&M, mills/kWh Fuel, mills/kWh LCOE, mills/kWh (2010$) Base Case cc TROC case TROC Case TROC Case TROC Case TROC Case 187.4 12,860 790 4,220 117.8 8.63 91.2 26.6 21 .1 138.8 194.6 11,620 727 3,730 88.6 3.06 80.7 16.5 19.1 116.3 195.4 11,580 729 3.730 88.6 3.64 80.6 17.1 19.0 116.7 195.3 11,580 753 3,860 90.4 3.05 83.4 16.8 19.0 119.2 194.5 11,660 775 3,980 92.4 3.07 86.1 17.1 19.1 122.3 194.5 11.660 798 4,100 92.4 3.07 88.7 17.1 19.1 124.9 10 SoCo FOIA Response 002286 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO The TROC cases have a total plant cost of 3 to 12 percent less than the PCC case on a $/k W basis, but this is not considered significant based on the estimating accuracy of this study. The TROC compact site sensitivity (Case 5) adds approximately 3 percent to the capital cost, so the costs ofrepowering a more compact site are not prohibitive. The TROC cases have a significant advantage in O&M costs (36 to 38 percent lower), primarily due to the amine solvent makeup costs in the PCC case, and a slightly lower fuel cost, which is a direct result of the heat rate difference between PCC and TROC. These differences combine to give TROC a I 0 to 16 percent lower levelized cost of electricity, assuming the same dispatch rate and capacity factor. Figure 2 plots the LCOE. 200 -.-----~ • Fuel • O&M • Capital 88.7 PCC TROC"' TROC"' TROC"' TRQCTM TROC 111 Case 1 Case 2 Case 3 Case 4 Case 5 Figure 2. Leve!ized Cost of Electricity at 75 Percent Capacity Factor for All Study Cases. Costof£/ectricitySensitivitytoCaoacityFactor. Although the total plant costs are similar for PCC and the TROC cases, the costs to dispatch the plant and produce a unit of power (the sum of the fuel cost plus the variable O&M cost) are significantly different as listed: • • • PCC Base Case - 29.7 mills/kWh Case 1 - 22.1 mills/kWh Case 2 - 22.6 mills/kWh • • • Case 3 - 22.0 mills/kWh Case 4 - 22.2 mills/kWh Case 5 - 22.2 mills/kWh This suggests that in operation, the TROC plants would be operated at a higher capacity factor, which would lead to a lower levelized cost of electricity. Figure 3 demonstrates the LCOE sensitivity to capacity factor. 11 SoCo FOIA Response 002287 TOPICAl REPORT BUDGET PERIOD TWO NATIONAl CARBON CAPTURE CENTER POWER SYSTEMS DEVElOPMENT FACiliTY ~ 150 ~ ~ 'E f cs w s 100 - Pee ·• ·Case 1 + Case2 + Case3 - Case4 - cases 50 (.J 0 50% 70% 60% 80% 00% Capacity Factor Figure 3. LCOE Sensitivity to Capacity Factor. If a PCC plant were dispatched to have a capacity factor of 55 or 65 percent, the levelized cost of electricity from Figure 3 would be about 156 to 179 mills/kWh . In contrast, if a TROC plant were dispatched at a capacity factor of 85 perce nt, its LCOE would be I05 to 113 mills/kWh, or about 30 to 40 percent less than for PCC. Therefore, the difference in variable O&M costs and fuel costs would produce significant differences in the actual LCOE. COSTS OF CO CA TURE AND AVOIDANCE Table 9 provides the costs of C02 capture and of C02 emissions avoided for all cases. Table 9. Costs of C02 Capture and Emissions Avoided for All Study Cases. Cost of C02Capture, $/ton Cost of C02Capture, $/tonne Cost of C02Emissions Avoided, $/ton Cost of C0 2Emissions Avoided, $/tonne cc TROC Case TROC Case TROC Case TROC Case TROC Case 64 46 51 55 61 47 52 56 61 54 59 65 56 62 69 76 59 65 72 79 71 88 97 72 The advantage of capturing 99 percent of the C02 at lower purity rather than 90 percent at higher purity becomes evident in the results for Cases I and 2, since they have significantly lower costs of C0 2 capture and C0 2 avoidance than the other cases. The higher LCOE of the PCC case is reflected above, with C01 capture and avoidance costs 8 to 60 percent higher than for TROC. CONClUSIONS This study investigated two options for mitigating emissions at a representative existing midsized coal plant. For the system arrangements considered, using bituminous coal, the results showed the following: 12 SoCo FOIA Response 002288 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY • • • • • • • • TOPICAL REPORT BUDGET PERIOD TWO Both PCC and TROC require a significant capital investment and negatively affect plant perfonnance. Both PCC and TROC are capable of recovering a minimum of 90 percent of the C02 produced by the plant, and some TROC configurations can capture 99 percent if the C02 product purity is decreased. Both PCC and TROC (in one configuration) are capable of meeting typical industry C02 product specifications, including some for enhanced oil recovery. If high product purity is not required, the TROC capital cost can be reduced by choosing a configuration with less C02 purification, while still achieving a purity sufficient for sequestration. Although the results show 3 to 12 percent lower capital costs for TROC compared with PCC (on a $/kW basis), the difference is within the accuracy of the estimate. Although a space-constrained site adds to the capital cost ofTROC, Case 5 suggests that the increment is not excessive. TROC has lower heat rates and O&M costs compared with PCC resulting in a I 0 to 16 percent lower LCOE, at 75 percent capacity factor, and this advantage widens if dispatch differences are considered. It is expected that PCC and TROC dispatch rates would be significantly different since the TROC dispatch costs (fuel plus variable O&M) are 24 to 26 percent lower than for PCC. 13 SoCo FOIA Response 002289 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO RE CO BUSTION CO CA TURE AND SE ARATION To advance pre-combustion C02 capture technologies, the NCCC has the capacity to investigate key processes including gas/ liquid contacting systems. solvents for C02 capture/separation, water-gas shift processes, and emerging syngas processes. The infrastructure for pre-combustion C02 capture testing provides for a wide range of test conditions. and includes the Syngas Conditioning Unit (SCU). During BP2, the SC U was modified, and various C02 capture and water-gas shift tests commenced, as did support of gas separation membrane testing by outside researchers. SYNGAS CONDITIONING UNIT The SCU is a flexible slipstream facility that can accommodate multiple, small-scale tests, such as water-gas shift. hydrolysis, desulfurization, and C0 2 capture. The SCU, shown in Figure 4, consists of small reactor vessels, arranged to allow operation in series or in parallel, which accommodate a range of flow rates, temperatures, and pressures. The unit is also used to support outside technology developers by providing a syngas test location, and it has supported development of technologies such as gas separation membranes, fuel cells, and heavy metal removal processes. v ~ J' ST(A ~ --~~~--~----~~ rv 7YNC'.:o: E:ST: ' \ FIJ£LCELLS E BAAH£S ETC ! ! 1001 (RIESIIIGOR ~~~~~0 ~:lOR SYNGAS CONDff/ONJNG UNIT \ .._ l&.aJ rv r o v. .. v ~~va:.._ ........ ..... I I ~ I I l I ' Rgure 4. Flow Diagram of the Syngas Conditioning Unit. SCU Modifications. Upgrading the SCU continued during BP2 to accommodate the everexpanding range of technology development. A new gas analyzer building for the SCU was installed during BP2 to house existing and future analysis equipment. The existing analyzers include six gas chromatographs (GCs), four continuous syngas analyzers, one Fourier Transform Infrared (FTIR) analyzer, four area gas detectors, and two calibration panels. 14 SoCo FOIA Response 002290 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Views of the outside and inside of the building are presented in Figure 5. The syngas sample lines are routed from the SCU test equipment along with lines for calibration gases, GC nitrogen carrier gas, and instrument air. The system has over 40 sample and calibration connections and the analyzer outputs are connected to the Plant Information data acquisition system. Figure 5. Gas Analyzer Building for the Syngas Conditioning Unit, Other modifications made to the SCU, which comprised Phase I and Phase II infrastructure improvements, included: • • • • • • • • New instrumentation (including a flow meter, control valve, and local instrumentation) and changes to associated piping and heat tracing to support higher syngas flow rates for mercury sorbent testing Accommodations for a mass spectrometer supplied by NETL to validate the design of the analyzer system used to monitor the perfonnance of the Johnson Matthey mercury sorbent Modifications to existing thermocouples and addition of new thermocouples to improve measurements of temperature profiles in the water-gas shift (WGS) fixed-bed reactor and at the reactor outlet Addition of probes to measure moisture content at the inlet of the WGS reactors Installation of heat tracing to eliminate steam condensation in the steam supply sub-header to the was reactors Addition of a new model syngas chromatograph Modifications to the temperature control on the syngas piping to the Membrane Technology & Research (MTR) membrane skid to maintain a stable syngas feed temperature Addition of intrinsically safe nitrogen purges to the Media & Process Technology (MPT) membrane skid electronic and variac enclosures ATER GAS S 1FT CATALYST TESTING Evaluation studies completed at the NCCC show that catalyst vendors generally recommend high steam-to-CO ratios to maximize CO conversion and minimize methane formation. Values as high as 2.6 have been quoted. This is based on requirements by chemical production processes to maximize hydrogen fonnation (the desired product) and minimize methane formation, a 15 SoCo FOIA Response 002291 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO potential contaminant. High steam content also suppresses carbon formation from the cracking of long-chain hydrocarbons. For power plant applications, where the objective may be to capture only 90 percent ofthe C02, incomplete conversion of CO and the production of some methane are acceptable. Moreover, there are little, if any, long-chain hydrocarbons in coal-derived syngas so there is no need for excess steam to suppress carbon formation. The evaluation studies also indicated that for a 500-MW IGCC plant, a steam-to-CO ratio ofO.I corresponded to 4 MW of power, so operating with excess steam would have a significant impact upon net power production. For example, if a steam-to-CO ratio of 1.6 was acceptable rather than 2.6, then an additional 40 MW would be available. To determine the feasibility of operating with steam-to-CO ratios lower than those normally proposed, the NCCC began investigating the performance of WGS catalysts provided by the major suppliers. The terms of the confidentiality agreements signed prevent identification of the catalysts in this report. Test Procedure. The inlet and outlet gas compositions were determined using the gas chromatography and non-dispersive infrared (NDlR) instruments. The inlet flow rates of syngas and steam were measured using a V-cone meter and orifice plate, respectively. The accuracy of these meters was checked using known flows of nitrogen prior to the start of the run and during the run. The outlet flow rate was not measured but was calculated using nitrogen present in the syngas as a marker. Using the instrumentation available, the composition of the syngas entering and leaving the WGS reactor were calculated on both dry and wet bases. For testing during gasification test run ROS, an amount of 13 pounds of catalyst was installed in the vessel, giving a fixed bed 26-inches deep supported on a 310 stainless steel mesh. The syngas and steam flowed vertically downward through the catalyst. The gas flow rates were held constant during the run to maximize the data collected for a given space velocity. The heat tracing on the line from the header to the vessel was adjusted to achieve an inlet temperature of 540°F to keep the exit temperature below 650°F, above which sintering could occur. The parameter that varied the most was the steam-to-CO ratio. Table I 0 lists the test conditions for ROS. Table 10. Water-Gas Shift Catalyst Test Conditions. Test ara eter Syngas Row Rate, lblhr Steam Flow Rate, lb/hr Operating Pressure._l)sia Inlet Temperature, "F Superficial Svnoas Velocitv. Ills Soace Velocity, hr' H20/CO Molar Ratio Test Duration, hours No ina Va es 50 2.0 195 540 0.22 3,240 0.8 to 1.6 780 16 SoCo FOIA Response 002292 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO To monitor how the temperature varies in the catalyst bed as the WGS reaction proceeds, thennocouples were installed along the reactor length. Figure 6 plots the temperatures for select operating periods at the six locations. The maximum temperature occurred at the 3-inch level. The temperature drop for the lower two thennocouples was attributed to heat losses from the flange, which is only insulated and not heat traced as is the reactor wall section. The mean temperature increase in the reactor was 90°F from 530 to 620°F; without the heat loss, the temperature increase would have been closer to 95°F. 650 ~ ~- 600 I ~ • 550 i 500 ·5 h 1rl i1 0 5 -1 Tl- 1' 1 11 10 15 20 25 30 Height Relative to Catalyst Bed Bottom, inches Figure 6. Temperature Profile in the Fixed Bed Reactor during R05. The mean values for the major syngas components during R05 are given in Table II along with the analyzer used to make the determination. Each analyzer has its own error bias which data analysis accentuates when comparing the changes in composition between the inlet and outlet of the reactor. Table 11. Mean Syngas Compositions at Water-Gas Shift Reactor Inlet and Outlet. Inlet Concentration, val % (analyzer used) Outlet Concentration, vol% (analyzer used) co co 9.7 (NDIR) 3.6 (GC) 9.7 (NDIR) 14.3 (GC) c 7.1 (GC) 12.7 (GC) 1.02 (GC) 1.04 (GC) Figure 7 compares the amounts of CO shifted (delta CO) to the amount of C02 fonned (delta C02) by the WGS reaction. These amounts should be equimolar, one mole of CO being converted to one mole of C02 formed, according to the water-gas shift equation: CO+ H20- C02 + H2 (water-gas shift equation) All but one data point fell within I0 percent of perfect agreement, which validated the data quality. 17 SoCo FOIA Response 002293 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO 0.120 , ,, ,, , 0.100 -e cS u ~ 0.080 • R05Test oara -PerfectAgreement - - -+1· t0 Pe~tent 0.060 0.060 0.080 0.120 0.100 Delta co. mol Figure 7. Amount of C02 Produced Compared to Amount of CO Shifted. Figure 8 plots the amounts of CO shifted to H2 by the WGS reaction. Again, according to watergas shift equation, these amounts should be equimolar. The data for hydrogen did not agree as well as that for the carbon dioxide, with the data showing more hydrogen formed than CO consumed. The discrepancy likely arose from small measurement errors. Efforts continue to reduce error as much as possible. , 0.140 / /~v '7 . ... , , ~• , , , •o o_R..eeo 0.120 • -e 0.100 ------0080 , , ' ~0 ,, £ ~ , If'·· , ~ __ ... ----·· 0060 0.060 0.080 0.100 , .. , ,, o ROS Test Data -PerlectAgreement - - -+1· 25 Pe~tent 0.120 0.140 Delta co' mol Figure 8. Amount of H2 Produced Compared to Amount of CO Shifted. Figure 9 compares the amount of methane entering and leaving the WGS reactor. The data showed some scatter but did not indicate that methane formation occurred. Further, carbon deposits were not detected on either the surface of the catalyst or the inside surface of the reactor. 18 SoCo FOIA Response 002294 TOPICAL REPORT BUDGET PERIOD TWO NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY -- - 0025 • ' 0020 E :t ,, u ~ ,, ,' ,' ,, ' ,' ' '' ' '' --· ( _. _._,-- ,' _ ' ' 0015 -, ........; ~ ,' ' , • R05 Tesl Data ,, 0 010 0010 ,' -Pt~oc:tAgeemanl ,' -- 4 15 Percent 0015 0025 0020 lnlel CH. 1bmol Figure 9. Comparison of Methane Content Entering and Exiting the WGS Reactor. Figure I0 presents data showing the measured CO conversion variation with steam-to-CO ratio. Also presented is the equilibrium conversion calculated from information provided by the catalyst vendor. On average, the measured conversions were 70 percent of the equilibrium values. The trend for both data sets appeared to be asymptotic, with conversions leveling off for molar ratios greater than 1.6. "" 00 I 8 . ,. ,..:--... ... . .. •-'--• ! .-.......... . .. ~-- - 60 ......... --········: :··· ···· • o Equilibrium Conversion • Aclual Conversion 0.8 1.0 1.2 16 1.8 Sleam-to-CO Mliilf Ratio Figure 10. Comparison of Actual and Equilibrium WGS Conversions. The tests showed that sufficiently high CO conversions were achieved at lower than recommended steam-to-CO ratios and that only marginal increases in conversion would be realized for ratios above 1.6. No methane was formed and no carbon was deposited in the reactor. For power generation applications, steam-to-CO ratios lower than those recommended for chemical production applications are acceptable. 19 SoCo FOIA Response 002295 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO CO CA TURE TESTING During the reporting period, NCCC researchers investigated several C02 capture sorbents, including ammonia; polydimethylsiloxane, which was compared to the well~documented solvent dimethyl ether of polyethylene glycol (DEPG); and potassium carbonate and potassium prolinate, which were compared to ammonia. A ONIA C E ISTRY Ammonia Compounds for C01 Capture. Ammonia can capture C02 by two main mechanisms, one involving ammonium carbonate, and the other ammonium carbamate. The carbonate route involves the following reactions: NHJ + H20 + C02 +-+ (NH4)2C03 (·24.1 kca!/g-mol; -986 Btu/lb C02) Equation 1 (NH4)2C03 + H~ + C02 +-+ 2NH4HC03 (·6.36 kcaVg-mol; -260 Btu/lb C02) Equation 2 The carbamate route involves the following reactions: 2NHJ + C02 +-+ (NH3)2C02 (-17.7 kcaVg-mol; -725 Btu/lb C02) Equation 3 (NH3)2C02 + 2H20 + C02 +-+ 2NH4HCOJ (-12.75 kcaVg-mol; -521 Btu/lb C02) Equation 4 If the ammonium bicarbonate (ABC) crystallizes, heat is released, the heat of crystallization being -6.78 kcal/g mol (-277 Btu/lb C02). Similarly, heat is required to dissolve the crystals. If the liquor to be regenerated contains crystals, then heat must be applied to dissolve the crystals. If the ABC releases its C02 to form carbonate, the heat of reaction (-260 Btu/Jb C02) is lower than if carbamate is formed (-521 Btu/lb C02). Hence, it is important to know the exact chemical route followed. In addition, the formation of crystals may be beneficial in reducing the heat of regeneration. The crystals can be separated from the liquor, lowering the water content of the ABC-rich liquor sent to the regenerator, thereby lowering the sensible heat requirement. However, this will be offset to some degree by the heat required to dissolve the crystals. A comprehensive model to predict ammonia chemistry is required to resolve these issues. The thermodynamic software identified was supplied by OLI Systems and is used widely to predict the properties for a range of aqueous solutions. When used to predict the capture of C02 using ammonia, the calculations are based on carbamate being the primary product of the reaction. To confirm that this is correct and validate the model, tests were completed in the SCU batch reactor to produce ammonia liquors with a range of compositions. These solutions were analyzed using nuclear magnetic resonance (NMR) spectroscopy. The NMR technique beams an electromagnetic pulse at the solution and the energy radiated back is influenced by the properties of the molecule's nucleus. A spectral output signal is presented in Figure II, the frequency shift being a characteristic of the nucleus and the height of the peak 20 SoCo FOIA Response 002296 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO being an indication of the amount present. The instrument can be programmed such that the peak value represents the percentage of the species present in solution. 56% (NH1),C01 44%(NH,)1CO/ NH,HC01 165 166 164 163 Frequency Shift Figure 11. Output Signal ffom NMR Analyzer. The left-hand peak results only from ammonium carbamate and allows direct determination of this species. The right-hand peak results from a combination of ammonium carbonate and bicarbonate requiring a means of deducing the proportions of the two species present. Research from the University of Florence showed that the greater the horizontal separation of the two peaks the greater the bicarbonate content of the left-hand peak. This group then developed a calibration curve using solutions with known carbonate and bicarbonate contents. This calibration curve was used to extract the carbonate and bicarbonate information from the on~site analyses. Fifteen tests were completed to compare the concentration of ammonium compounds measured by NMR with values predicted by OLI. Figure 12 provides plots of the ammonium carbamate, ammonium bicarbonate, and the ammonium carbonate concentrations measured by NMR versus those predicted by the OLI program. 14 ~ I i I!! 12 B !i z 6 A .Aa2ped • Rejeded 10 ~ ~ j ~ 40 0 I J< 0 I ! 30 / lro9B8x, R•0 9947 j ~ 20 fi'" 2 .D 0 A- 10 1 I ~ !i z ~ A.Aa2pbld • Reiec:Ed 1 i 0 /x' 4 6 ~ ~ 2 4 6 B OU Prediction,wt% AnvroniumCalbama1e 10 0 5 t. Aa2ped ~ 4 • Rejected t{ / I!! I ir= o.9G~l R'=09906 0 0 ~ J 2 1 30 10 20 OU Predidion,wl% Ammonium Bicarbonate !i z / .K L I ~r-% ./ At' ry= 1 73~~ R'=0.9911 0 40 0 1 2 3 OU Prediclion,w1% 4 Amrronium Carllona1e Ffgure 12. Comparison of Measured and Predicted Concentrations of Ammonia Compounds. 21 SoCo FOIA Response 002297 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO As noted in the figure, three data points were rejected from the data set. For ammonium carbamate and ammonium bicarbonate, the slope of almost one indicated good agreement. For ammonium carbonate, the measured values were appreciably higher than the predictions as indicted by the slope being greater than one. The error may have resulted from error in the calibration curve. The ABC results presented in the figure could be slightly over-predicted, giving a slope of less than one. Adjusting the measured ABC to match the predicted value will increase the amount represented in the right hand peak of the NMR measurement and so the amount of ammonium carbonate measured is reduced. This approach improved the match achieved in the ammonium carbonate plot and lowered the slope to 1.24, but still suggested that the model under-predicts the ammonium carbonate present. It was concluded that the measured ammonium carbamate and ABC were predicted with good accuracy by the OLI model and any error associated with ammonium carbonate was low. This validated the model and allowed its use with confidence for predicting the composition of the ammonia liquor. The model was also used to predict other performance parameters of interest. Figure I3 presents C02 capture data and shows that the model agreed well with the measured values. The perturbation in experimental C01 capture efficiency seen around 68 minutes into the test may have been related to the onset of ABC crystal formation after around 64 minutes. 100 90 i! 80 1:f 70 i ·o te w I!! .a l3 0 u ~ !!!.. 20 10 0 ~\ 0 \ • Experimental R 24 20 16 / I\ - OLIModei ABCPPT ./ \ 40 60 " 80 100 :!9 :~ 12 u 8 a> < ~ /_ I' 20 j Q. \ ' ~ ' v .. J... 1- • Experimental EffiCiency ':- -+-OLIModel Efficiency 60 50 40 30 40 36 32 28 ~ 4 0 ~ r% 120 Time, min Figure 13. Comparison of Measured and Predicted C02 Capture Efficiencies. The ''R" value included in Figure 13 represents the ammonia-to-C02 molar ratio and fell as the C02 content of the liquor increased. When the COz capture efficiency began to decrease after around 50 minutes, R was slightly greater than 2, indicating that the free ammonia was almost depleted. Up to this point, C02 capture occurred primarily by the reaction in Equation 3, and carbamate was the primary ammonia compound formed. After this, Equation 4 was the primary C02 capture reaction, and the carbamate was converted to bicarbonate. Eventually the saturation concentration was reached, resulting in the formation of ABC crystals after 64 minutes. 22 SoCo FOIA Response 002298 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Figure 14 presents the concentration of ammonia exiting with the gases leaving the reactor and also shows that the model agreed well with the measured values. Ammonia was released at around 1,000 ppmv at the onset of ABC crystallization even though there was no free ammonia. This was a result of the presence of ammonia anions. 7,000 Q&-;;=======;-..,.--~r- 1----1--- -+1 30 6.000 H--:-:::;;;~RRI'~ : : : :: I 35 'i t i u .!l! 3,000 < 2,000 15 r - --'M-- --tl''---+---r----t 10 ·~ 0.. ~ 1,000 < l__,..._U~~!!I:It2rz==moboooo 20 80 40 60 Time,min 0 100 Figure 14. Comparison of Measured and Predicted Ammonia Slip. The experimental work to date has validated the use of OLI software for predicting ammonia chemistry. Subsequent work began to identify the optimum absorber and regenerator operating conditions. Initial Modeling Results. Initial testing using properties predicted by the validated OLI model was undertaken to detennine how the composition of the liquor leaving the absorber changed as it was heated in the regenerator. The change is presented in Figure 15. This graph shows absolute values for the ammonium bicarbonate crystals and the C02 released, and the difference in values for the dissolved species, ammonium bicarbonate, carbamate, and carbonate. .. 300 o~ ABC crystal dissolution 1 (actual values) " 0 " ~~ ~X It> . . .... : "" " " ~~ ... X "x X "" " 4'> I '-'o XX XX X C02<0ioaso 40 X '1J >I< XC.rl>ooattdocoft1>0slion 20 ,. 0 OABCd_..;tion AC.rllomatolannalion ·300 X •"' .. I 60 80 100 Reactor Temperature, nn .. '" ron ..u n 'V E "' '"" 15:2.... g 2,A ~c: 1.,., ;:J -+- Cycle1 ~-- - / vr Ill g 1w Cycle 2 r I' -+- Cycle 1 Cycle2 (.) "n :s2 oJU --- Cycle3 n tf w en ., £ -5 0 5 10 15 20 25 30 35 40 45 50 - - - Cycle3 - l . -5 0 5 10 15 20 25 30 35 40 45 50 Time, min Time,min PDMS DEPG Figure 21 . H2S concentration Profile during Absorption Following Thermal Regeneration. Figure 22 presents the maximum l-hS absorption efficiency as function of the flash pressure used to regenerate the solvent prior to absorption. As flash pressure increased, less H2S was released, and as a consequence of the reduced free capacity, H2S absorption efficiency fell. The trend of the data is simi Jar to that of C02 presented in Figure 19, but the efficacy of H2S flash regeneration was lower as indicated by the lower capture efficiency values achieved with H2S. 100% 90% c: 11> 80% ·o ~ 70% a- -+-DEPG I I~ PDMS u"' en ' £ E :::> E '13 ::;; ~ n I!! 60% .a c.. -.'o.. 50% 40% 30% 20% 10% 0% '~ " 0 20 40 ---60 80 ----a 100 Flash Pressure.psia Figure 22. Effectiveness of H2S Regeneration at Vartous Flash Pressures. As DEPG has a high affinity for water, some of the regeneration energy required to release H2S and C02 is used to evaporate water and stabilize the solvent moisture content. Since PDMS is immiscible with water, the water can be separated mechanically, eliminating evaporation duty and lowering the heat of regeneration. Ten weight-percent water was added to the solvents to determine the effect of water on C02 absorption and regeneration performance. The volume of solvent/water mixture added to the reactor was 4.6 liters to maintain the depth at I0 inches. Figure 23 presents the moles of C02 absorbed in the mixtures. The amount absorbed by the DEPG-water mixture was lower than for DEPG only. The reduction was in the range 15 to 29 SoCo FOIA Response 002305 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO 25 percent, more than the straight I 0 percent through dilution with water. In contrast, the amount of C02 absorbed by the PDMS-water mixture is 5 to 15 percent higher than for PDMS only. With or without water addition, DEPG absorbs more C02 than PDMS. 30 28 26 ~ 24 ~ DEPG ·No H 20 "' '"'" "" '"' ~ -o- DEPG/10% H20 1- ~ PD MS-no H20 ~ PDMSI10% H20 t- ~ ...,; ~ 2.2 ~ 2,0 8 1.8 0.. 16 _... _.o ..........:. 1.4 1.2 ' 2 0 Cycle 6 4 Figure 23. Effect of Water Addition to DEPG and PDMS on C01Absorption. OTASSIU CARBONATE AND OTASSIU ROLINATE To widen the range of chemical solvents under investigation, potassium carbonate and potassium prolinate were tested in the batch reactor. Potassium carbonate is an established solvent and is used in the Benfield process for acid gas purification, and amino acids such as proline, are being investigated for post-combustion C02 capture. Properties of the solvents used are listed in Table 14. Table 14. Properties of Potassium Carbonate and PotassitJm Prolinate Solvents. oe ar eiq t b b Potassium Carbonate Potassium Prolinate 0 138 153 Con entration t 0 1.7 5.1 20 56 Absor tion Te erat re F 212 102 Potassium carbonate captures C0 2 forming a bicarbonate: Heat of reaction Heat of crystallization Total -6.07 kcal/g mol -9.64 kcal/g mol -15.71 kcal/g mol (249 Btu/ lb C02) (-395 Btu/lb C02) (-644 Btu/lb C02) The comparable values for ammonium carbamate/bicarbonate are (-521 , -277, and -798 Btu/lb C02) so the potassium carbonate has lower heats of reaction. This advantage is offset by a lower rate of reaction requiring absorption at a higher temperature (212°F compared to 98° F) for ammonium hydroxide. Additionally, as KHCOJ has a higher molecular weight, the C02 loading 30 SoCo FOIA Response 002306 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO is lower than that of ABC. To keep the K2C03 in solution, the concentration is limited to 20 weight-percent. Together, these characteristics mean that the solvent flow rate is higher, increasing the heat of regeneration. Amino acids have several advantageous properties such as low volatility and corrosivity, which offer advantages over amines. Research at the University ofTwente in the Netherlands investigating amino acids for post combustion C02 capture concluded that L-proline had the highest reaction rate of the amino acid salts in one-molar aqueous solutions. Tests were carried out at the NCCC using five-molar solutions to increase the C02 loading. Initial tests were carried out with the sodium salt formed by mixing the proline with sodium hydroxide. C02 was bubbled through the solution and very fine crystals were formed, eventually producing a thick mixture. Similar tests were completed with the potassium salt (using potassium hydroxide), but the final mixture was less viscous presumably because the potassium salt was more soluble. Figure 24 compares the C02 capture efficiency for the three solvents presented on a molar basis as well as on a mass basis. The performance of the ammonia and potassium carbonate were similar, with the capture efficiency of potassium prolinate falling precipitously after exceeding a molar ratio of0.5. The C02 mass loading for ammonia was shown to be greatly in excess of the other two solvents, with the potassium carbonate having the lowest loading. 100 ~ 80 I OAmoronia o Fotassilm Profnate () I~Potassilm "'5 c; u!:::.. v ~ u ~··~ ·~ <> <> #- 90 ~ UJ 100 ~~ .... . Carbonate #- ~ 60 0.2 04 06 !:::.. 80 !:::.. a (.) 60 0.8 Molar Loading, mot CCI mot solvent MolarBasis ~ UJ 8 70 c; ~ (.) b. ~ ~ !:::.. <>- 70 90 1 0 ro ~ <> ~. Potassium Prolilate 1 o°~~ ~ l>. Potassilm Carbon~te l 100 t50 200 250 Mass loading g COikg of sokloon JOO M:lssllisis Figure 24. C02 Capture Efficiencies for Potassium Prolinate and Potassium Carbonate. Figure 25 graphs the pressure rise in the reactor during heating for each of the three solvents. No C02 was vented from the reactor, so all the C02 released resulted in pressure increases. The factor "L" represents the molar loading of C02, that is, moles of C02 per mole of solvent. The higher pressure indicates that the ammonia solution released C02 more readily and was regenerated more fully than the two other solutions. 31 SoCo FOIA Response 002307 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY 600 TOPICAL REPORT BUDGET PERIOD TWO ~Potassium Prolinale, L • 0.45 o Ammonia, L • 0.68 1> Potassium Carb:lnale, La 0.94 A A A 0 0~ 0 A ~ (),~ "'o"i> AAo I>Ao 0 ~I> 0 oA 0 "' 50 0 A 0 100 0 0 150 200 250 Regeneralion Temperalure, 'C Figure 25. Pressure Increase during Regeneration of Three C02 Capture Solvents. GAS SE ARATION E BRANES During BP2, the NCCC continued its support of gas membrane testing, which has been ongoing for several years. A portion of the SCU was made available to MTR and to MPT for testing of membrane technologies. E BRANE TEC NOLOGY RESEARC YDROGEN AND CO E BRANES MTR is a private company in Menlo Park, California, which designs, manufactures, and sells polymeric gas-separation membranes for petrochemical and natural gas applications. Since 2007, the company has been carrying out R&D in C02 separation from coal-derived nue gas and syngas. Figure 26 provides a cross-sectional view of MTR's thin-film composite membrane structure. The micro-porous support membrane provides the mechanical strength required and is coated with a 0.5- to !.O-micron thick gutter layer that provides a smooth surface on which to coat the selective membrane layer, which is about 0.05 to 0.1 micron thick. A surface coating on the selective layer protects it from mechanical damage. The gutter layer and surface coating are sufficiently permeable to allow the permeating gases to pass through readily. I II Protective Coating Layer Selectivelayer(1.000A lllick) Gutter layer Support Membrane One micron Figure 26. Schematic of MTR's Thin-Film Composite Membrane. 32 SoCo FOIA Response 002308 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO MTR uses a spiral-wound configuration for membrane production, which is shown in Figure 27. A sheet of thin-film composite membrane is cut to the required length and folded in half to create an envelope. Spacer material (the permeate spacer) is placed between the two surfaces to create a flow channel for the permeate stream, and the two parallel edges of the envelope are glued together. The remaining open edge is secured to a perforated collection tube and spacer material (the feed spacer) is placed over the membrane surface. Additional membrane envelope sections with feeder spacers are secured to the collection tube in a similar manner until the specified membrane area is reached. The membrane envelopes and feed spacers are then wrapped around the tube, and the module is inserted into a steel pipe. Figure 27. Schematic of MTR's Spiral-Wound Membrane Assembly. The feed gas is fed to one end of the pipe and enters the feed spacer channels of the membrane module. The permeable gases pass through the membrane layer and flow along the permeate spacer channel toward the central collection pipe and exit the membrane module at low pressure. The residual gases that do not permeate through the membrane continue to flow along the feed spacer channel and exit the membrane module and the pipe section at high pressure. In November 2009, MTR began testing two polymeric membranes at the NCCC to process coalderived syngas, one a COrselective PolarisTM membrane and the other a H2-selective ProteusTM membrane. The prototype C02 membrane assembly is approximately 3-feet long with a 4-inch outer diameter (OD) and is installed in a skid-mounted tube able to accept two modules. The H2 membrane is flat sheet installed in a 6-inch diameter, high-pressure permeation cell set in a small pressure vessel. Figure 28 provides photographs of the membrane mounting equipment. 33 SoCo FOIA Response 002309 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO C02 Membrane Skid Figure 28. MTR Membrane Test Equipment. High-temperature syngas from the SCU is cooled by bubbling through a water bath that also removes the small amount of hydrocarbons present. The permeate and residual streams leaving the membranes are analyzed, then re-combined and returned to the exit syngas header. Table 15 summarizes the conditions for membrane testing during gasification test runs R03, R04, and ROS. In R03 and R04, the C02 membrane operating temperature varied with ambient conditions, and for R05, the membrane tube was heat traced and insulated to maintain steady operating temperatures. Table 15. MTR Membrane Test Conditions. Test ara eter Synaas Conditions Coal Membrane Temoerature, "F CC02IH2I Membrane Surface Area, m2 IC021H2I Membrane Pressure, osia Hours of Ooeration Syngas Flow Rate, lb/h (COvH2I Mean Inlet Syngas Composition (Dry Basis) Hydrogen, vol% C02, vol% CO, vol% H2S, oomv Test R n R Unshifted, sweet PRB Test R n R Shifted, sour L_ignite Test R n R Shifted. sour PRB 49/250 0.8/30 150 500 10/1 68/250 3.2/30 190 500 50/1 82/250 3.2/30 190 800 50/1 9.3 11.7 5.7 12.5 14.1 2.2 780 13.6 14.8 2.8 360 Less than 10 Figure 29 plots the results of C02 membrane operation during R03, showing the variation with time for the permeance of gases in the syngas and the selectivity of C02 relative to these gases. The term "gpu" used in the mixed gas permeance plot in Figure 29 represents the gas permeation unit, which is the volumetric flow rate per unit cross sectional area for a given pressure differential in units of(I0'6 standard cm3 ) I (cm2 *s*cmHg). 34 SoCo FOIA Response 002310 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO 100 ~co, ... "S !!! 100 • •~~ ...•.. ..•• ~·· l ••'i" ~'·.~. ~ "5 li = 'i" co 10 ~"· :i :i 1 5 10 15 Openllng tlme(dayst 0 ~~:~::: 10 iX 20 1 25 0 5 10 15 20 25 Operating tlme(dayst Figure 29. MTR C02 Membrane Performance during R03. The C02 concentration in the permeate was 4 to 5 times that of the feed steam, and the H2S concentration was about 6 times higher in the permeate than in the feed stream. During the testing, the membrane operated stably with the variations shown in Figure 29 occurring primarily from changes in ambient temperature, with a lesser effect ofsyngas composition and flow rate. Figure 30 presents test results for the hydrogen membrane at two operating temperatures during R04. For a temperature increase from 120°C to 135°C, the hydrogen permeance increased from 190 to 270 gpu, and the H2/C02 selectivity decreased from 24 to 17. Nevertheless, the membrane performance exceeded target values for these two parameters at both temperatures. Results from all three test series indicated that hydrogen in the feed stream was enriched 6 to 8 times in the permeate stream. The presence of H2S in the syngas feed did not compromise membrane performance. 00 1.- •I b) us•c IWC c ..... .. ?1'\... I'J - n :15 c ,, .. "· ... 00 en -... "' "'"' "' 25 (.) 15 ·~ c: us·c nrc 11 • •••• • ••• • ••• co, 30 0 •• • • • 1WC • 20 •• • • • • 1:150C 10 a I • • 0 eralingli 10 0 IS e as Zl u 0 a 10 15 20 25 0 eratingli e a s Figure 30. MTR H2 Membrane Performance during R04. For hydrogen membranes designed to separate 90 percent of the hydrogen from coal-derived syngas, the DOE has set a target of limiting the cost of electricity increase by more than 35 SoCo FOIA Response 002311 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO 10 percent. The results ofMTR' s analysis for the hydrogen membrane, including test data from the NCCC, indicate that the increase in cost of electricity would be 15 percent, half that achieved using Selexol (according to MTR) but still above the DOE targeted value of I0 percent. Hence, some improvement in membrane performance is required, and the NCCC is expecting to support the testing required to achieve the necessary enhancement. In summary, both the C02-selective Polaris membrane and Hrselective Proteus membrane have performed well using coal-derived syngas. The results are consistent with those from MTR · s bench-scale test using simulated syngas. Stable membrane performance under industrial conditions is encouraging for further development of polymeric membrane technology. EDIA ROCESS TEC NOLOGY YDROGEN E BRANE The MPT Carbon Molecular Sieve hydrogen membrane was developed to demonstrate efficiency gain in the water-gas shift reaction while producing hydrogen from coal-derived syngas in a "one-box" configuration. The membrane was designed to enhance CO conversion in fuel gas via the removal of hydrogen in-situ, and/or yield high purity hydrogen as a product or co-product. The key feature of the one-box process is to limit pre-treatment requirements to particulate removal only. The membrane was first tested at the PSDF in 2008, which marked the first time a hydrogen-selective membrane was successfully operated on untreated coal-derived syngas. The MPT membrane operating temperature ranges from 480 to 570°F. At the lower temperature, the permeability is low but the selectivity is high and vice versa for the higher temperature. Since the PSDF syngas is more diluted by nitrogen than would be syngas from a commercial facility, bottled hydrogen was added to the syngas for the membrane testing, increasing the hydrogen concentration from about I0 percent to 55 percent. Testing was initially completed using a single-tube ceramic membrane 30 inches long with a 0.225-inch outer diameter housed in a 0.375-inch inner diameter stainless steel tube. For R04, MPT scaled up its single-tube membrane test unit to a multiple-tube assembly consisting often tubes similar to those in the single-tube arrangement. The tubes were housed in a 4-inch outer diameter stainless steel vessel using compression fittings with graphite ferrules to secure the tubes to the tube sheet. For this arrangement, the membrane material was coated on the outer tube surface to increase the membrane area per tube. The inlet syngas flow rate, augmented with hydrogen, was 12 lb/min with a maximum operating temperature of 450°F. While testing at this temperature, the permeate flux fell by I 0 percent because of hydrocarbons condensing on the membrane surface. The use of compression fittings proved cumbersome, so an improved design consisting of fourteen tubes held in position by fused glass in a ceramic collar was designed for testing in R05 (see Figure 31 ). The assembly was installed in a 2-inch outer diameter stainless steel tube. The inlet syngas flow rate, augmented with hydrogen, was 20 lb/min. At the 530°F operation temperature, the permeate flux remained constant, indicating that no hydrocarbon deposition had occurred. The modifications also improved controls and enabled continuous operation for over 100 hours. 36 SoCo FOIA Response 002312 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Figure 31. Media &Process Technology Hydrogen Membrane Assembly. Table 16 shows pure gas permeation measurements made with nitrogen and helium following testing in run R05. Table 16. Pure Gas Permeance Measurements of the MPT Hydrogen Membrane. Te erat re of 514 392 214 er ean e N 0.019 0.011 0.008 rbar e 1.02 0.80 0.48 I ea Se e tivit eN 53 70 64 The measurements show that nitrogen and helium permeance increases substantially from 392 to 514°F but the selectivity (He/N2) peaked at around 392°F. The temperature effect on selectivity explains the variation in permeate hydrogen content measured in the test program. These results indicate that the MPT carbon molecular sieve membrane operating at 530°F can be used to separate hydrogen from raw syngas without any reduction in performance. This temperature is compatible with water gas shift catalytic reactor temperature indicating that the water-gas shift reaction and hydrogen separation could potential be incorporated into a single unit process. The MPT membrane is still relatively small but testing at the NCCC along with the technical support provided, has assisted in increasing the size of the test modules and progressing the technology along the path to commercialization. E BRANE ATERIAL COU ON TESTING NETL selected a number of coupons of materials under consideration for use in hydrogen membranes to be exposed to coal-derived syngas at around 750°F. The materials were installed inside the hot gas filter vessel downstream of the filter elements. The data collected allows comparison of corrosion rates using actual coal-derived syngas with those collected in the laboratory using simulated syngas. The coupon types exposed were as follows: 37 SoCo FOIA Response 002313 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY • • • TOPICAL REPORT BUDGET PERIOD TWO Materials from NETL Pittsburgh approximately I00 microns thick, including Pd, PdCu (5 samples), PdCuX (4 samples), PdX (7 samples), and 2 miscellaneous alloys Six supported membrane materials from Worchester Polytechnic Institute, which included composite Pd and PdCu on porous stainless steel Four structural alloy materials from NETL Albany Each coupon was approximately one-inch square with a 0.125 inch diameter hole in one comer to allow the coupons to be wired inside a stainless steel mesh box in the filter vessel. The coupons were exposed to syngas for 1,000 hours at mean conditions of750°F, 7.5 vol% hydrogen, and 250 ppmv H2S. Analysis of the exposed coupons is still in progress. Analysis procedures being used include: • • • • Weight change X-ray diffraction Scanning electron microscopy (SEM) with energy dispersive spectroscopy of the exposed surfaces and prepared cross sections Elemental analysis using inductively-coupled plasma optical emission spectrometry and inductively-coupled plasma mass spectrometry Some of the X-ray diffraction results are presented in Figure 32. These show that a membrane consisting of only palladium sulfides failed within I,000 hours of exposure. The resistance to corrosion was increased as the percent of copper in the coupon material increased. However, based on previous membrane testing, increasing the copper content decreases the hydrogen permeability ofthe alloy. Pd only-Only Pd4Sphase detected. Pd ooupon oompletely sulfided and fractured. 80-wt% Pd in Cu- Thick sulfided corrosion layerofPd13Cu3Swith trace ofPd4Sdetected. Pd metal not detected. 60-wt% Pd in Cu-Only ordered-body centered-cubic alloy detected. Sulfides visible by SEM are below detection limit ofstandard scan conditions used. Figure 32. X-Ray Diffraction Analyses of Membrane Material Coupons Exposed to Filtered Syngas. 38 SoCo FOIA Response 002314 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO OST CO BUSTION CO CA TURE Design and construction of the PC4 continued at the Alabama Power E.C. Gaston plant site (see Figure 33). The layout of the PC4, shown in Figure 34, contains several areas for testing of carbon capture technologies, a control room building, electrical infrastructure, and a Balance of Plant (BOP) area containing utilities and chemical storage/handling. Fabrication of the PSTU, a major part of the PC4 test equipment, and utility bridge modules continued during BP2. Initial commissioning activities were underway during the last part of the year. Figure 33. PC4 Site at the E.C.Gaston Plant. PSTU 2nd PILOT UNIT BAY 1,180 micron) Content, wt% As-Fed Fine (<45 micron) Content. wt% Avera~eVa e R 7 R 7 4 43 930 4 43 830 38 11 29 1 While mill system operation was satisfactory, problems occurred during R03 with the dense phase pneumatic conveyor that transfers the processed biomass from the mill system pulverized storage silo to the coal feeder storage silo. The root cause of the transfer problems was a combination of flow restrictions in the discharge piping and insufficient conveying gas supply. First, the discharge piping layout was not conducive to the transfer of a lower density fibrous material such as biomass, as it contained several long radius elbows that reduced the velocity of the material enough to cause it to collect along the bottom of the piping, eventually forming a plug in the line. The fibrous structure of the biomass allowed the individual particles to compress and interlock with one another, forcing them outward against the pipe wall and preventing the material from transferring. This occurrence had not been observed in previous operations when conveying coal from the pulverized silo to the feeder due to its noncompressible nature. The second and equally important cause for the transfer problem was that the system had an insufficient supply of conveying gas (nitrogen) to maintain conveying velocity of the biomass particles high enough to prevent line plugging. Both of these problems were mitigated during the run by decreasing the amount of biomass charged to the conveyor and by re-arranging and adding conveying gas to the system. During the outage between run R03 and R04, modifications were made to the dense phase conveying system that transfers the biomass from the pulverized coal storage silo to the coal feeder. The piping layout was modified to remove excess elbows and other areas of unnecessary pressure drop. Additionally, the conveying gas supply to the dense phase feeder was increased and booster gas was added to elbows in the transfer line. For the transfer line booster gas additions, new Kates flow controllers were installed that maintain a constant volumetric flow of gas by using an internal regulating valve to counterbalance downstream fluctuations in pressure. These changes resulted in improved system operation when compared to R03 operation, maintaining solids velocity requirements high enough for consistent transfer of the low density biomass material. Figure 44 shows some of the changes made. 59 SoCo FOIA Response 002335 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Figure 44. Modifications to the Dense Phase Transfer Line for Biomass Conveying. While it is recognized that the dense phase conveying is not as well-suited for this application as other pneumatic conveying methods (i.e., dilute phase conveying with higher gas to solids ratios), the modifications incorporated provided the most economical path to successful conveying of the biomass at this facility. Off-Line Biomass Feeder Testing. A milestone to perform off-line testing with different biomass/coal was incorporated in the project plan to support testing of co-gasification of biomass with coal during R03 and R04. While the wood pellets that were tested during R03 (from forest waste) were different in physical properties from the pellets tested in the off-line system in early 2009 (made from recycled furniture), the biomass was successfully fed during R03 for more than 200 hours without any operational problems in the gasifier. The prospect of testing a torrified biomass material was investigated but there were concerns about the economic viability of a commercial plant using this expensive material, plus the material could not be acquired during the available time frame. Based on the unavailability of the alternate biomass and the success during R03, plans were made to move forward with another co-feed test in run R04 with a different coallbiomass feed of Mississippi lignite and the wood pellets without another off-line test. GASIFIER 0 ERATION Gasifier operation during coal only feeding and during co-feeding of coal and biomass yielded high carbon conversions, as shown in Table 25. Table 25. Steady Stale Carbon Conversions for R03 and R04. ini ai Coal Only Carbon Conversion, % Biomass Co-Feed Carbon Conversion, % R R 98.7 99.6 99.9 99.9 R 97.1 98.9 Averaae R R R 97.6 99.3 98.3 99.2 99.1 99.6 60 SoCo FOIA Response 002336 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO Inspections of gasifier ash samples taken during coal-only feed and during co-feeding periods did not indicate agglomeration (see Figure 45). Additionally, the primary gas cooler performance remained stable, and condensate sampling did not indicate any evidence of tar formation. Coal Feed Only Coal/ Biomass Co-feed Figure 45. Gasifier Ash Samples during Coal-Only Feed and during Biomass Co-Feed in R04 During the final hours of test run R04, a period of biomass feed only was tested. Primary gas cooler performance began to deteriorate soon after establishing biomass only feed to the gasifier, as the cooler outlet temperature began to rise (evidence of tube fouling). Eventually, this decrease in performance resulted in the end of gasifier operations for R04. Post-run inspections revealed fouling in the primary gas cooler tubes, as shown in Figure 46. Samples from the tubes were collected for analysis, and results indicated the presence of tars. A secondary test of the tube foulant did not reveal any alkali metal content which can also provide a mechanism for fouling. For biomass co-feed operation in the future, a more gradual transition to biomass only feed is planned to better understand when the increased tar generation problem begins. Inlet Section Middle Section Outlet Section Figure 46. Post-Run Inspection of Primary Gas Cooler Tubes. 61 SoCo FOIA Response 002337 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO EFFECT OF BIO ASS CO GASIFICATION ON AS C ARACTERISTICS Table 261ists the characteristics of the ash entering the particulate control device (PCD) during gasifier operation with and without biomass co-feeding. Because of the low ash content of the biomass, the addition of biomass reduced the inlet ash concentration with both the PRB coal and the Mississippi lignite. The addition also increased the bulk density and true density of the ash, while reducing the bulk porosity and surface area. The loss on ignition was also reduced, suggesting that the biomass addition improved carbon conversion. There was no significant effect on mean particle size of the ash as this is controlled primarily by the performance of the gasifier solids separation devices. Table 26. Effect of Biomass Co-Gasification on Ash Characteristics. B Gasi ier F e PRB Coal (R03) PRB Coal (R05) PRB Coal and Biomass (R03) MS Lignite (R04) MS Lignite and Biomass (R04) Den sit Tr e Densit a a 0.25 0.31 0.35 0.45 0.52 2.64 2.64 2.74 2.62 2.77 orosit loss on Ignition 90.5 88.2 87.2 82.8 81.1 19.2 16.5 9.8 10.3 2.1 B Effect of Biomass Addition on Particle-Size Distribution. Figure 47 shows the effect of biomass addition on the particle-size distribution of ash entering the PCD as measured by Microtrac laser diffraction analysis of the PCD inlet ash samples. Particle Diameter, micrometers Figure 47. Particle-Size Distributions of Ash Measured at PCD Inlet. 62 SoCo FOIA Response 002338 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO The results are presented as a series of differential mass distributions that represent a differentiation of the cumulative mass loading curve. This type of presentation is widely used with tine particle measurements, because the dM/dlogD value reflects the mass concentration of particles in a given size band, and the area under the curve between any two points indicates the mass concentration of particles within that particle size range. As indicated in Figure 4 7, the addition of biomass reduced the mass concentration of ash over almost the entire particle size range. With PRB coal, the mass reduction occurred over the range of about I to 50 microns. With Mississippi lignite, the reduction was evident over the range of about 0.5 to 30 microns. Little difference is seen in the distributions at the upper end, because those particles are largely removed by solids separation section of the gasifier. Effect of Biomass Addition on Transient Drag. Past studies showed that dustcake drag generally decreases with decreasing ash carbon content (or decreasing loss on ignition). Since the loss on ignition was reduced by the addition of biomass, a commensurate reduction in the dustcake drag was expected. The transient drag of the dustcake is calculated from the transient pressure drop, the ash mass loading, and filter face velocity (based on syngas flow) using procedures presented in earlier reports. (Transient pressure drop is the pressure drop increase between pulse-cleaning cycles.). In keeping with previous results, the drag was proportional to the ash carbon content (loss on ignition) as indicated in Figure 48. The lignite ash has lower drag than that of the PRB due to differences in ash morphology and the slightly larger particle size of the lignite ash resulting in Jess flow resistance. For both fuels, the lowest drag occurred with coal and biomass co-feeding. Based on these results, the addition of biomass would not have an adverse effect on PCD pressure drop. 1 140 -120 ~ ~100 ;?" ·~ :1:! ~~I C5' 80 :f ~ 60 c i 1- 40 PRBCoalwilh Biomass I~ ""1"0"l0!!to . Mississ ppi Ugnitewilh Biomass 20 -- 0 0 5 10 15 20 25 Ash Carbon Content (LOI), wt% Figure 48. Transient PCD Drag as a Function of Carbon Content. Laboratory Drag Measurements. Figure 49 shows dustcake drag as a function of particle size using the re-suspended ash permeability tester in the on-site laboratory. In these measurements, the ash samples obtained with and without biomass addition are re-suspended in a fluidized bed and 63 SoCo FOIA Response 002339 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVElOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO passed through various combinations of small cyclones to produce ashes with a range of particle sizes. The ash from the cyclones is collected on a sintered metal plate. Monitoring the flow and pressure drop during the build-up of the dustcake on the sintered plate and weighing the collected cake allows the dustcake drag to be determined as a function of particle size. ~ ~ 200 ~ 150 ? I g ~ "iij E ~ 100 70 50 40 30 PRBCool .ol y PM6 + Blo~u • Uoni\e +810m111 e Ugna• Co•l 3 4 5 6 8 10 15 20 Particle Diameter, micrometers Figure 49. Effect of Biomass Addition on Laboratory Drag Measurements. As shown in Figure 49, the dust cake drag with both the PRB coal and Mississippi lignite is lower for ashes with biomass addition over the particle size range studied (approximately 2 to I0 microns). This difference is considered to arise primarily from the effect of carbon content shown in Figure 48. From the two figures, it can be concluded that the transient drag of the dust cake is inversely proportional to its mean particle size and proportional to its carbon content, although there is also likely a contribution from other morphological differences. SENSOR DEVELO ENT Because of the research nature of the NCCC/PSDF and the unique process conditions, significant effort has gone into the development of instrumentation. During BP2, sensor development included a sapphire thermowell for gasifier service, a coal flow measurement device, and coal feeder level probes. SA IRET ER 0 Ell A sapphire therrnowell was installed in the gasifier riser prior to run R04 to test the durability of this material in a high-velocity, erosive environment. The performance of the sapphire thermowell was compared with an existing HR-160 therrnowell installed in the same plane of the gasifier. Both therrnowells contained Type-N thermocouples which have an accuracy of +1- 0.75 percent. The percent difference between the average steady state temperature 64 SoCo FOIA Response 002340 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO indications of the thermocouples averaged about one percent during R04 and averaged about 3.5 percent during ROS. Figure 50 illustrates the agreement of the two indications. 1,850 l"' 1,800 1- ,§; 1,750 "i "' 1,700 0.1!- 1- x • R05 Steady Stale Data en I i= ~~ 1,600 I!! .a 1,550 E 1,500 i ~ - Perfect Agreement , ,,, , , __ v-r- , ,, - , ,, . ,, ,, , ,, , ,, ,, / ~?!· / .·"._,._ ····...,' . , - - -+/- 7.5 Percent 1,650 Et- .g R04 Steady State Data ·~ ,' / 1( ,, . - , , -, ,, ,, , r---- ,, ~ -- - , -.-.- 1,450 " r1,450 1,500 1,550 1,600 1,650 1,700 1,750 1,800 1,650 ~ Temperature from Thermocouple with HR-160 ThellTlOINell, °F Figure 50. Comparison of Temperature Readings for Sapphire and HR-160 Thennowells. Post-run inspections of the thermowell revealed no signs of erosion or ash deposition. While the percent difference between the two temperature indications at the beginning of R05 was close to the expected accuracy for the thermocouple type, the sapphire thermowell indication began to drift low about 330 hours into the run. Based on this observation, thermowell condition and/or a temperature transmitter problem were thought to be the cause. The temperature transmitter will be inspected during the outage to determine if it contributed to the slow decrease in the temperature reading. Additional insight into the observed performance will be pursued with representatives of Emerson Process Management, who supplied the thermowell, pending the outcome of the transmitter investigation. DENSFLO COAL FLO ETER A new coal flow measuring device, the DensFiow meter from SWR Engineering, was installed in the developmental coal feeder discharge line to the gasifier prior to R04. This device is a nonintrusive technique of measuring solids flow using a patented alternating electromagnetic field. The solids flowing through the device absorb this field energy, and a measurement of density of the material is inferred. Simultaneously, conveying velocity is also calculated by the same sensors. The combination of the two measurements with the cross sectional area of the device yields a mass flow rate of material through the feeder discharge line. Operation of the flow meter during R04 with Mississippi lignite showed good agreement when compared to the existing weigh cell loss of weight calculation. The measurement was also sensitive to instantaneous changes in coal feed rate when compared to existing conveying line differential pressure readings. During ROS, the flow meter again displayed good agreement with 65 SoCo FOIA Response 002341 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO the weigh cell calculation at higher flow rates. However, during low feed rates with PRB coal during ROS, the agreement was poor. Figure 51 plots the feed rate data for the two runs. 6,000 ~ li 5,000 4,000 +-----------.r-~----1 ~ ~ 4,000 t------~ ~ ' I t - - --41 ~ 1,000 t-~~----j--Pelrfect~IQ!eell'lentH 8 1,000 3,000 1--t--t--t--t-~:--:.~:-t~-i ~ 2,000 1--+--t--1-+l~.P:::-t£--1--+--i 3000 - 1 - - - - - - - : ~ 2,000 3,500 t a: ~ 2,500 1---+-t--+-1.1 u. 't; ~ 2,000 t--+--+--t--+--+-- n :"71"'-0-i ~ 3,000 4,000 5,000 Coal FlowRaleCaiOJialed from Weigh Cells,IMlr Test RunR04 6,000 1~ ~-+-4-~.~~~~~~~~~ ~ u. 1,000 ~ 1--1-~1111 500 0 ~~~~~~~~ 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 Coal Flow Rale Calculaled from Weigh Cells,lb.br TestRunR05 Figure 51. Comparison of Flow Rates from DensFiow Meter and from Weigh Cell Indications. Discussions with SWR Engineering representatives indicated that the inaccuracy could be due to the change in coal properties, and that recalibrating the probe using PRB coal as the reference material should result in more reliable readings. The meter will be recalibrated for future service with PRB coal. COAL FEEDER LEVEL ROBES Dynatrol Level Probes. Long term evaluation of the Dynatrol vibration level probes continued during R04. The probes were installed to replace older, less reliable capacitance probes in several locations including both the lock vessel and dispense vessel of the feeder. The probes continued to demonstrate consistent operation. The vibration probes have a wide range of material measurement capability, from low density flakes or powders to heavy granules and pellets, and there is no required field adjustment of the probes after installation. After ROS, the probes had operated for over 2,500 hours providing consistent indication of solids levels inside the vessels for both lignite and subbituminous coals. Drexelbrook Level Probe. Additional level probe technology was tested in the PDAC feeder dispense vessel during R04. Observations of previous feeder operation revealed a decrease in coal feed rate slightly before a subsequent lock vessel fill cycle occurs. Data analysis of these instances indicated that a deep funnel was forming inside the dispense vessel resulting in the drop in coal feed rate. In order to prevent this occurrence, the dispense vessel needed to be controlled at a higher level. Therefore, a vertical level probe was installed in the top of the dispense vessel to permit the lock vessel fill cycle to occur sooner, maintaining higher level control. A Drexelbrook point sensitive level probe was selected for this service. The operating basis of the probe is similar to a capacitance probe but combines a radio frequency signal with circuitry 66 SoCo FOIA Response 002342 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO shielding technology to ignore the effects of material buildup on the probe. Initial field calibration of the probe was required using a simple potentiometer adjustment. Controlling at a higher level helped avoid the development offunnel flow inside the vessel, resulting in a more consistent coal feed rate. However, there were occurrences during which the level probe did not change state causing the vessel to become overfilled. It was determined that the probe had been improperly calibrated prior to R04, causing a decrease in the point sensitivity. After re-calibrating the probe, it was used for dispense vessel level control during the entire R05 run without any instances of vessel overfill. GASIFIER ERFOR ANCE EVALUATION Parametric testing was performed during gasifier startup of run R04 (before coal feed) to determine if standpipe fluidization could be used exclusively to control gasifier solids circulation rate to low levels. Test data indicated that gasifier solids circulation rate could be controlled to low levels by varying only the fluidization to the bottom of the standpipe. Figure 52 illustrates the relationship demonstrated during this testing. ..,, .;,-- . .. . , ,til . ~ ,' ~ a:: "• I' / c:: .Q ".. I 16 "3 ~ (3 . i:,. "' :E 0 Q) Qj a:: ,,.. . .. ,;-' en > ~ 4 r .,..~-. Relative Fluidization Rate to Bottom of Standpipe, lb/hr Figure 52. Gasifier Solids Circulation Rate versus Fluidization Rate to Bottom of Standpipe. A new gasifier temperature control scheme utilizing upper and lower mixing zone air flow adjustments was evaluated during R05. The purpose of this new control scheme was to demonstrate control of gasifier mixing zone temperatures using standard proportional-integralderivative controllers to adjust air flow to the different zones while maintaining a constant total air flow to the gasifier. The control scheme was further modified during the run to control gasifier exit temperature by adjusting the gasifier total air flow set point. Control loop tuning was performed to modify the responsiveness of the controllers to changes in gasifier temperature set point. Since gasifier upper and lower mixing zone temperatures respond rapidly to changes in air feed rate, the temperature controllers were tuned to respond slowly to minimize temperature overshoot. Figure 53 plots the response to a change in temperature set point. 67 SoCo FOIA Response 002343 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO 1,800 1,780 u.. 0 1,760 .a~ 1,740 ~ 1,720 iE ...... 1,700 1,680 1,660 t;v· I , ~ ~1I ' ·- 1 A-- ~--I 0 ~ I - Gasifier Mixing Zone Temperature -Gasifier Mixing Zone Temperature Setpoint - Gasifier Exit Temperature - Gasifier Exit Temperature Setpolnt 1.5 0.5 2.5 2 Time, hours Figure 53. Gasifier Temperature Response to Set Point Change. Additionally, the controllers were tested to ascertain the ability to maintain a constant gasifier temperature. Figure 54 illustrates the steady state temperature performance. The controllers will be optimized further in future gasification runs. 1,790 1,780 ~ i 1.760 ... 1,750 8. 1,740 ~ 1,730 1,rn ::: t' r - -Gasifier Mixing Zone Temperature Setpoint - GasifierExitTemperature __ - Gasifier Exit Temperature Setpoinl lA-6_+-••.{~nlJ\-M , -~ ~ VVV"~'If"'~ 1.690 - 0 2 3 - ~ 4 5 Time, hours Figure 54. Gasifier Temperature Control Steady State Performance. OT GAS FILTER ELE ENT EVALUATION During the gasification test runs, the PCD operated with very high collection efficiency (>99.999%) and without any filter element failures. Since the PCD was not opened for inspections during 2010, there was no off-line inspections of the filter elements. A new type of 68 SoCo FOIA Response 002344 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO filter element was tested in the cold-flow filter model, but the collection efficiency did not meet selection requirements. Filter Element Configuration. For all of the gasification testing conducted in BP2, the PCD was configured with a total of 72 filter elements, which are given in Table 27. Since the PCD was not opened between tests, the same filter element configuration was used for all three test campaigns with a total exposure to syngas of2,088 hours. Table 27. Hot Gas Filter Elements Tested During BP2. Fi ter e iaT e Sintered Metal Powder Fine Sintered Metal Fiber Coarse Sintered Metal Fiber Sintered Metal Powder Sintered Metal Fiber ateria Iron aluminide HR-160 HR-160 High alloy Coated high alloy s ier Bran Paii/PSS PaD/Dynalloy PaU/Dynalloy Molt Porvair/Sinterllo N ber lnsta e 20 17 22 3 10 Tota s ngas E os re o rs 4,050 to 13,540 3583 2,088 to 5,610 2088 2560 Testing allowed continued exposure of the Paii/PSS iron aluminide sintered metal powder elements along with several different types of sintered metal fiber elements supplied by Pall, Mott, and Porvair. The PCD will be opened early in 20 II for detailed inspection, and the elements will be removed for tlow testing, cleaning, and corrosion evaluation. Qualification TestinqofNewFilter£/ements. Cold-flow particulate collection efficiency tests were conducted with a new type of sintered metal fiber filter element that was in an early stage of development. The prototype element failed to achieve acceptable collection efficiency, normally 99.995 percent for a new filter, but the supplier is working on improvements in the filter element design. When an improved prototype is available, another set of collection efficiency measurements will be made to assess the design improvements made by the manufacturer. Overall, the results from the cold-flow PCD testing continued to show that the collection efficiency of the sintered metal fiber elements increases with decreasing fiber size. However, the finer fiber size also produces a higher pressure drop and is more vulnerable to corrosion. As noted previously, the sintered metal powder elements tend to give higher collection efficiencies than do the sintered metal fiber elements due to the more tortuous flow path through the filter media. Collection efficiencies in excess of99.9999 percent can be achieved with the sintered metal powder media and with other media that have been conditioned in the PCD. 0 NSON ATI EY ERCURY SORBENT In collaboration with the NETL, Johnson Matthey has been developing a solid, sorbent-based process to remove mercury and other trace contaminants, such as arsenic and selenium, at high temperature in coal gasification processes. Compared to low-temperature capture by activated carbon, high-temperature capture of these trace elements retains the high thermal efficiency of the coal gasification process in IGCC power plants. 69 SoCo FOIA Response 002345 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO The high-temperature, palladium-based, mercury adsorbent supplied by Johnson Matthey was tested in runs R04 and R05 in the SCU. Around I0 pounds of sorbent (which had been reduced on site to its metallic form) were placed in a pressure vessel in a fixed-bed arrangement. A catalyst bed height of 14 inches was selected to achieve the required space velocity of2,800/hr. Table 28 lists the test conditions. Table 28. Operating Conditions for Mercury Sorbent. TestR n R Test R nR 10 500 195 Svnaas Flow Rate, lblhr Ooeratina Temperature, "F Ooeratina Pressure, psia Hours of Operation Palladium Content. wt% 25 500 195 720 5 500 2 The objectives of the test program are to: • • • Determine durability of sorbent under commercially realistic operating conditions Improve candidate sorbent capacities Elucidate mercury-sorbent interactions During R04, ten gas samples, five each from the inlet and outlet of the sorbent bed, were collected using a modified EPA Method 29 for trace metal analysis of mercury, arsenic, and selenium. Breakthrough of each species occurred between the times the last two samples were taken, but prior to that collection efficiency was near I 00 percent. During R05 twelve gas samples, six each from the inlet and outlet of the sorbent bed were collected. No breakthrough of the three species was detected, indicating that the beds were not saturated. The absence of breakthrough during the R05 could be partially explained by the lower inlet mercury concentration. Figure 55 provides syngas mercury concentrations during R04 and R05. After both test runs, the sorbent was removed from the bed in seven layers and returned to the Johnson Matthey company for analysis. of ~j 2030J~-----------=====L­ I (.) 10J~--~--------r-~ 0 .l.d~~k::=:J~~~ 110 182 278 Run Hours TestRun R04 370 467 I ~ _g: ~ (.) 30 ~----------~ 2o J----------------=====10 0 .lc::lk =A.::=:k=ll-=:.::1111:7 139 283 382 474 522 642 Run Hours TestRunROS Figure 55. Reactor Inlet and Outlet Mercury Concentrations during Sorbent Testing. NETL Mass Spectrometry. During R05, a Gas Chromatograph-Inductively Coupled Plasma/Mass Spectrometry (GC-ICP/MS), shown in Figure 56, which is under development at NETL, was 70 SoCo FOIA Response 002346 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO incorporated into the mercury sorbent test. This instrument allows for on-line measurement of trace metal concentrations. To prevent trace metal adsorption in the sample tube delivering syngas to the instrument, the inner surface was coated with one-micron thick silicon oxide barrier layer. Figure 56. GC-ICP/MS at DOE-NETL Laboratory. This was first time this instrument was used in the field to measure mercury concentrations directly. Data were collected continuously every 15 minutes. Although measured mercury levels from the GC-ICP/MS were higher than those determined by the EPA method, the results demonstrated the potential to gather real-time data and to facilitate control over key parameters. More analysis is being conducted at NETL to understand the discrepancy. In addition, NETL researchers are incorporating lessons teamed during ROS, which includes improving the heat tracing of sampling loops and controls for system pressure and syngas flow. The instrument will be tested further during future test runs. 71 SoCo FOIA Response 002347 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY TOPICAL REPORT BUDGET PERIOD TWO CONCLUSIONS AND LESSONS LEARNED Conclusions and lessons learned from studies and from experience gained during BP2 are discussed in the following sections. TEC NOLOGY ASSESS ENT • • • • • • • • Both PCC and TROC require a significant capital investment and negatively affect plant performance. Both PCC and TROC are capable of recovering a minimum of90 percent of the C02 produced by the plant, and some TROC configurations can capture 99 percent if the C02 product purity is decreased Both PCC and TROC (in one configuration) are capable of meeting typical industry C02 product specifications, including some for enhanced oil recovery If high product purity is not required, the TROC capital cost can be reduced by choosing a configuration with less C02 purification, while still achieving a purity sufficient for sequestration Although the results show 3 to 12 percent lower capital costs for TROC compared with PCC (on a $/kW basis), the difference is within the accuracy of the estimate Although a space-constrained site adds to the capital cost ofTROC, Case 5 suggests that the increment is not excessive TROC has lower heat rates and O&M costs compared with PCC resulting in a I0 to 16 percent lower LCOE, at 75 percent capacity factor, and this advantage widens if dispatch differences are considered It is expected that PCC and TROC dispatch rates would be significantly different since the TROC dispatch costs (fuel plus variable O&M) are 24 to 26 percent lower than for PCC RE CO BUSTION CO CA TURE AND SE ARATION • • • • Water-gas shift reaction testing showed that sufficiently high CO conversions were achieved at lower than recommended steam-to-CO ratios and that only marginal increases in conversion would be realized for ratios above 1.6. No methane was formed and no carbon was deposited in the reactor. The evaluation studies also indicated that for a 500-MW JGCC plant, a steam-to-CO ratio of 0.1 corresponded to 4 MW of power, so operating with excess steam would have a significant impact upon net power production. For example, if a steam-to-CO ratio of 1.6 was acceptable rather than 2.6, then an additional 40 MW would be available for distribution to the grid. Measured concentrations of ammonium carbamate and ABC were predicted with good accuracy by the OLI model and any error associated with ammonium carbonate was low. This was considered to validate the model and allow it to be used with confidence for predicting the composition of the ammonia liquor. Testing of ammonia sorbent regeneration showed that despite the temperature increase, no ammonium bicarbonate decomposed, and no C02 was released. Results suggested that the liquor re-established chemical equilibrium at the new temperature. At around 60°C, C02 72 SoCo FOIA Response 002348 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY • • • • • • • • • TOPICAL REPORT BUDGET PERIOD TWO release began, but ammonium bicarbonate was being formed and did not start to decompose until the temperature was around 80°C. Controlling the sorbent absorption temperature at 40°C requires additional cooling to remove the heat released when the ammonium bicarbonate crystallizes. When regeneration is required, heat must be added to dissolve the crystals and the temperature raised to above 80°C before significant C02 is released. Cooling duty and water usage could be reduced if absorption could be carried out effectively closer to 60°C. This would also reduce the sensible heat required (some of which is recovered using recuperators) to raise the liquor to regeneration temperature. A possible drawback of operating the absorber at 60°C is an increase in ammonia slip in the exiting C02-depleted syngas. The ammonia would be scrubbed out using water wash, although this constitutes a system loss. The feasibility of operating the absorber at temperatures greater than 40°C will be assessed with additional modeling and batch reactor testing. Agreement between the data from OLI modeling and from the Raman Spectroscope was not good, and comparisons of ammonium carbamate and carbonate were similarly poor. More testing and analysis is required to understand how to achieve a correlation that is applicable to all concentrations of ammonia. The incentive for resolving this issue is that the Raman probe with its rapid response could potentially be used to monitor and control a commercial process. SCU test data showed that with or without water addition, DEPG achieved higher absorption efficiencies than PDMS for initial and subsequent cycles. Also, the C02 concentration profile indicated that absorption was maintained for a longer period, allowing DEPG to achieve a higher loading level. From the area within the concentration profiles, the C02 loading for DEPG was approximately 1.4 times higher than that for PDMS. The H2S concentration profiles indicated that absorption was maintained for a longer period with DEPG than with PDMS. From the area within the concentration profiles, the H2S loading for DEPG is approximately 3.5 times higher than that for PDMS. The C02 mass loading for ammonia was shown to be greatly in excess of potassium carbonate and potassium prolinate, with the potassium carbonate having the lowest loading. During testing of the MTR C02 membrane, the C02 concentration in the permeate was 4 to 5 times that of the feed steam, and the H2S concentration was about 6 times higher in the permeate than in the feed stream. During the testing, the membrane operated stably with variations occurring primarily from changes in ambient temperature, with a lesser effect of syngas composition and flow rate. Results from MTR's hydrogen membrane tests indicated that hydrogen in the feed stream was enriched 6 to 8 times in the permeate stream. The presence of H2S in the syngas feed did not compromise membrane performance. Both the C02-selective Polaris membrane and H2-selective Proteus membrane from MTR performed well using coal-derived syngas. The results were consistent with those from MTR's bench-scale test using simulated syngas. Stable membrane performance under industrial conditions is encouraging for further development of polymeric membrane technology. 73 SoCo FOIA Response 002349 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY • • TOPICAL REPORT BUDGET PERIOD TWO Test results indicate that the MPT carbon molecular sieve membrane operating at 530°F can be used to separate hydrogen from raw syngas without reduction in performance. This temperature is compatible with water gas shift catalytic reactor temperature indicating that the water-gas shift reaction and hydrogen separation could potential be incorporated into a single unit process. Coupon testing of potential membrane materials showed that material consisting of only palladium sulfides failed within I ,000 hours of exposure. The resistance to corrosion was increased as the percent of copper in the coupon material increased. OST CO BUSTION CO CA TURE • • • • • The PC4 site preparation work included recovery of an area from the Plant Gaston coal pile run-ofT pond, leveling and compaction of the site, and commencement of caisson installation. A total of 75 caissons and 30 micropiles were required to provide a solid base for continued installation of foundations and other civil engineering components. The micropiles were required in some areas where existing underground piping and electrical conduits could not be rerouted. In addition, 54 piers were installed at the top of the caissons in preparation of setting support columns for utility bridge modules. The PSTU design included development of a 3-D model, which greatly assisted field personnel during fabrication. Quality control procedures were developed, which will be employed to ensure that data collected is of the highest possible value. Analytical methods will require further development to be used in the unique applications of the PC4. The establishment of the PSTU commissioning and start-up team was key in personnel training, procedure development, and other preparations which all worked to keep the commissioning on schedule. GASIFICATION ROCESS • • • • • The increased reliability of level probe indications provided by the vibration-type probes in the PDAC feeder allow the lock vessel filling cycle to be optimized by using the level probe indication to end the fill cycle instead of waiting for the timer to time out. The benefit of this change is especially significant when operating the feeder at higher feed rates. Optimization of the PDAC instantaneous feed rate feedback control resulted in decreased feed rate variability as indicated by the conveying line differential pressure indication. Controlling the PDAC feeder silo at a higher level promoted a mass flow regime from the bin, decreasing material segregation that can lead to coal feed rate fluctuations. Operation of the gasifier with biomass/coal blends yielded steady state carbon conversions averaging over 99 percent. During operation with biomass, the gasification process operated with reliable feeding and with no evidence of ash agglomeration, corrosion, or excessive tar formation. Because of the low ash content of the biomass, the addition of biomass reduced the inlet ash concentration with both the PRB coal and the Mississippi lignite. The addition also increased the bulk density and true density of the ash, while reducing the bulk porosity and 74 SoCo FOIA Response 002350 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY • • • • • • • • • • • • • TOPICAL REPORT BUDGET PERIOD TWO surface area. The loss on ignition was also reduced, suggesting that the biomass addition improved carbon conversion. For both PRB and Mississippi lignite coals, the gasification ashes produced with biomass cofeeding had lower drag than the ashes produced by coal feeding alone. Based on ash characterization studies, the addition of biomass would not have an adverse effect on PCD pressure drop. The performance of the sapphire thermowell in the gasifier riser degraded slightly. Additional insight into the observed performance will be pursued with representatives of Emerson Process Management, who supplied the thermowell, pending the outcome of the transmitter investigation. Operation of the flow meter during R04 with Mississippi lignite showed good agreement when compared to the existing weigh cell loss of weight calculation. The measurement was also sensitive to instantaneous changes in coal feed rate when compared to existing conveying line differential pressure readings. During R05, the flow meter again displayed good agreement \Vith the weigh cell calculation at higher flow rates. However, during low feed rates with PRB coal during R05, the agreement was poor. The meter will be recalibrated for future service to improve performance. After R05, the Dynatrol level probes had operated for over 2,500 hours providing consistent indication of solids levels inside the vessels for both lignite and subbituminous coals. A Drexelbrook point sensitive level probe, installed to maintain a higher level control in the PCAD lock vessel, operated reliably after re-calibration. Test data indicated that gasifier solids circulation rate could be controlled to low levels by varying only the fluidization to the bottom of the standpipe. A new gasifier temperature control scheme demonstrated good control of gasifier mixing zone temperatures using standard proportional-integral-derivative controllers to adjust air flow to the different zones while maintaining a constant total air flow to the gasifier. Since gasifier upper and lower mixing zone temperatures respond rapidly to changes in air feed rate, the temperature controllers were tuned to respond slowly to minimize temperature overshoot. At the end of BP2 testing, the gasification process had operated for almost 15,000 hours on coal. During the gasification test runs, the PCD operation with very high collection efficiency (>99.999%) and without any filter element failures. The elements used included various metal elements supplied by Pall, Mott, and Porvair. Some of the elements have been exposed to gasification operation for over 13,500 hours. Results from cold-flow PCD testing continued to show that the collection efficiency of the sintered metal fiber elements increases with decreasing fiber size. However, the finer fiber size also produces a higher pressure drop and is more vulnerable to corrosion. In hot gas filter operation, collection efficiencies in excess of99.9999 percent can be achieved with the sintered metal powder media and with other media that have been conditioned from previous operation. Testing of the Johnson Matthey palladium-based mercury sorbent indicated collection efficiencies near I 00 percent. 75 SoCo FOIA Response 002351 NATIONAL CARBON CAPTURE CENTER POWER SYSTEMS DEVELOPMENT FACILITY • TOPICAL REPORT BUDGET PERIOD TWO Although measured mercury levels from NETL's GC-ICP/MS were higher than those determined by the EPA method, the results demonstrated the potential to gather real-time data and so facilitate control over key parameters. NETL researchers are incorporating lessons learned during R05, which includes improving the heat tracing of sampling loops and controls for system pressure and syngas flow. 76 SoCo FOIA Response 002352 From: Sent: To: Subject: Attachments: Thursday, July 28, 2011 7:26 AM Robbins, Brittley K.; Madden, Diane R.; PricingGroup Award: DEFC2606NT42391, Audit of For-Profit Recipients (316 Audit) Period Ending: 12/3l/2010(42391FPA_Al23110) 42391FPA_Al23110.pdf Subject: Distribution of Audit of For-Profit Recipients (316 Audit) ContracVGranVCooperative Agreement No. DEFC2606NT42391 with Southern Company Services Inc Period Ending 12131/2010 The attached report has been submitted by the contractor/recipient and received into FITS. This is the formal distribution for the deliverable, since this is an electronic only award. Thank you, Susan Olson SoCo FOIA Response 002353 SoCo FOIA Response 002354 SoCo FOIA Response 002355 56 57 SoCo FOIA Response 002358 SoCo FOIA Response 002359 SoCo FOIA Response 002360 SoCo FOIA Response 002361 SoCo FOIA Response 002362 SoCo FOIA Response 002363 SoCo FOIA Response 002364 THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES FINANCIAL SECTION II-8 SoCo FOIA Response 002365 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Southern Company and Subsidiary Companies 2010 Annual Report Southern Company’s management is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management’s supervision, an evaluation of the design and effectiveness of Southern Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2010. Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company’s financial statements, has issued an attestation report on the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2010. Deloitte & Touche LLP’s report on Southern Company’s internal control over financial reporting is included herein. Thomas A. Fanning Chairman, President, and Chief Executive Officer Art P. Beattie Executive Vice President and Chief Financial Officer February 25, 2011 II-9 SoCo FOIA Response 002366 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Southern Company We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company and Subsidiary Companies (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule of the Company listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and the financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting (page II-9). Our responsibility is to express an opinion on these financial statements and the financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the consolidated financial statements (pages II-44 to II-101) referred to above present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Atlanta, Georgia February 25, 2011 II-10 SoCo FOIA Response 002367 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Southern Company and Subsidiary Companies 2010 Annual Report OVERVIEW Business Activities The primary business of Southern Company (the Company) is electricity sales in the Southeast by the traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. Many factors affect the opportunities, challenges, and risks of Southern Company’s electricity business. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. Each of the traditional operating companies has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives. Southern Company’s other business activities include investments in leveraged lease projects, renewable energy projects, and telecommunications. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions and dispositions accordingly. Key Performance Indicators In striving to maximize shareholder value while providing cost-effective energy to more than four million customers, Southern Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share (EPS). Southern Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The fossil/hydro 2010 Peak Season EFOR of 1.67% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The performance for 2010 was better than the target for these reliability measures. Southern Company’s 2010 results compared with its targets for some of these key indicators are reflected in the following chart: 2010 Target Performance Top quartile in customer surveys 5.06% or less $2.30 – $2.36 Key Performance Indicator Customer Satisfaction Peak Season EFOR - fossil/hydro Basic EPS 2010 Actual Performance Top quartile 1.67% $2.37 See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2010 reflects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations. II-11 SoCo FOIA Response 002368 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report Earnings Southern Company’s net income after dividends on preferred and preference stock of subsidiaries was $1.98 billion in 2010, an increase of $332 million from the prior year. This increase was primarily the result of increases in revenues due to colder weather in the first and fourth quarters 2010 and warmer weather in the second and third quarters 2010, a litigation settlement agreement with MC Asset Recovery, LLC (MC Asset Recovery) in the first quarter 2009, increased amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia Public Service Commission (PSC), revenues associated with increases in rates under Alabama Power’s rate stabilization and equalization plan (Rate RSE) and rate certificated new plant environmental (Rate CNP Environmental) that took effect in January 2010, and increases in sales primarily in the industrial sector. The 2010 increase was partially offset by increases in operations and maintenance expenses, which include an additional accrual to Alabama Power’s natural disaster reserve (NDR), a gain in 2009 on the early termination of two leveraged lease investments, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects. Net income after dividends on preferred and preference stock of subsidiaries was $1.64 billion in 2009 and $1.74 billion in 2008. Basic EPS was $2.37 in 2010, $2.07 in 2009, and $2.26 in 2008. Diluted EPS, which factors in additional shares related to stockbased compensation, was $2.36 in 2010, $2.06 in 2009, and $2.25 in 2008. EPS for 2010 was negatively impacted by $0.12 per share as a result of an increase in the average shares outstanding. Dividends Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.8025 in 2010, $1.7325 in 2009, and $1.6625 in 2008. In January 2011, Southern Company declared a quarterly dividend of 45.50 cents per share. This is the 253rd consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. The Company targets a dividend payout ratio of approximately 70% of net income. For 2010, the actual payout ratio was 76%. RESULTS OF OPERATIONS Electricity Business Southern Company’s electric utilities generate and sell electricity to retail and wholesale customers in the Southeast. A condensed statement of income for the electricity business follows: Amount 2010 2010 Increase (Decrease) from Prior Year 2009 2008 (in millions) Electric operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total electric operating expenses Operating income Other income (expense), net Interest expense, net of amounts capitalized Income taxes Net income Dividends on preferred and preference stock of subsidiaries Net income after dividends on preferred and preference stock of subsidiaries $ 17,374 6,699 563 3,907 1,494 867 13,530 3,844 159 $ 833 1,116 2,054 65 $ 1,732 747 89 505 19 51 1,411 321 (41) $ (1,358) (865) (341) (183) 62 22 (1,305) (53) 53 (2) 128 154 61 (49) (12) $ 154 $ (12) 1,860 973 300 111 199 56 1,639 221 26 10 87 150 - - 1,989 $ 17 $ 133 II-12 SoCo FOIA Response 002369 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report Electric Operating Revenues Details of electric operating revenues were as follows: 2010 Amount 2009 2008 (in millions) Retail – prior year Estimated change in – Rates and pricing Sales growth (decline) Weather Fuel and other cost recovery Retail – current year Wholesale revenues Other electric operating revenues Electric operating revenues Percent change $ 13,307 $ 14,055 $ 12,639 384 32 439 629 14,791 1,994 589 $ 17,374 11.1% 144 (208) (21) (663) 13,307 1,802 533 $ 15,642 (8.0%) 668 (106) 854 14,055 2,400 545 $ 17,000 12.3% Retail revenues increased $1.5 billion, decreased $748 million, and increased $1.4 billion in 2010, 2009, and 2008, respectively. The significant factors driving these changes are shown in the preceding table. The increase in rates and pricing in 2010 was primarily due to Rate RSE and Rate CNP Environmental increases at Alabama Power and the recovery of environmental costs at Gulf Power. The 2009 increase in rates and pricing when compared to the prior year was primarily due to an increase in revenues from customer charges at Alabama Power and increased environmental compliance cost recovery (ECCR) revenues at Georgia Power in accordance with its retail rate plan for the years 2008 through 2010 (2007 Retail Rate Plan), partially offset by a decrease in revenues from market-response rates to large commercial and industrial customers at Georgia Power. The 2008 increase in rates and pricing when compared to the prior year was primarily due to Alabama Power’s increase under its Rate RSE, as ordered by the Alabama PSC, and Georgia Power’s increase under the 2007 Retail Rate Plan, as ordered by the Georgia PSC. Also contributing to the 2008 increase was an increase in revenues from market-response rates to large commercial and industrial customers. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. The traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental, storm damage, new plants, and PPAs. Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit power sales contracts, and short-term opportunity sales. Wholesale revenues from PPAs and unit power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on the market cost of available energy compared to the cost of the Company’s system-owned generation, demand for energy within the Company’s service territory, and the availability of the Company’s system generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Shortterm opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. In 2010, wholesale revenues increased $192 million primarily due to higher capacity and energy revenues under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010, as well as increased energy sales that were not covered by PPAs at Southern Power due to more favorable weather. This increase was partially offset by the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Alabama Power – Rate CNP” herein for additional information regarding the termination of certain unit power sales contracts in 2010. In 2009, wholesale revenues decreased $598 million. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $603 million in 2009. Excluding wholesale fuel revenues, wholesale revenues increased $5 million primarily due to additional revenues associated with a new PPA at Southern Power’s Plant Franklin Unit 3 which began in January 2009, partially offset by fewer short-term opportunity sales due to lower gas prices and reduced margins on short-term opportunity sales. II-13 SoCo FOIA Response 002370 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report In 2008, wholesale revenues increased $412 million primarily as a result of a 21.8% increase in the average cost of fuel per net kilowatt-hour (KWH) generated, as well as revenues resulting from new and existing PPAs and revenues derived from contracts for Southern Power’s Plant Oleander Unit 5 and Plant Franklin Unit 3 placed in operation in December 2007 and June 2008, respectively. The 2008 increase was partially offset by a decrease in short-term opportunity sales and weather-related generation load reductions. Revenues associated with PPAs and opportunity sales were as follows: 2009 2010 2008 (in millions) Other power sales – Capacity and other Energy Total $ 684 1,034 $ 1,718 $ 575 735 $ 1,310 $ 538 1,319 $ 1,857 KWH sales under unit power sales contracts decreased 55.0%, 7.5%, and 2.1% in 2010, 2009, and 2008, respectively. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Alabama Power – Rate CNP” herein for additional information regarding the termination of certain unit power sales contracts in 2010, which resulted in a decrease in capacity and energy revenues. In addition, fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales contracts, influence changes in energy sales. However, because the energy is generally sold at variable cost, fluctuations in energy sales have a minimal effect on earnings. The capacity and energy components of the unit power sales contracts were as follows: 2009 2010 2008 (in millions) Unit power sales – Capacity Energy Total $ $ 136 140 276 $ $ 225 267 492 $ $ 223 320 543 Other Electric Revenues Other electric revenues increased $56 million, decreased $12 million, and increased $32 million in 2010, 2009, and 2008, respectively. Other electric revenues increased in 2010 primarily as a result of a $38 million increase in transmission revenues, a $4 million increase in rents from electric property, a $4 million increase in outdoor lighting revenues, and a $4 million increase in late fees. The 2009 decrease in other electric revenues was not material when compared to 2008. The 2008 increase in other electric revenues was not material when compared to 2007. Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2010 and the percent change by year were as follows: Total KWHs 2010 Total KWH Percent Change 2009 2008 2010 Weather-Adjusted Percent Change 2009 2008 2010 (in billions) Residential Commercial Industrial Other Total retail Wholesale Total energy sales 57.8 55.5 50.0 0.9 164.2 32.6 196.8 11.8% 3.7 7.7 (1.0) 7.6 (2.8) 5.7% (1.1)% (1.7) (11.8) 2.0 (4.8) (14.9) (6.8)% (2.0)% (0.4) (3.7) (2.9) (2.1) (3.4) (2.3)% 0.2% (0.6) 7.1 (1.5) 2.0% (0.7)% (1.2) (11.7) 2.2 (4.5)% 0.0% 1.0 (3.5) (2.7) (0.9)% Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales increased 11.6 billion KWHs in 2010. This increase was primarily the result of colder weather in the first and fourth quarters 2010 and warmer weather in the second and third quarters 2010, increased industrial KWH sales, and customer growth of 0.3%. Increased demand in the primary metals, chemicals, and transportations sectors were the main contributors to the increase in industrial KWH sales. Retail energy sales decreased 7.7 billion KWHs in 2009 primarily as a result of II-14 SoCo FOIA Response 002371 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report lower usage by industrial customers due to the recessionary economy. Reduced demand in the primary metal, chemical, and textile sectors, as well as the stone, clay, and glass sector, contributed most significantly to the decrease in industrial KWH sales. Unfavorable weather also contributed to lower KWH sales across all customer classes. The number of customers in 2009 was flat compared to 2008. Retail energy sales in 2008 decreased 3.4 billion KWHs as a result of a 1.4% decrease in electricity usage mainly due to a slowing economy that worsened during the fourth quarter. The 2008 decrease in residential sales resulted primarily from lower home occupancy rates in Southern Company’s service area when compared to 2007. Throughout the year, reduced demand in the textile sector, the lumber sector, and the stone, clay, and glass sector contributed to the decrease in 2008 industrial sales. Additional weakness in the fourth quarter 2008 affected all major industrial segments. Significantly less favorable weather in 2008 when compared to 2007 also contributed to the 2008 decrease in retail energy sales. These decreases were partially offset by customer growth of 0.6%. Wholesale energy sales decreased by 0.9 billion KWHs in 2010, decreased by 5.9 billion KWHs in 2009, and decreased by 1.4 billion KWHs in 2008. The decrease in wholesale energy sales in 2010 was primarily related to the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010. This decrease was partially offset by increased energy sales under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010, as well as sales that were not covered by PPAs at Southern Power primarily due to more favorable weather in 2010 compared to 2009. The decrease in wholesale energy sales in 2009 was primarily related to fewer shortterm opportunity sales driven by lower gas prices and fewer uncontracted generating units at Southern Power available to sell electricity on the wholesale market. The decrease in wholesale energy sales in 2008 was primarily related to longer planned maintenance outages at a fossil unit in 2008 as compared to 2007 which reduced the availability of this unit for wholesale sales. Lower short-term opportunity sales primarily related to higher coal prices also contributed to the 2008 decrease. These decreases were partially offset by Plant Oleander Unit 5 and Plant Franklin Unit 3 at Southern Power being placed in operation in December 2007 and June 2008, respectively. Fuel and Purchased Power Expenses Fuel costs constitute the single largest expense for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market. Details of electricity generated and purchased by the electric utilities were as follows: Total generation (billions of KWHs) Total purchased power (billions of KWHs) Sources of generation (percent) – Coal Nuclear Gas Hydro Cost of fuel, generated (cents per net KWH) – Coal Nuclear Gas Average cost of fuel, generated (cents per net KWH)* Average cost of purchased power (cents per net KWH) 2010 196 10 2009 187 8 2008 198 11 58 15 25 2 57 16 23 4 68 15 16 1 3.93 0.63 4.27 3.50 6.98 3.70 0.55 4.58 3.38 6.37 3.27 0.50 7.58 3.52 7.85 *Fuel includes fuel purchased by the electric utilities for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power. In 2010, fuel and purchased power expenses were $7.3 billion, an increase of $836 million or 13.0% above 2009 costs. This increase was primarily the result of a $538 million increase in the amount of total KWHs generated and purchased due primarily to increased customer demand. Also contributing to this increase was a $298 million increase in the average cost per KWH generated and purchased due primarily to a 3.6% increase in the cost per KWH generated and a 9.6% increase in the cost per KWH purchased. In 2009, fuel and purchased power expenses were $6.4 billion, a decrease of $1.2 billion or 15.8% below 2008 costs. This decrease was primarily the result of an $839 million decrease related to the total KWHs generated and purchased due primarily to lower customer demand. Also contributing to this decrease was a $367 million reduction in the average cost of fuel and purchased power resulting primarily from a 39.6% decrease in the cost of gas per KWH generated. II-15 SoCo FOIA Response 002372 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report In 2008, fuel and purchased power expenses were $7.6 billion, an increase of $1.3 billion or 20.0% above 2007 costs. This increase was primarily the result of a $1.3 billion net increase in the average cost of fuel and purchased power partially resulting from a 25.3% increase in the cost of coal per net KWH generated and a 14.2% increase in the cost of gas per net KWH generated. From an overall global market perspective, coal prices increased substantially in 2010 from the levels experienced in 2009, but remained lower than the unprecedented high levels of 2008. The slowly recovering U.S. economy and global demand from coal importing countries drove the higher prices in 2010, with concerns over regulatory actions, such as permitting issues, and their negative impact on production also contributing upward pressure. Domestic natural gas prices continued to be depressed by robust supplies, including production from shale gas, as well as lower demand. These lower natural gas prices contributed to increased use of natural gas-fueled generating units in 2009 and 2010. Uranium prices remained relatively constant during the early portion of 2010 but rose steadily during the second half of the year. At year end, uranium prices remained well below the highs set during 2007. Worldwide uranium production levels increased in 2010; however, secondary supplies and inventories were still required to meet worldwide reactor demand. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the traditional operating companies’ fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information. Likewise, Southern Power’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Other Operations and Maintenance Expenses Other operations and maintenance expenses were $3.9 billion, $3.4 billion, and $3.6 billion, increasing $505 million, decreasing $183 million, and increasing $111 million in 2010, 2009, and 2008, respectively. Discussion of significant variances for components of other operations and maintenance expenses follows. Other production expenses at fossil, hydro, and nuclear plants increased $277 million, decreased $70 million, and increased $63 million in 2010, 2009, and 2008, respectively. Production expenses fluctuate from year to year due to variations in outage schedules and changes in the cost of labor and materials. Other production expenses increased in 2010 mainly due to a $178 million increase in outage and maintenance costs and an $86 million increase in commodity and labor costs, reflecting a return to more normal spending levels when compared to 2009. Also contributing to this increase was an $18 million increase in maintenance costs related to additional equipment placed in service. Partially offsetting the 2010 increase was a $5 million loss recognized in 2009 on the transfer of Southern Power’s Plant Desoto. Other production expenses decreased in 2009 mainly due to a $104 million decrease related to less planned spending on outages and maintenance, as well as other cost containment activities, which were the results of efforts to offset the effects of the recessionary economy. The 2009 decrease was partially offset by a $6 million increase related to new facilities, a $5 million loss on the transfer of Southern Power’s Plant Desoto in 2009, a $6 million gain recognized in 2008 by Southern Power on the sale of an undeveloped tract of land to the Orlando Utilities Commission (OUC), and a $17 million increase in nuclear refueling costs. Other production expenses increased in 2008 primarily due to a $64 million increase related to expenses incurred for maintenance outages at generating units and a $30 million increase related to labor and materials expenses, partially offset by a $15 million decrease in nuclear refueling costs. The 2008 increase was also partially offset by a $24 million decrease related to new facilities, mainly lower costs associated with the 2007 write-off of Southern Power’s integrated coal gasification combined cycle (IGCC) project with the OUC. See Note 1 to the financial statements under “Property, Plant, and Equipment” for additional information regarding nuclear refueling costs. Transmission and distribution expenses increased $143 million, decreased $41 million, and increased $4 million in 2010, 2009, and 2008, respectively. Transmission and distribution expenses fluctuate from year to year due to variations in maintenance schedules and normal changes in the cost of labor and materials. Transmission and distribution expenses increased in 2010 primarily due to increased spending on line clearing and other maintenance costs, reflecting a return to more normal spending levels, as well as an additional accrual to Alabama Power’s NDR. Transmission and distribution expenses decreased in 2009 primarily related to lower planned spending, as well as other cost containment activities, partially offset by an additional accrual to Alabama Power’s NDR. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Alabama Power – Natural Disaster Reserve” herein for additional information. The 2008 increase in transmission and distribution expenses was not material when compared to the prior year. Customer sales and service expenses increased $18 million, decreased $42 million, and increased $32 million in 2010, 2009, and 2008, respectively. Customer sales and service expenses increased in 2010 primarily as a result of an $8 million increase in sales expenses, a $13 million increase in customer service expense, a $10 million increase in records and collection, and a $3 million increase in uncollectible accounts expense. Partially offsetting this increase was a $7 million decrease in meter reading expenses and a $9 million decrease in other energy services. Customer sales and service expenses decreased in 2009 primarily as a result of a $12 II-16 SoCo FOIA Response 002373 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report million decrease in customer service expenses, an $8 million decrease in meter reading expenses, a $10 million decrease in sales expenses, and a $7 million decrease in customer records related expenses. The 2008 increase in customer sales and service expenses was primarily a result of an increase in customer service expenses, including a $13 million increase in uncollectible accounts expense, a $9 million increase in meter reading expenses, and an $8 million increase for customer records and collections. Administrative and general expenses increased $67 million, decreased $30 million, and increased $12 million in 2010, 2009, and 2008, respectively. Administrative and general expenses increased in 2010 primarily as a result of cost containment activities in 2009 which were taken to offset the effects of the recessionary economy. The 2008 increase in administrative and general expenses was not material when compared to 2007. Depreciation and Amortization Depreciation and amortization increased $19 million in 2010 primarily as the result of additional depreciation on plant in service related to environmental, transmission, and distribution projects, as well as additional depreciation at Southern Power. This increase was largely offset by a $133 million increase in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power– Retail Rate Plans” for additional information regarding Georgia Power’s cost of removal amortization. Depreciation and amortization increased $62 million in 2009 primarily as a result of an increase in plant in service related to environmental, transmission, and distribution projects mainly at Alabama Power and Georgia Power and the completion of Southern Power’s Plant Franklin Unit 3, as well as an increase in depreciation rates at Southern Power. Partially offsetting the 2009 increase was a decrease associated with the amortization of the regulatory liability related to the cost of removal obligations as authorized by the Georgia PSC. Depreciation and amortization increased $199 million in 2008 primarily as a result of an increase in plant in service related to environmental, transmission, and distribution projects mainly at Alabama Power and Georgia Power and generation projects at Georgia Power. An increase in depreciation rates at Georgia Power and Southern Power also contributed to the 2008 increase, as well as the expiration of a rate order previously allowing Georgia Power to levelize certain purchased power capacity costs and the completion of Southern Power’s Plant Oleander Unit 5 in December 2007 and Plant Franklin Unit 3 in June 2008. Taxes Other Than Income Taxes Taxes other than income taxes increased $51 million in 2010 primarily due to higher municipal franchise fees at Georgia Power as a result of increased retail revenues, increases in state and municipal public utility license tax bases at Alabama Power, increases in gross receipts and franchise fees at Gulf Power, increases in ad valorem taxes, and increases in payroll taxes. Taxes other than income taxes increased $22 million in 2009 primarily as a result of increases in the bases of state and municipal public utility license taxes at Alabama Power and an increase in franchise fees at Gulf Power. Increases in franchise fees are associated with increases in revenues from energy sales. Taxes other than income taxes increased $56 million in 2008 primarily as a result of increases in franchise fees and municipal gross receipt taxes associated with increases in revenues from energy sales, as well as increases in property taxes associated with property tax actualizations and additional plant in service. Other Income (Expense), Net Other income (expense), net decreased $41 million in 2010 primarily due to a decrease in allowance for funds used during construction (AFUDC) equity, mainly due to the completion of environmental projects at Alabama Power and Gulf Power, and a $13 million profit recognized in 2009 at Southern Power related to a construction contract with the OUC. The 2010 decrease was partially offset by increases in AFUDC equity related to the increase in construction of three new combined cycle units and two new nuclear generating units at Georgia Power. Other income (expense), net increased $53 million in 2009 primarily due to an increase in AFUDC equity as a result of environmental projects at Alabama Power and Gulf Power and additional investments in transmission and distribution projects at Alabama Power. In addition, during 2009, Southern Power recognized a $13 million profit under a construction contract with the OUC whereby Southern Power provided engineering, procurement, and construction services to build a combined cycle unit. Other income (expense), net increased $26 million in 2008 primarily as a result of an increase in AFUDC equity related to additional investments in environmental equipment at generating plants at Alabama Power, Georgia Power, and Gulf Power, as well as additional investments in transmission and distribution projects mainly at Alabama Power and Georgia Power. II-17 SoCo FOIA Response 002374 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report Interest Expense, Net of Amounts Capitalized Total interest charges and other financing costs decreased $2 million in 2010 primarily due to an $18 million decrease related to lower average interest rates on existing variable rate debt, an $11 million decrease in other interest costs, and a $2 million increase in capitalized interest as compared to 2009. The 2010 decrease was largely offset by a $29 million increase associated with $1.0 billion in additional debt outstanding at December 31, 2010 compared to December 31, 2009. Total interest charges and other financing costs increased by $61 million in 2009 primarily as a result of a $100 million increase associated with $1.4 billion in additional debt outstanding at December 31, 2009 compared to December 31, 2008. Also contributing to the 2009 increase was $16 million in other interest costs. The 2009 increase was partially offset by $42 million related to lower average interest rates on existing variable rate debt and $13 million of additional capitalized interest as compared to 2008. Total interest charges and other financing costs increased by $10 million in 2008 primarily as a result of a $65 million increase associated with $1.8 billion in additional debt outstanding at December 31, 2008 compared to December 31, 2007. Also contributing to the 2008 increase was $5 million in other interest costs. The 2008 increase was partially offset by $55 million related to lower average interest rates on existing variable rate debt and $7 million of additional capitalized interest as compared to 2007. Income Taxes Income taxes increased $128 million in 2010 primarily due to higher pre-tax earnings as compared to 2009, a decrease in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction, and an increase in Alabama state taxes due to a decrease in the state deduction for federal income taxes paid. Partially offsetting this increase were state tax credits at Georgia Power and tax benefits associated with the construction of a biomass facility at Southern Power. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. Income taxes decreased $49 million in 2009 primarily due to lower pre-tax earnings as compared to 2008, an increase in AFUDC equity, which is not taxable, and an increase in the federal production activities deduction. Income taxes increased $87 million in 2008 primarily due to higher pre-tax earnings as compared to 2007 and a 2007 deduction for a Georgia Power land donation. The 2008 increase was partially offset by an increase in AFUDC equity, which is not taxable. Dividends on Preferred and Preference Stock of Subsidiaries In both 2010 and 2009, dividends on preferred and preference stock of subsidiaries were flat compared to the applicable prior year. Dividends on preferred and preference stock of subsidiaries increased $17 million in 2008 primarily as a result of issuances of $320 million and $150 million of preference stock in the third and fourth quarters of 2007, respectively, partially offset by the redemption of $125 million of preferred stock in January 2008. Other Business Activities Southern Company’s other business activities include the parent company (which does not allocate operating expenses to business units), investments in leveraged lease projects, and telecommunications. These businesses are classified in general categories and may comprise one or more of the following subsidiaries: Southern Company Holdings invests in various projects, including leveraged lease projects; and SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. II-18 SoCo FOIA Response 002375 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report A condensed statement of income for Southern Company’s other business activities follows: Amount 2010 Increase (Decrease) from Prior Year 2009 2008 2010 (in millions) Operating revenues Other operations and maintenance MC Asset Recovery litigation settlement Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income (loss) Equity in income (losses) of unconsolidated subsidiaries Leveraged lease income (losses) Other income (expense), net Interest expense Income taxes Net income (loss) $ $ 82 103 19 2 124 (42) $ (19) (22) (202) (8) (232) 213 (2) 18 (16) 62 (90) (14) (1) (22) (19) (8) 1 $ 178 $ $ (26) (40) 202 (2) (1) 159 (185) $ (86) (44) (1) (45) (41) (11) 125 (8) (22) 30 (87) 35 (125) (31) (30) (7) $ (125) Operating Revenues Southern Company’s non-electric operating revenues from these other businesses decreased $19 million in 2010 primarily as a result of a decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry. The $26 million decrease in 2009 primarily resulted from a $25 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry. The $86 million decrease in 2008 primarily resulted from a $60 million decrease associated with Southern Company terminating its investment in synthetic fuel projects at December 31, 2007 and a $21 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry. Also contributing to the 2008 decrease was a $5 million decrease in revenues from Southern Company’s energy-related services business. Other Operations and Maintenance Expenses Other operations and maintenance expenses for these other businesses decreased $22 million in 2010 primarily as a result of lower administrative and general expenses for these other businesses. Other operations and maintenance expenses decreased $40 million in 2009 primarily as a result of a $15 million decrease in salary and wages, advertising, equipment, and network costs at SouthernLINC Wireless; a $10 million decrease in expenses associated with leveraged lease litigation costs; and a $6 million decrease in parent company expenses associated with the MC Asset Recovery litigation. Other operations and maintenance expenses decreased $44 million in 2008 primarily as a result of $11 million of lower coal expenses related to Southern Company terminating its investment in synthetic fuel projects at December 31, 2007; $9 million of lower sales expenses at SouthernLINC Wireless related to lower sales volume; and $5 million of lower parent company expenses related to advertising, litigation, and property insurance costs. MC Asset Recovery Litigation Settlement In March 2009, Southern Company entered into a litigation settlement agreement with MC Asset Recovery which resulted in a charge of $202 million and required MC Asset Recovery to release Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in connection with Mirant’s plan of reorganization, as well as to release all actions against current or former officers and directors of Mirant and Southern Company that had or could have been filed. Pursuant to the settlement, Southern Company recorded a charge in the first quarter 2009 of $202 million, which was paid in the second quarter 2009. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. In June 2009, the case was dismissed with prejudice. Equity in Income (Losses) of Unconsolidated Subsidiaries Equity in income (losses) of unconsolidated subsidiaries for 2010 was flat when compared to the prior year. Equity in income (losses) of unconsolidated subsidiaries decreased $11 million in 2009 as a result of an $11 million gain recognized in 2008 related to the II-19 SoCo FOIA Response 002376 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report dissolution of a partnership that was associated with synthetic fuel production facilities. Equity in income (losses) of unconsolidated subsidiaries increased $35 million in 2008 primarily as a result of Southern Company terminating its investment in synthetic fuel projects at December 31, 2007. Leveraged Lease Income (Losses) Southern Company has several leveraged lease agreements which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Leveraged lease income (losses) decreased $22 million in 2010 primarily as a result of a $26 million gain recorded in 2009 associated with the early termination of two international leveraged lease investments, the proceeds from which were required to extinguish all debt related to the leveraged lease investments, and a portion of which had make-whole redemption provisions. This resulted in a $17 million loss in 2009, partially offsetting the gain. In addition, leveraged lease income decreased $6 million in 2010 primarily due to lease income no longer being recognized on the terminated leveraged lease investments. Leveraged lease income (losses) increased $125 million in 2009 primarily as a result of the application in 2008 of certain accounting standards related to leveraged leases, as well as a $26 million gain recorded in the second quarter 2009 associated with the early termination of two international leveraged lease investments. The proceeds from the termination were required to be used to extinguish all debt related to leveraged lease investments, a portion of which had make-whole redemption provisions. This resulted in a $17 million loss and partially offset the 2009 increase. Leveraged lease income (losses) decreased $125 million in 2008 as a result of Southern Company’s decision to participate in a settlement with the Internal Revenue Service (IRS) related to deductions for several sale-in-lease-out transactions and the resulting application of certain accounting standards related to leveraged leases. Other Income (Expense), Net Other income (expense), net for these other businesses decreased $19 million in 2010 primarily due to charitable contributions made by the parent company. The 2009 change in other income (expense), net when compared to the prior year was not material. Other income (expense), net decreased $31 million in 2008 primarily as a result of the 2007 gain on a derivative transaction in the synthetic fuel business which settled on December 31, 2007. Interest Expense Total interest charges and other financing costs for these other businesses decreased $8 million in 2010 primarily due to lower average interest rates on existing variable rate debt. Total interest charges and other financing costs decreased $22 million in 2009 primarily as a result of $26 million associated with lower average interest rates on existing variable rate debt and a $2 million decrease attributed to other interest charges. The 2009 decrease was partially offset by a $4 million increase associated with $63 million in additional debt outstanding at December 31, 2009 compared to December 31, 2008. Total interest charges and other financing costs decreased $30 million in 2008 primarily as a result of $29 million associated with lower average interest rates on existing variable rate debt and a $4 million decrease attributed to lower interest rates associated with new debt issued to replace maturing securities. At December 31, 2008, these other businesses had $92 million in additional debt outstanding compared to December 31, 2007. The 2008 decrease was partially offset by a $5 million increase in other interest costs. Income Taxes The 2010 increase in income taxes for these other businesses was not material when compared to the prior year. Income taxes increased $30 million in 2009 excluding the effects of the $202 million charge resulting from the litigation settlement with MC Asset Recovery in the first quarter 2009. The 2009 increase was primarily due to the application in 2008 of certain accounting standards related to leveraged leases and income taxes. Partially offsetting this increase was lower tax expense associated with the early termination of two international leveraged lease investments and the extinguishment of the associated debt discussed previously under “Leveraged Lease Income (Losses).” Income taxes decreased $7 million in 2008 primarily as a result of leveraged lease losses discussed previously under “Leveraged Lease Income (Losses),” partially offset by a $36 million decrease in net synthetic fuel tax credits as a result of Southern Company terminating its investment in synthetic fuel projects at December 31, 2007. See Note 5 to the financial statements under “Effective Tax Rate” for further information. Effects of Inflation The traditional operating companies are subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing II-20 SoCo FOIA Response 002377 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report power. Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on Southern Company’s results of operations has not been substantial in recent years. FUTURE EARNINGS POTENTIAL General The four traditional operating companies operate as vertically integrated utilities providing electricity to customers within their service areas in the Southeastern U.S. Prices for electricity provided to retail customers are set by state PSCs under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the Federal Energy Regulatory Commission (FERC). Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Power continues to focus on long-term capacity contracts, optimized by limited energy trading activities. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about regulatory matters. The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Other major factors include profitability of the competitive wholesale supply business and federal regulatory policy. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in economic conditions impact sales for the traditional operating companies and Southern Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. In 2010, Southern Company system generating capacity increased 30 megawatts due to the completion of a solar photovoltaic plant near Cimarron, New Mexico. In general, Southern Company has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities or to meet requirements of Southern Company’s regulated retail markets, both of which are optimized by limited energy trading activities. See FUTURE EARNINGS POTENTIAL – “Construction Program” herein and Note 7 to the financial statements for additional information. As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information. New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities II-21 SoCo FOIA Response 002378 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against Alabama Power is ongoing. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. Southern Company believes that the traditional operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth II-22 SoCo FOIA Response 002379 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Statutes and Regulations General The electric utilities’ operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2010, the electric utilities had invested approximately $8.1 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of $500 million, $1.3 billion, and $1.6 billion for 2010, 2009, and 2008, respectively. The Company expects that capital expenditures to comply with existing statutes and regulations will be $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. These environmental costs that are known and estimable at this time are included under the heading “Capital” in the table under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million in 2011, $191 million to $670 million in 2012, and $476 million to $1.9 billion in 2013. The Company’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of any new or revised environmental statutes and regulations that are enacted, including the proposed environmental legislation and regulations described below; the cost, availability, and existing inventory of emissions allowances; and the fuel mix of the electric utilities. Compliance with any new federal or state legislation or regulations relating to global climate change, air quality, coal combustion byproducts, including coal ash, water quality, or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the electric utilities’ operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the electric utilities’ commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for Southern Company. Through 2010, the electric utilities had spent approximately $7 billion in reducing sulfur dioxide (SO 2 ) and nitrogen oxide (NO x ) emissions and in monitoring emissions pursuant to the Clean Air Act. As a result, emissions control projects have been completed recently or are underway. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements. The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone air quality standard. A 20county area within metropolitan Atlanta is the only location within Southern Company’s service area that is currently designated as II-23 SoCo FOIA Response 002380 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report nonattainment for the current standard. On November 30, 2010, the EPA extended the attainment date for this area by one year as a result of improving air quality. In March 2008, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the level of the standard. Under the EPA’s current schedule, a final revision to the eight-hour ozone standard is expected in July 2011, with state implementation plans for any resulting nonattainment areas due in mid-2014. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within Southern Company’s service territory, and could result in additional required reductions in NO x emissions. During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within Southern Company’s service area in Alabama and Georgia. State implementation plans demonstrating attainment with the annual standard for all areas have been submitted to the EPA. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. In October 2009, the EPA designated the Birmingham area as nonattainment for the 24-hour standard. In April 2010, the State of Alabama requested that the EPA re-designate Birmingham to attainment for the 24-hour standard based on current air quality data. In September 2010, the EPA determined that Birmingham has air quality data that meets the 24-hour standard. The EPA is expected to propose new annual and 24-hour fine particulate matter standards during the summer of 2011. Final revisions to the National Ambient Air Quality Standard for SO 2 , including the establishment of a new one-hour standard, became effective on August 23, 2010. Since the EPA intends to rely on computer modeling for implementation of the SO 2 standard, the identification of potential nonattainment areas remains uncertain and could ultimately include areas within the Company’s service territory. Implementation of the revised SO 2 standard could result in additional required reductions in SO 2 emissions and increased compliance and operation costs. Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO 2 ), which established a new one-hour standard, became effective on April 12, 2010. Although none of the areas within Southern Company’s service territory are expected to be designated as nonattainment for the NO 2 standard, based on current ambient air quality monitoring data, the new NO 2 standard could result in significant additional compliance and operational costs for units that require new source permitting. Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO x and/or SO 2 to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. States in the Southern Company service territory have completed plans to implement CAIR, and emissions reductions are being accomplished by the installation and operation of emissions controls at coal-fired facilities of the electric utilities and/or by the purchase of emissions allowances. On August 2, 2010, the EPA published a proposed rule, referred to as the Transport Rule, to replace CAIR. This proposed rule would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO 2 and NO x that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, Florida, and Georgia, to reduce annual emissions of SO 2 and NO x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including each of the states in Southern Company’s service territory, to achieve additional reductions in NO x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requested comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA stated that it also intends to develop a second phase of the Transport Rule in 2011 to address the more stringent ozone air quality standards after they are finalized. The EPA expects to finalize the Transport Rule in June 2011 and require compliance beginning in 2012. The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO 2 and NO x , and no additional controls beyond CAIR are anticipated to be necessary at any of the traditional operating companies’ facilities. States have completed or are currently completing implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress. II-24 SoCo FOIA Response 002381 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal- and oil-fired electric generating units which will establish emission limitations for numerous hazardous air pollutants, including mercury. As part of a proceeding in the U.S. District Court for the District of Columbia, the EPA has entered into a consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011. On April 29, 2010, the EPA issued a proposed Industrial Boiler (IB) MACT rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA issued the final rules on February 23, 2011 and, at the same time, issued a notice of intent to reconsider the final rules to allow for additional public review and comment. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time. The impacts of the eight-hour ozone, fine particulate matter, SO 2 and NO 2 standards, the proposed Transport Rule, the Clean Air Visibility Rule, and the proposed MACT rules for electric generating units and industrial boilers on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any pending and future legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company has already installed a number of SO 2 and NO x emissions controls to ensure continued compliance with applicable air quality requirements. In addition to the federal air quality laws described above, Georgia Power also is subject to the requirements of the State of Georgia’s Multi-Pollutant Rule, which was adopted in 2007. The Multi-Pollutant Rule is designed to reduce emissions of mercury, SO 2 , and NO x state-wide by requiring the installation of specified control technologies at certain coal-fired generating units by specific dates between December 31, 2008 and June 1, 2015. The State of Georgia also adopted a companion rule that requires a 95% reduction in SO 2 emissions from the controlled units on the same or similar timetable. Through December 31, 2010, Georgia Power had installed the required controls on 10 of its largest coal-fired generating units and is in the process of installing the required controls on six additional units. As a result of uncertainties related to the potential federal air quality regulations described above, Georgia Power has suspended certain work related to both the installation of emissions control equipment at Plant Branch Units 1 and 2 and Plant Yates Units 6 and 7 and the conversion of Plant Mitchell from coal-fired to biomass-fired. Georgia Power continues to analyze the potential costs and benefits of installing the required controls on its remaining coal-fired generating units in light of the potential federal regulations described above. Georgia Power may determine that retiring and replacing certain of these existing units with new generating resources or purchased power is more economically efficient than installing the required environmental controls. Georgia Power currently expects to file an update to its integrated resource plan in June 2011. Under the terms of an Alternate Rate Plan approved by the Georgia PSC for Georgia Power which became effective January 1, 2011 and will continue through December 31, 2013 (the 2010 ARP), any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets (resulting from new or revised environmental regulations) through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Such costs that may be deferred as a regulatory asset include any impairment losses that may result from a decision to retire certain units that are no longer cost effective in light of new or modified environmental regulations. In addition, in connection with the 2010 ARP, the Georgia PSC also approved revised depreciation rates that will recover the remaining book value of certain of Georgia Power’s existing coal-fired units by December 31, 2014. The ultimate outcome of these matters cannot be determined at this time. Water Quality In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. In April 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is expected to propose revisions to the regulations in March 2011 and issue final regulations in mid-2012. While the U.S. Supreme Court’s decision II-25 SoCo FOIA Response 002382 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on the specific provisions of the EPA’s final rule and on the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time. However, if the final rules require the installation of cooling towers at certain existing facilities of the traditional operating companies, the traditional operating companies may be subject to significant additional compliance costs and capital expenditures that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. In December 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted, and the EPA has announced its intention to adopt such revisions by January 2014. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Southern Company system facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, and, therefore, cannot be determined at this time. Environmental Remediation Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the traditional operating companies could incur substantial costs to clean up properties. The traditional operating companies conduct studies to determine the extent of any required cleanup and have recognized in their respective financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional operating companies may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” for additional information. Coal Combustion Byproducts The traditional operating companies currently operate 22 electric generating plants with on-site coal combustion byproduct storage facilities (some with both “wet” (ash ponds) and “dry” (landfill) storage facilities). In addition to on-site storage, the traditional operating companies also sell a portion of their coal combustion byproducts to third parties for beneficial reuse (approximately onefourth in recent years). Historically, individual states have regulated coal combustion byproducts and the states in Southern Company’s service territory each have their own regulatory parameters. Each traditional operating company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments and compliance with applicable regulations. The EPA is currently evaluating whether additional regulation of coal combustion byproducts (including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June 21, 2010, the EPA published a proposed rule that requested comments on two potential regulatory options for the management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of, or significant change to, existing storage facilities and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. On November 19, 2010, Southern Company filed publicly available comments with the EPA regarding the rulemaking proposal. These comments included a preliminary cost analysis under various alternatives in the rulemaking proposal. Southern Company regards these estimates as pre-screening figures that should be distinguished from the more formalized cost estimates Southern Company provides for projects that are more definite as to the elements and timing of execution. Although its analysis was preliminary, Southern Company concluded that potential compliance costs under the proposed rules would be substantially higher than the estimates reflected in the EPA’s rulemaking proposal. The ultimate financial and operational impact of any new regulations relating to coal combustion byproducts cannot be determined at this time and will be dependent upon numerous factors. These factors include: whether coal combustion byproducts will be regulated as hazardous waste or non-hazardous waste; whether the EPA will require early closure of existing wet storage facilities; whether beneficial reuse will be limited or eliminated through a hazardous waste designation; whether the construction of lined landfills is required; whether hazardous waste landfill permitting will be required for on-site storage; whether additional waste water treatment will be required; the extent of any additional groundwater monitoring requirements; whether any equipment modifications will be required; the extent of any changes to site safety practices under a hazardous waste designation; and the time period over which compliance will be required. There can be no assurance as to the timing of adoption or the ultimate form of any such rules. II-26 SoCo FOIA Response 002383 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report While the ultimate outcome of this matter cannot be determined at this time, and will depend on the final form of any rules adopted and the outcome of any legal challenges, additional regulation of coal combustion byproducts could have a material impact on the generation, management, beneficial use, and disposal of such byproducts. Any material changes are likely to result in substantial additional compliance, operational, and capital costs that could affect future unit retirement and replacement decisions. Moreover, the traditional operating companies could incur additional material asset retirement obligations with respect to closing existing storage facilities. Southern Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. Global Climate Issues Although the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas emissions, neither this legislation nor similar measures passed the U.S. Senate before the end of the 2010 session. Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are expected to continue to be considered in Congress. The financial and operational impacts of climate or energy legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal, natural gas, and biomass prices and cost recovery through regulated rates. While climate legislation has yet to be adopted, the EPA is moving forward with regulation of greenhouse gases under the Clean Air Act. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. In December 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, which began on January 2, 2011, applies to sources and projects that would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed settlement agreement to issue standards of performance for greenhouse gas emissions from new and modified fossil fuel-fired electric generating units and greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012. All of the EPA’s final Clean Air Act rulemakings have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit; however, the court declined motions to stay the rules pending resolution of those challenges. As a result, the rules may impact the amount of time it takes to obtain PSD permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate outcome of these rules cannot be determined at this time and will depend on the content of the final rules and the outcome of any legal challenges. International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The most recent round of negotiations took place in December 2010. The outcome and impact of the international negotiations cannot be determined at this time. Although the outcome of federal, state, and international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect II-27 SoCo FOIA Response 002384 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. See Item 1 – BUSINESS – “Rate Matters – Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. In 2009, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the electric utilities were approximately 121 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2010 is approximately 131 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The Company is actively evaluating and developing electric generating technologies with lower greenhouse gas emissions. These include, but are not limited to, new nuclear generation, including two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4) in Georgia; construction of the Kemper IGCC in Mississippi with 65% carbon capture; and renewables investments, including the construction of a biomass plant in Sacul, Texas. In addition, a subsidiary of the Company completed construction on a solar photovoltaic plant near Cimarron, New Mexico in 2010. The Company is currently considering additional projects and is pursuing research into the costs and viability of other renewable technologies. PSC Matters Alabama Power Rate RSE Alabama Power operates under Rate RSE approved by the Alabama PSC. Alabama Power’s Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. Retail rates remain unchanged when the retail return on common equity (ROE) is projected to be between 13.0% and 14.5%. If Alabama Power’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail ROE fall below the allowed equity return range. The Rate RSE increase for 2010 was 3.24%, or $152 million annually, and was effective in January 2010. In December 2010, Alabama Power made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2011 and earnings were within the specified return range. Consequently, the retail rates will remain unchanged in 2011 under Rate RSE. Under the terms of Rate RSE, the maximum increase for 2012 cannot exceed 5.00%. Rate CNP Alabama Power’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under a Rate CNP. There was no adjustment to the Rate CNP to recover certificated PPA costs in 2008 or 2009. Effective April 2010, Rate CNP was reduced by approximately $70 million annually, primarily due to the expiration on May 31, 2010 of the PPA with Southern Power covering the capacity of Plant Harris Unit 1. It is estimated that there will be a slight decrease to the current Rate CNP effective April 2011. Rate CNP also allows for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Retail rates increased approximately 2.4% in January 2008 and 4.3% in January 2010 due to environmental costs. In October 2008, Alabama Power agreed to defer collection of any increase in rates under this portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations, from 2009 until 2010. The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no significant effect on the Company’s revenues or net income. On December 1, 2010, Alabama Power submitted calculations associated with its cost of complying with environmental mandates, as provided under Rate CNP Environmental. The filing reflects an incremental increase in the revenue requirement associated with such environmental compliance, which would be recoverable in the billing months of January 2011 through December 2011. In order to afford additional rate stability to customers as the economy continues to recover from the recession, the Alabama PSC ordered on January 4, 2011 that Alabama Power leave in effect for 2011 the factors associated with Alabama Power’s II-28 SoCo FOIA Response 002385 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report environmental compliance costs for the year 2010. Any recoverable amounts associated with 2011 will be reflected in the 2012 filing. The ultimate outcome of this matter cannot be determined at this time. Natural Disaster Reserve Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Natural Disaster Rate (Rate NDR) charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Alabama Power has discretionary authority to accrue certain additional amounts as circumstances warrant. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the reserve. For the year ended December 31, 2010, Alabama Power accrued an additional $48 million to the NDR, resulting in an accumulated balance of approximately $127 million. For the year ended December 31, 2009, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $75 million. These accruals are included in the balance sheets under other regulatory liabilities, deferred and are reflected as operations and maintenance expense in the statements of income. Nuclear Outage Accounting Order On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Previously, Alabama Power accrued nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period. The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012, these deferred costs will be amortized to nuclear operations and maintenance expenses over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012, these deferred costs will be amortized to nuclear operations and maintenance expenses over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period. Georgia Power The economic recession significantly reduced Georgia Power’s revenues upon which retail rates were set by the Georgia PSC for 2008 through 2010 (2007 Retail Rate Plan). In June 2009, despite stringent efforts to reduce expenses, Georgia Power’s projected retail ROE for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, in June 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. In August 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, Georgia Power could amortize up to $108 million of the regulatory liability in 2009 and up to $216 million in 2010, limited to the amount needed to earn no II-29 SoCo FOIA Response 002386 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report more than a 9.75% and 10.15% retail ROE in 2009 and 2010, respectively. For the years ended December 31, 2009 and 2010, Georgia Power amortized $41 million and $174 million of the regulatory liability, respectively. On December 21, 2010, the Georgia PSC approved the 2010 ARP. The terms of the 2010 ARP reflect a settlement agreement among Georgia Power, the Georgia PSC’s Public Interest Advocacy Staff, and eight other intervenors. Under the terms of the 2010 ARP, Georgia Power will amortize approximately $92 million of its remaining regulatory liability related to other cost of removal obligations over the three years ending December 31, 2013. Also under the terms of the 2010 ARP, effective January 1, 2011, Georgia Power increased its (1) traditional base tariff rates by approximately $347 million; (2) Demand-Side Management (DSM) tariff rates by approximately $31 million; (3) ECCR tariff rate by approximately $168 million; and (4) Municipal Franchise Fee (MFF) tariff rate by approximately $16 million, for a total increase in base revenues of approximately $562 million. Under the 2010 ARP, the following additional base rate adjustments will be made to Georgia Power’s tariffs in 2012 and 2013:  Effective January 1, 2012, the DSM tariffs will increase by $17 million;  Effective April 1, 2012, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Units 4 and 5 for the period from commercial operation through December 31, 2013;  Effective January 1, 2013, the DSM tariffs will increase by $18 million;  Effective January 1, 2013, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Unit 6 for the period from commercial operation through December 31, 2013; and  The MFF tariff will increase consistent with these adjustments. Georgia Power currently estimates these adjustments will result in annualized base revenue increases of approximately $190 million in 2012 and $93 million in 2013. Under the 2010 ARP, Georgia Power’s retail ROE is set at 11.15% and earnings will be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. If at any time during the term of the 2010 ARP, Georgia Power projects that retail earnings will be below 10.25% for any calendar year, it may petition the Georgia PSC for the implementation of an Interim Cost Recovery (ICR) tariff to adjust Georgia Power’s earnings back to a 10.25% retail ROE. The Georgia PSC will have 90 days to rule on any such request. If approved, any ICR tariff would expire at the earlier of January 1, 2014 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR, Georgia Power may file a full rate case. Except as provided above, Georgia Power will not file for a general base rate increase while the 2010 ARP is in effect. Georgia Power is required to file a general rate case by July 1, 2013, in response to which the Georgia PSC would be expected to determine whether the 2010 ARP should be continued, modified, or discontinued. Fuel Cost Recovery The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In previous years, the traditional operating companies experienced higher than expected fuel costs for coal, natural gas, and uranium. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Alabama Power, Georgia Power, and Gulf Power of approximately $420 million at December 31, 2010. As of December 31, 2010, Mississippi Power had a total over recovered fuel balance of $55 million. At December 31, 2009, total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power were approximately $667 million and Alabama Power and Mississippi Power had a total over recovered fuel balance of approximately $229 million. The traditional operating companies continuously monitor the under or over recovered fuel cost balances. II-30 SoCo FOIA Response 002387 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Retail Regulatory Matters – Alabama Power – Fuel Cost Recovery” and “Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery” for additional information. Legislation Stimulus Funding On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S. Department of Energy (DOE), formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding, to be matched by Southern Company, will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. The ultimate outcome of this matter cannot be determined at this time. Healthcare Reform On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Southern Company and the traditional operating companies have been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Southern Company. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and related employee benefit plan costs. Any future impact on the financial statements of Southern Company cannot be determined at this time. See Note 5 to the financial statements under “Current and Deferred Income Taxes” for additional information. Income Tax Matters Georgia State Income Tax Credits Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia DOR has appealed to the Georgia Court of Appeals and a decision is expected later this year. Any decision may be subject to further appeal to the Georgia Supreme Court. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers in accordance with the 2010 ARP. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s cash flow. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot now be determined. Tax Method of Accounting for Repairs Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. On a consolidated basis, the new tax method resulted in net positive cash flow in 2010 of approximately $297 million. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing II-31 SoCo FOIA Response 002388 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. Bonus Depreciation On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which could have a significant impact on the future cash flows of Southern Company. The application of the bonus depreciation provisions in these acts in 2010 provided approximately $393 million in increased cash flow. Southern Company estimates the potential increased cash flow for 2011 to be between approximately $500 million and $600 million. Internal Revenue Code Section 199 Domestic Production Deduction The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to Southern Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions, there was no domestic production deduction available to Southern Company for 2010, and none is projected to be available for 2011. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. Construction Program The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including natural gas and biomass units at Southern Power, natural gas and new nuclear units at Georgia Power, and the Kemper IGCC at Mississippi Power, as well as adding environmental control equipment and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the financial statements under “Construction Program” for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction,” “Retail Regulatory Matters – Georgia Power – Other Construction,” and “Retail Regulatory Matters – Mississippi Power Integrated Coal Gasification Combined Cycle” for additional information. On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost Recovery (NCCR) tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act. The Georgia PSC has ordered Georgia Power to report against the total certified cost of Plant Vogtle Units 3 and 4 of approximately $6.1 billion. In addition, on December 21, 2010, the Georgia PSC approved Georgia Power’s NCCR tariff. The NCCR tariff became effective January 1, 2011 and is expected to collect approximately $223 million during 2011 to recover financing costs associated with the construction of Plant Vogtle Units 3 and 4. Other Matters Southern Company and its subsidiaries are involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, II-32 SoCo FOIA Response 002389 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements. See Note 3 to the financial statements for information regarding material issues. ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors. Electric Utility Regulation Southern Company’s traditional operating companies, which comprised approximately 95% of Southern Company’s total operating revenues for 2010, are subject to retail regulation by their respective state PSCs and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional operating companies are permitted to charge customers based on allowable costs. As a result, the traditional operating companies apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional operating companies; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company. As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements. Contingent Obligations Southern Company and its subsidiaries are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject them to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company’s financial statements. II-33 SoCo FOIA Response 002390 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report These events or conditions include the following: • Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters. • Changes in existing income tax regulations or changes in IRS or state revenue department interpretations of existing regulations. • Identification of additional sites that require environmental remediation or the filing of other complaints in which Southern Company or its subsidiaries may be asserted to be a potentially responsible party. • Identification and evaluation of other potential lawsuits or complaints in which Southern Company or its subsidiaries may be named as a defendant. • Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA. Unbilled Revenues Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations. Alabama Power is better able to determine unbilled KWH sales due to the installation of automated meters. At the end of each month, amounts of electricity delivered are read for the customers with automated meters. From this reading, unbilled KWH sales are determined and included in Alabama Power’s unbilled revenue calculation. For customers without automated meter readings, amounts of unbilled electricity delivered are estimated. Pension and Other Postretirement Benefits Southern Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. Key elements in determining Southern Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on Southern Company’s investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company’s target asset allocation. Southern Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. II-34 SoCo FOIA Response 002391 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report The following table illustrates the sensitivity to changes in Southern Company’s long-term assumptions with respect to the expected long-term rate of return on plan assets and the assumed discount rate: Change in Assumption Increase/(Decrease) in Total Benefit Expense for 2011 Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, 2010 Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 2010 (in millions) 25 basis point change in discount rate 25 basis point change in salary assumption 25 basis point change in long-term return on plan assets $25/$(17) $249/$(236) $52/$(50) $13/$(12) $63/$(60) N/M $20/$(20) N/M N/M N/M – Not meaningful FINANCIAL CONDITION AND LIQUIDITY Overview Southern Company’s financial condition remained stable at December 31, 2010. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information. Southern Company’s investments in the qualified pension plan and the nuclear decommissioning trust funds remained stable in value as of December 31, 2010. In December 2010, the traditional operating companies and certain other subsidiaries contributed $620 million to the qualified pension plan. Southern Company does not expect any material changes to funding obligations to the nuclear decommissioning trust funds prior to 2014. Net cash provided from operating activities in 2010 totaled $4 billion, an increase of $728 million from the corresponding period in 2009. Significant changes in operating cash flow for 2010 as compared to the corresponding period in 2009 include an increase in net income, a reduction in fossil fuel stock, and an increase in deferred income taxes primarily due to the change in the tax accounting method for repair costs. A contribution to the qualified pension plan partially offset these increases. Net cash provided from operating activities in 2009 totaled $3.3 billion, a decrease of $201 million from the corresponding period in 2008. Significant changes in operating cash flow for 2009 as compared to the corresponding period in 2008 include a reduction to net income, increased levels of coal inventory, and increased cash outflows for tax payments. These uses of funds were partially offset by increased cash inflows as a result of higher fuel cost recovery rates included in customer billings. Net cash provided from operating activities in 2008 totaled $3.5 billion, an increase of $30 million as compared to 2007. Significant changes in operating cash flow for 2008 included a $264 million increase in the use of funds for fossil fuel inventory as compared to the corresponding period in 2007. This use of funds was offset by an increase in cash of $312 million in accrued taxes primarily due to a difference between the periods in payments for federal taxes and property taxes. Net cash used for investing activities in 2010 totaled $4.3 billion primarily due to property additions to utility plant. Net cash used for investing activities in 2009 totaled $4.3 billion primarily due to property additions to utility plant of $4.7 billion, partially offset by approximately $340 million in cash received from the early termination of two leveraged lease investments. Net cash used for investing activities in 2008 totaled $4.1 billion primarily due to property additions to utility plant of $4.0 billion. Net cash provided from financing activities totaled $22 million in 2010, a decrease of $1.3 billion from the corresponding period in 2009. This decrease was primarily due to redemptions of long-term debt in 2010. Net cash provided from financing activities totaled $1.3 billion in 2009 primarily due to the issuances of new long-term debt and common stock, partially offset by cash outflows for repayments of long-term debt and dividend payments. Net cash provided from financing activities totaled $878 million in 2008 primarily due to long-term debt issuances. Significant balance sheet changes in 2010 include an increase of $2.8 billion in total property, plant, and equipment for the installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other II-35 SoCo FOIA Response 002392 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report significant changes include an increase in notes payable of $658 million used primarily for construction expenditures and general corporate purposes and $1.3 billion of additional equity. At the end of 2010, the closing price of Southern Company’s common stock was $38.23 per share, compared with book value of $19.21 per share. The market-to-book value ratio was 199% at the end of 2010, compared with 184% at year-end 2009. Sources of Capital Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of the Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2011, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. Except as described below with respect to potential DOE loan guarantees, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. On June 18, 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs, or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined construction and operating license for Plant Vogtle Units 3 and 4 from the Nuclear Regulatory Commission (NRC), negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE but has yet to begin discussions with the DOE regarding the terms and conditions of any loan guarantee. There can be no assurance that the DOE will issue federal loan guarantees for Mississippi Power. The issuance of securities by the traditional operating companies is generally subject to the approval of the applicable state PSC. The issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts, if any, registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. Southern Company, each traditional operating company, and Southern Power obtain financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company. Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities). At December 31, 2010, Southern Company and its subsidiaries had approximately $447.4 million of cash and cash equivalents and $4.8 billion of unused credit arrangements with banks, of which $1.6 billion expire in 2011 and $3.2 billion expire in 2012. Approximately $81 million of the credit facilities expiring in 2011 allow for the execution of term loans for an additional two-year period, and $927 million allow for the execution of one-year term loans. Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants. A portion of the unused credit with banks is II-36 SoCo FOIA Response 002393 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2010 was approximately $1.3 billion. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The traditional operating companies may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of each of the traditional operating companies. At December 31, 2010, the Southern Company system had approximately $1.3 billion of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During 2010, Southern Company had an average of $690 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $1.3 billion. At December 31, 2009, the Southern Company system had approximately $638 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During 2009, Southern Company had an average of $956 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding for commercial paper was $1.4 billion. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash. Financing Activities During 2010, Southern Company issued $400 million aggregate principal amount of Series 2010A 2.375% Senior Notes due September 15, 2015. The net proceeds were used to redeem $250 million aggregate principal amount of Southern Company Capital Funding, Inc.’s Series C 5.75% Senior Notes due November 15, 2015. In addition, certain Southern Company subsidiaries issued $2.8 billion of senior notes and other long-term debt and entered into bank term loan agreements of $125 million. The proceeds were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes, including the applicable subsidiary’s continuous construction program. Southern Company also issued 19.6 million shares of common stock for $629 million through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued 4.1 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $143 million, net of $1 million in fees and commissions. The proceeds from the sale of the common stock were used by the Company for general corporate purposes, including the investment by the Company in its subsidiaries, and to repay a portion of its outstanding short-term indebtedness. In December 2010, Mississippi Power incurred obligations in connection with the issuance of $100 million of revenue bonds in two series, each of which is due December 1, 2040. The first series of $50 million was issued with an initial fixed rate of 2.25% through January 14, 2013 and the second series of $50 million was issued with a floating rate. The proceeds from the first series bonds were used to finance the acquisition and construction of buildings and immovable equipment in connection with Mississippi Power’s construction of the Kemper IGCC. Proceeds from the second series bonds were classified as restricted cash at December 31, 2010 and these bonds were redeemed on February 8, 2011. Subsequent to December 31, 2010, Alabama Power entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million. Also subsequent to December 31, 2010, Georgia Power issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay a portion of Georgia Power’s outstanding short-term indebtedness and for general corporate purposes, including Georgia Power’s continuous construction program. In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Off-Balance Sheet Financing Arrangements In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership whose investors are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease also provides for a residual value guarantee, approximately 73% of the acquisition cost, by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the assets. In April 2010, Mississippi Power was required to notify the lessor, Juniper, if it intended to terminate the lease at the end II-37 SoCo FOIA Response 002394 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the Plant Daniel combined cycle generating units for approximately $354 million or renew the lease for approximately $31 million annually for 10 years. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be determined at this time. See Note 7 to the financial statements under “Operating Leases” for additional information. Credit Rating Risk Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At December 31, 2010, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $489 million. At December 31, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.5 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market. On August 12, 2010, Moody’s Investors Service (Moody’s) downgraded the issuer and long-term debt ratings of Southern Company (senior unsecured to Baa1 from A3); Moody’s also announced that it had downgraded the short-term ratings of Southern Company and a financing subsidiary of Southern Company that issues commercial paper for the benefit of several Southern Company subsidiaries (including Georgia Power, Gulf Power, and Mississippi Power) to P-2 from P-1. In addition, Moody’s downgraded the issuer and long-term debt ratings of Georgia Power (senior unsecured to A3 from A2), Gulf Power (senior unsecured to A3 from A2), and Mississippi Power (senior unsecured to A2 from A1). All of these companies have stable ratings outlooks from Moody’s. On September 3, 2010, Fitch Ratings, Inc. (Fitch) confirmed the long-term debt ratings of Southern Company (senior unsecured A), but announced that the ratings outlook of Southern Company had been revised to negative, and that the issuer default ratings and longterm debt ratings of Mississippi Power had been downgraded by one notch (senior unsecured to A+ from AA- and issuer default rating to A from A+). On December 22, 2010, Fitch announced that the ratings outlook of Southern Company and Georgia Power had been revised from negative to stable. Market Price Risk Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. The Company may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives outstanding at December 31, 2010 have a notional amount of $650 million and are related to fixed and floating rate obligations over the next several years. The weighted average interest rate on $2.5 billion of longterm variable interest rate exposure that has not been hedged at January 1, 2011 was 0.75%. If Southern Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $25 million at January 1, 2011. For further information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements. Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts II-38 SoCo FOIA Response 002395 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the years ended December 31 were as follows: 2009 2010 Changes Changes Fair Value (in millions) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes(a) Contracts outstanding at the end of the period, assets (liabilities), net $(178) 197 (215) $(196) $(285) 367 (260) $(178) (a)Current period changes also include the changes in fair value of new contracts entered into during the period, if any. The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2010 was a decrease of $18 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 2010, Southern Company had a net hedge volume of 149 million mmBtu with a weighted average contract cost approximately $1.35 per mmBtu above market prices, compared to 145 million mmBtu at December 31, 2009 with a weighted average contract cost approximately $1.23 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses. At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets (liabilities) were as follows: Asset (Liability) Derivatives 2009 2010 (in millions) Regulatory hedges Cash flow hedges Not designated Total fair value $(193) (1) (2) $(196) $(175) (2) (1) $(178) Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies’ fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Total net unrealized pre-tax gains (losses) recognized in the statements of income for the years ended December 31, 2010, 2009, and 2008 for energy-related derivative contracts that are not hedges were $(2) million, $(5) million, and $1 million, respectively. II-39 SoCo FOIA Response 002396 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 10 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2010 were as follows: December 31, 2010 Fair Value Measurements Total Maturity Fair Value Year 1 Years 2&3 Years 4&5 (in millions) Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period $ (196) $ (196) $ (144) $ (144) $ (52) $(52) $$- Southern Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s, a division of The McGraw Hill Companies, Inc., or with counterparties who have posted collateral to cover potential credit exposure. Therefore, Southern Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized. Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company’s domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company’s international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level. Capital Requirements and Contractual Obligations The construction programs of the Company’s subsidiaries are currently estimated to include a base level investment of $4.9 billion, $5.1 billion, and $4.5 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million for 2011, $191 million to $670 million for 2012, and $476 million to $1.9 billion for 2013. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction,” “Retail Regulatory Matters – Georgia Power – Other Construction,” and “Retail Regulatory Matters –Mississippi Power Integrated Coal Gasification Combined Cycle” and Note 7 to the financial statements under “Construction Program” for additional information. As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” II-40 SoCo FOIA Response 002397 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report In addition, as discussed in Note 2 to the financial statements, Southern Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the traditional operating companies’ respective regulatory commissions. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 6, 7, and 11 to the financial statements for additional information. II-41 SoCo FOIA Response 002398 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report Contractual Obligations 2011 20122013 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) After 2015 Uncertain Timing(d) Total (in millions) (a) Long-term debt – Principal Interest Preferred and preference stock dividends(b) Energy-related derivative obligations(c) Operating leases Capital leases Unrecognized tax benefits and interest(d) Purchase commitments(e) – Capital(f) Limestone(g) Coal Nuclear fuel Natural gas(h) Biomass fuel(i) Purchased power Long-term service agreements(j) Trusts – Nuclear decommissioning(k) Pension and other postretirement benefit plans(l) Total 20142015 $1,278 876 65 151 154 23 203 $2,938 1,610 130 55 170 28 - $1,138 1,369 130 94 13 - $14,029 11,194 103 35 - 4,554 39 3,810 335 1,357 260 110 9,242 82 3,244 427 2,280 32 506 270 72 1,656 349 1,687 36 559 290 3 64 $13,282 4 147 $21,165 $ 122 $19,383 15,049 325 206 521 99 325 89 1,798 807 3,413 110 2,439 1,435 - 13,796 282 10,508 1,918 8,737 178 3,764 2,105 4 35 $7,397 $35,487 $ 122 46 211 $77,453 All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2011, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only. For additional information, see Notes 1 and 11 to the financial statements. The timing related to the realization of $122 million in unrecognized tax benefits and corresponding interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Notes 3 and 5 to the financial statements for additional information. Southern Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2010, 2009, and 2008 were $4.0 billion, $3.5 billion, and $3.8 billion, respectively. Southern Company provides forecasted capital expenditures for a three-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for nuclear fuel. In addition, such amounts exclude Southern Company’s estimates of potential incremental investments to comply with anticipated new environmental regulations which could range from $74 million to $289 million for 2011, $191 million to $670 million for 2012, and $476 million to $1.9 billion for 2013. At December 31, 2010, significant purchase commitments were outstanding in connection with the construction program. As part of Southern Company’s program to reduce SO 2 emissions from its coal plants, the traditional operating companies have entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2010. Biomass fuel commitments are based on minimum committed tonnage of wood waste purchases. Long-term service agreements include price escalation based on inflation indices. Projections of nuclear decommissioning trust fund contributions are based on the 2010 ARP for Georgia Power. Southern Company forecasts contributions to the qualified pension and other postretirement benefit plans over a three-year period. Southern Company does not expect to be required to make any contributions to the qualified pension plan during the next three years. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from Southern Company’s corporate assets. II-42 SoCo FOIA Response 002399 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2010 Annual Report Cautionary Statement Regarding Forward-Looking Statements Southern Company’s 2010 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate actions, environmental regulations and expenditures, future earnings, dividend payout ratios, access to sources of capital, projections for the qualified pension plan, postretirement benefit, and nuclear decommissioning trust fund contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:                         the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations; current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS audits; the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate; variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures; available sources and costs of fuels; effects of inflation; ability to control costs and avoid cost overruns during the development and construction of facilities; investment performance of Southern Company’s employee benefit plans and nuclear decommissioning trust funds; advances in technology; state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms; regulatory approvals and actions related to the Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees; regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals and potential DOE loan guarantees; the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries; the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers; the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings; the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices; catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on Southern Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC. Southern Company expressly disclaims any obligation to update any forward-looking statements. II-43 SoCo FOIA Response 002400 CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2010, 2009, and 2008 Southern Company and Subsidiary Companies 2010 Annual Report 2010 2009 2008 (in millions) Operating Revenues: Retail revenues Wholesale revenues Other electric revenues Other revenues Total operating revenues Operating Expenses: Fuel Purchased power Other operations and maintenance MC Asset Recovery litigation settlement Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Interest income Leveraged lease income (losses) Gain on disposition of lease termination Loss on extinguishment of debt Interest expense, net of amounts capitalized Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Consolidated Net Income Dividends on Preferred and Preference Stock of Subsidiaries Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries Common Stock Data: Earnings per share (EPS)– Basic EPS Diluted EPS Average number of shares of common stock outstanding – (in millions) Basic Diluted Cash dividends paid per share of common stock $14,791 1,994 589 82 17,456 $13,307 1,802 533 101 15,743 $14,055 2,400 545 127 17,127 6,699 563 4,010 1,513 869 13,654 3,802 5,952 474 3,526 202 1,503 818 12,475 3,268 6,818 815 3,748 1,443 797 13,621 3,506 194 24 18 (895) (77) (736) 3,066 1,026 2,040 65 200 23 31 26 (17) (905) (22) (664) 2,604 896 1,708 65 152 33 (85) (866) (18) (784) 2,722 915 1,807 65 $ 1,975 $ 1,643 $ 1,742 $2.37 2.36 $2.07 2.06 $2.26 2.25 832 837 $1.8025 795 796 $1.7325 771 775 $1.6625 The accompanying notes are an integral part of these financial statements. II-44 SoCo FOIA Response 002401 CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2010, 2009, and 2008 Southern Company and Subsidiary Companies 2010 Annual Report 2010 2009 2008 (in millions) Operating Activities: Consolidated net income Adjustments to reconcile consolidated net income to net cash provided from operating activities -Depreciation and amortization, total Deferred income taxes Deferred revenues Allowance for equity funds used during construction Leveraged lease (income) losses Gain on disposition of lease termination Loss on extinguishment of debt Pension, postretirement, and other employee benefits Stock based compensation expense Hedge settlements Generation construction screening costs Other, net Changes in certain current assets and liabilities --Receivables -Fossil fuel stock -Materials and supplies -Other current assets -Accounts payable -Accrued taxes -Accrued compensation -Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Investment in restricted cash from revenue bonds Distribution of restricted cash from revenue bonds Nuclear decommissioning trust fund purchases Nuclear decommissioning trust fund sales Proceeds from property sales Cost of removal, net of salvage Change in construction payables Other investing activities Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds -Long-term debt issuances Common stock issuances Redemptions -Long-term debt Redeemable preferred stock Payment of common stock dividends Payment of dividends on preferred and preference stock of subsidiaries Other financing activities Net cash provided from financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year $ 2,040 $ 1,708 $ 1,807 1,831 1,038 (103) (194) (18) (614) 33 2 (51) 86 1,788 25 (54) (200) (31) (26) 17 (3) 23 (19) (22) 102 1,704 215 120 (152) 85 21 20 15 (108) 80 135 (30) (17) 4 (308) 180 (103) 3,991 585 (432) (39) (47) (125) (95) (226) 334 3,263 (176) (303) (23) (36) (74) 293 36 20 3,464 (4,086) (50) 25 (2,009) 2,004 18 (125) (51) 18 (4,256) (4,670) (55) 119 (1,234) 1,228 340 (119) 215 (143) (4,319) (3,961) (96) 69 (720) 712 34 (123) 83 (124) (4,126) (306) (314) 659 3,151 772 (2,966) (1,496) (65) (33) 22 (243) 690 $ 447 3,042 1,286 (1,234) (1,369) (65) (25) 1,329 273 417 $ 690 3,687 474 (1,469) (125) (1,280) (66) (29) 878 216 201 $ 417 The accompanying notes are an integral part of these financial statements. II-45 SoCo FOIA Response 002402 CONSOLIDATED BALANCE SHEETS At December 31, 2010 and 2009 Southern Company and Subsidiary Companies 2010 Annual Report Assets 2009 2010 (in millions) Current Assets: Cash and cash equivalents Restricted cash and cash equivalents Receivables -Customer accounts receivable Unbilled revenues Under recovered regulatory clause revenues Other accounts and notes receivable Accumulated provision for uncollectible accounts Fossil fuel stock, at average cost Materials and supplies, at average cost Vacation pay Prepaid expenses Other regulatory assets, current Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated depreciation Plant in service, net of depreciation Nuclear fuel, at amortized cost Construction work in progress Total property, plant, and equipment Other Property and Investments: Nuclear decommissioning trusts, at fair value Leveraged leases Miscellaneous property and investments Total other property and investments Deferred Charges and Other Assets: Deferred charges related to income taxes Prepaid pension costs Unamortized debt issuance expense Unamortized loss on reacquired debt Deferred under recovered regulatory clause revenues Other regulatory assets, deferred Other deferred charges and assets Total deferred charges and other assets Total Assets $ 447 68 1,140 420 209 285 (25) 1,308 827 151 784 210 59 5,883 $ 690 43 953 394 333 375 (25) 1,447 794 145 508 167 49 5,873 56,731 20,174 36,557 670 4,775 42,002 53,588 19,121 34,467 593 4,170 39,230 1,370 624 277 2,271 1,070 610 283 1,963 1,280 88 178 274 218 2,402 436 4,876 $55,032 1,047 208 255 373 2,702 395 4,980 $52,046 The accompanying notes are an integral part of these financial statements. II-46 SoCo FOIA Response 002403 CONSOLIDATED BALANCE SHEETS At December 31, 2010 and 2009 Southern Company and Subsidiary Companies 2010 Annual Report Liabilities and Stockholders' Equity 2010 2009 (in millions) Current Liabilities: Securities due within one year Notes payable Accounts payable Customer deposits Accrued taxes -Accrued income taxes Unrecognized tax benefits Other accrued taxes Accrued interest Accrued vacation pay Accrued compensation Liabilities from risk management activities Other regulatory liabilities, current Other current liabilities Total current liabilities Long-Term Debt (See accompanying statements) Deferred Credits and Other Liabilities: Accumulated deferred income taxes Deferred credits related to income taxes Accumulated deferred investment tax credits Employee benefit obligations Asset retirement obligations Other cost of removal obligations Other regulatory liabilities, deferred Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Redeemable Preferred Stock of Subsidiaries (See accompanying statements) Total Stockholders' Equity (See accompanying statements) Total Liabilities and Stockholders' Equity Commitments and Contingent Matters (See notes) $ 1,301 1,297 1,275 332 $ 1,113 639 1,329 331 8 187 440 225 194 438 152 88 535 6,472 18,154 13 166 398 218 184 248 125 528 292 5,584 18,131 7,554 235 509 1,580 1,257 1,158 312 517 13,122 37,748 375 16,909 $55,032 6,455 248 448 2,304 1,201 1,091 278 346 12,371 36,086 375 15,585 $52,046 The accompanying notes are an integral part of these financial statements. II-47 SoCo FOIA Response 002404 CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31, 2010 and 2009 Southern Company and Subsidiary Companies 2010 Annual Report 2009 2010 (in millions) Long-Term Debt: Long-term debt payable to affiliated trusts -Maturity Interest Rates 2044 5.88% Variable rate (3.39% at 1/1/11) due 2042 Total long-term debt payable to affiliated trusts Long-term senior notes and debt -Interest Rates Maturity 2010 4.70% 2011 4.00% to 5.57% 2012 4.85% to 6.25% 2013 1.30% to 6.00% 2014 4.15% to 4.90% 2015 2.38% to 5.75% 2016 through 2048 2.25% to 8.20% Adjustable rates (at 1/1/11): 2010 0.35% to 0.97% 2011 0.56% to 0.78% 2013 0.62% 2040 0.44% Total long-term senior notes and debt Other long-term debt -Pollution control revenue bonds -Interest Rates Maturity 2016 through 2049 0.80% to 6.00% Variable rates (at 1/1/11): 2011 through 2041 0.26% to 0.51% Total other long-term debt Capitalized lease obligations Unamortized debt (discount), net Total long-term debt (annual interest requirement -- $ 876 million) Less amount due within one year Long-term debt excluding amount due within one year $ 206 206 412 2009 (percent of total) $ 206 206 412 304 1,778 1,436 425 1,184 9,438 102 304 1,778 936 425 1,025 8,822 915 350 50 15,880 990 790 15,172 1,807 1,973 1,284 3,091 99 (27) 1,612 3,585 98 (23) 19,455 1,301 18,154 2010 19,244 1,113 18,131 51.2% II-48 SoCo FOIA Response 002405 53.2% CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2010 and 2009 Southern Company and Subsidiary Companies 2010 Annual Report 2010 2009 (in millions) Redeemable Preferred Stock of Subsidiaries: Cumulative preferred stock $100 par or stated value -- 4.20% to 5.44% Authorized - 20 million shares Outstanding - 1 million shares $1 par value -- 5.20% to 5.83% Authorized - 28 million shares Outstanding - 12 million shares: $25 stated value Total redeemable preferred stock of subsidiaries (annual dividend requirement -- $ 20 million) Common Stockholders' Equity: Common stock, par value $5 per share -Authorized - 1 billion shares Issued -- 2010: 844 million shares -- 2009: 820 million shares Treasury -- 2010: 0.5 million shares -- 2009: 0.5 million shares Paid-in capital Treasury, at cost Retained earnings Accumulated other comprehensive income (loss) Total common stockholders' equity Preferred and Preference Stock of Subsidiaries: Non-cumulative preferred stock $25 par value -- 6.00% to 6.13% Authorized - 60 million shares Outstanding - 2 million shares Preference stock Authorized - 65 million shares Outstanding - $1 par value -- 5.63% to 6.50% - 14 million shares (non-cumulative) - $100 par or stated value -- 6.00% to 6.50% - 3 million shares (non-cumulative) Total preferred and preference stock of subsidiaries (annual dividend requirement -- $ 45 million) Total stockholders' equity Total Capitalization 2010 2009 (percent of total) 81 81 294 294 375 375 4,219 4,101 3,702 (15) 8,366 (70) 16,202 2,995 (15) 7,885 (88) 14,878 45 45 343 343 319 319 707 16,909 $35,438 707 15,585 $34,091 1.1 1.1 45.7 43.6 2.0 2.1 100.0% 100.0% The accompanying notes are an integral part of these financial statements. II-49 SoCo FOIA Response 002406 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY For the Years Ended December 31, 2010, 2009, and 2008 Southern Company and Subsidiary Companies 2010 Annual Report Number of Common Shares Issued Treasury Accumulated Other Comprehensive Common Stock Par Paid-In Retained Income (Loss) Value Capital Treasury Earnings (in thousands) Balance at December 31, 2007 Net income after dividends on preferred and preference stock of subsidiaries Other comprehensive loss Stock issued Stock-based compensation Cash dividends Other Balance at December 31, 2008 Net income after dividends on preferred and preference stock of subsidiaries Other comprehensive income Stock issued Stock-based compensation Cash dividends Other Balance at December 31, 2009 Net income after dividends on preferred and preference stock of subsidiaries Other comprehensive income Stock issued Stock-based compensation Cash dividends Other Balance at December 31, 2010 Preferred and Preference Stock of Subsidiaries Total (in millions) 763,503 (399) $3,817 $1,454 $(11) $7,155 $ (30) $707 14,113 777,616 (25) (424) 71 3,888 402 36 1 1,893 (1) (12) 1,742 (1,279) (6) 7,612 (75) (105) 707 1,742 (75) 473 36 (1,279) (6) 13,983 42,536 820,152 (81) (505) 213 4,101 1,074 26 2 2,995 (3) (15) 1,643 (1,369) (1) 7,885 17 (88) 707 1,643 17 1,287 26 (1,369) (2) 15,585 23,662 843,814 31 (474) 118 $4,219 654 52 1 $3,702 $(15) 1,975 (1,496) 2 $8,366 18 $(70) $707 1,975 18 772 52 (1,496) 3 $16,909 The accompanying notes are an integral part of these financial statements. II-50 SoCo FOIA Response 002407 $13,092 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2010, 2009, and 2008 Southern Company and Subsidiary Companies 2010 Annual Report 2010 2009 2008 (in millions) Consolidated Net Income Other comprehensive income: Qualifying hedges: $2,040 Changes in fair value, net of tax of $-, $(3), and $(19), respectively Reclassification adjustment for amounts included in net income, net of tax of $9, $18, and $7, respectively Marketable securities: Change in fair value, net of tax of $(2), $1, and $(4), respectively Pension and other postretirement benefit plans: Benefit plan net gain (loss),net of tax of $1, $(8), and $(32), respectively Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively Total other comprehensive income (loss) Dividends on preferred and preference stock of subsidiaries Consolidated Comprehensive Income $1,708 $1,807 (1) (4) (30) 15 28 11 (3) 4 (7) 6 (12) (51) 1 17 (65) $1,660 2 (75) (65) $1,667 1 18 (65) $1,993 The accompanying notes are an integral part of these financial statements. II-51 SoCo FOIA Response 002408 NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 2010 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General The Southern Company (the Company) is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. The financial statements reflect Southern Company’s investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment, but is not the primary beneficiary. All material intercompany transactions have been eliminated in consolidation. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC) and the traditional operating companies are also subject to regulation by their respective state public service commissions (PSC). The companies follow generally accepted accounting principles (GAAP) in the U.S. and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. II-52 SoCo FOIA Response 002409 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Regulatory Assets and Liabilities The traditional operating companies are subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2010 2009 Note (in millions) Deferred income tax charges Deferred income tax charges – Medicare subsidy Asset retirement obligations-asset Asset retirement obligations-liability Other cost of removal obligations Deferred income tax credits Loss on reacquired debt Vacation pay Under recovered regulatory clause revenues Over recovered regulatory clause revenues Building leases Generating plant outage costs Under recovered storm damage costs Property damage reserves Fuel hedging-asset Fuel hedging-liability Other assets Environmental remediation-asset Environmental remediation-liability Environmental compliance cost recovery Other liabilities Retiree benefit plans Total assets (liabilities), net $1,204 82 79 (82) (1,188) (237) 274 151 27 (40) 45 31 8 (216) 211 (7) 171 67 (10) (13) 2,041 $ 2,598 $ 1,048 125 (47) (1,307) (249) 255 145 40 (218) 47 39 22 (157) 187 (2) 156 68 (13) (96) (51) 2,268 $ 2,260 (a) (k) (a,i) (a,i) (a) (a) (b) (c,i) (d) (d) (f) (d) (d) (h) (d) (d) (d) (h,i) (h) (g) (j) (e,i) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and other cost of removal liabilities will be settled and trued up following completion of the related activities. Other cost of removal obligations include $92 million at Georgia Power that will be amortized over a three-year period beginning January 1, 2011 in accordance with a Georgia PSC order. See Note 3 under “Retail Regulatory Matters – Georgia Power – Retail Rate Plans” for additional information. (b) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years. (c) Recorded as earned by employees and recovered as paid, generally within one year. (d) Recorded and recovered or amortized as approved by the appropriate state PSCs over periods not exceeding 10 years. (e) Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. (f) Recovered over the remaining lives of the buildings through 2026. (g) Deferred revenue associated with the levelization of Georgia Power’s environmental compliance cost recovery (ECCR) tariff revenue for the years 2008 through 2010 in accordance with a Georgia PSC order. (h) Recovered as storm restoration or environmental remediation expenses are incurred. (i) Not earning a return as offset in rate base by a corresponding asset or liability. (j) Recorded and recovered or amortized as approved by the appropriate state PSC over periods up to the life of the plant or the remaining life of the original issue or, if refinanced, over the life of the new issue which may range up to 50 years. (k) Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 14 years. See Note 5 under “Current and Deferred Income Taxes” for additional information. In the event that a portion of a traditional operating company’s operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off or reclassify to accumulated other comprehensive income (OCI) related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Retail Regulatory II-53 SoCo FOIA Response 002410 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Matters – Alabama Power,” “Retail Regulatory Matters – Georgia Power,” and “Retail Regulatory Matters – Mississippi Power Integrated Coal Gasification Combined Cycle” for additional information. Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Southern Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under “Nuclear Fuel Disposal Costs” for additional information. Income and Other Taxes Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred investment tax credits (ITCs) for the traditional operating companies are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $23 million in 2010, $24 million in 2009, and $23 million in 2008. At December 31, 2010, all ITCs available to reduce federal income taxes payable had been utilized. Under the American Recovery and Reinvestment Act of 2009, certain projects at certain Southern Company subsidiaries are eligible for ITCs or cash grants. These subsidiaries have elected to receive ITCs. The credits are recorded as a deferred credit, which will be amortized over the life of the asset, and the tax basis of the asset is reduced by 50% of the credits received, resulting in a deferred tax asset. The subsidiaries have elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period. These basis differences will reverse and be recorded to income tax expense over the useful life of the asset once placed in service. In accordance with accounting standards related to the uncertainty in income taxes, Southern Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction. II-54 SoCo FOIA Response 002411 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Southern Company’s property, plant, and equipment consisted of the following at December 31: 2009 2010 (in millions) Generation Transmission Distribution General Plant acquisition adjustment Utility plant in service Information technology equipment and software Communications equipment Other Other plant in service Total plant in service $30,121 7,835 14,870 3,116 43 55,985 216 423 107 746 $56,731 $28,204 7,380 14,335 2,917 43 52,879 182 423 104 709 $53,588 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit’s operating cycle. The refueling cycles for Alabama Power and Georgia Power range from 18 to 24 months for each unit. In accordance with a Georgia PSC order, Georgia Power also defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle. The amount of non-cash property additions recognized for the years ended December 31, 2010, 2009, and 2008 was $427 million, $370 million, and $309 million, respectively. These amounts are comprised of construction related accounts payable outstanding at each year end together with retention amounts accrued during the respective year. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2010, 3.2% in 2009, and 3.2% in 2008. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $19.7 billion and $18.7 billion at December 31, 2010 and 2009, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. In August 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize a portion of its regulatory liability related to other cost of removal obligations. See Note 3 under “Retail Regulatory Matters – Georgia Power – Retail Rate Plans” for additional information. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 30 years. Accumulated depreciation for other plant in service totaled $441 million and $419 million at December 31, 2010 and 2009, respectively. Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 3 under “Retail Regulatory Matters – Georgia Power – Retail Rate Plans” for additional information related to Georgia Power’s cost of removal regulatory liability. II-55 SoCo FOIA Response 002412 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facilities, Plants Farley, Hatch, and Vogtle. In addition, the Company has retirement obligations related to various landfill sites, ash ponds, underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See “Nuclear Decommissioning” herein for further information on amounts included in rates. Details of the asset retirement obligations included in the balance sheets are as follows: 2009 2010 (in millions) Balance at beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions Balance at end of year $1,206 (16) 78 (2) $1,266 $1,185 2 (10) 77 (48) $1,206 Nuclear Decommissioning The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC’s regulations. Use of the Funds is restricted to nuclear decommissioning activities and the Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds’ managers to exercise the standard of care in investing that a “prudent investor” would use in the same circumstances. The FERC regulations also require, except for investments tied to market indices or other mutual funds, that the Funds’ managers may not invest in any securities of the utility for which it manages funds or its affiliates. In addition, the NRC prohibits investments in securities of power reactor licensees. While Southern Company is allowed to prescribe an overall investment policy to the Funds’ managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-today management of the investments in the Funds is delegated to unrelated third party managers with oversight by Southern Company, Alabama Power, and Georgia Power management. The Funds’ managers are authorized, within broad limits, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds’ investment securities are loaned to investment brokers for a fee. Securities so loaned are fully collateralized by cash, letters of credit, and securities issued or guaranteed by the U.S. government, its agencies, and the instrumentalities. As of December 31, 2010 and 2009, approximately $141 million and $14 million, respectively, of the fair market value of the Funds’ securities were on loan and pledged to creditors under the Funds’ managers’ securities lending program. The fair value of the collateral received was approximately $144 million and $14 million at December 31, 2010 and 2009, respectively, and can only be sold upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows. At December 31, 2010, investment securities in the Funds totaled $1.4 billion consisting of equity securities of $664 million, debt securities of $632 million, and $74 million of other securities. At December 31, 2009, investment securities in the Funds totaled $1.1 billion consisting of equity securities of $774 million, debt securities of $272 million, and $22 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases and the lending pool. II-56 SoCo FOIA Response 002413 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Sales of the securities held in the Funds resulted in cash proceeds of $2.0 billion, $1.2 billion, and $712 million in 2010, 2009, and 2008, respectively, all of which were reinvested. For 2010, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $139 million, of which $6 million related to securities held in the Funds at December 31, 2010. For 2009, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $215 million, of which $198 million related to securities held in the Funds at December 31, 2009. For 2008, fair value reductions, including reinvested interest and dividends and excluding the Funds’ expenses, were $(278) million. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of and purpose for which the securities were acquired. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2010, the accumulated provisions for decommissioning were as follows: Plant Farley Plant Hatch Plant Vogtle (in millions) External trust funds Internal reserves Total $553 24 $577 $360 $360 $206 $206 Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning based on the most current studies, which were performed in 2008 for Alabama Power’s Plant Farley and in 2009 for the Georgia Power plants, were as follows for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plants Hatch and Vogtle: Plant Farley Plant Hatch Plant Vogtle Decommissioning periods: Beginning year Completion year 2037 2065 2034 2063 2047 2067 (in millions) Site study costs: Radiated structures Non-radiated structures Total $1,060 72 $1,132 $583 46 $629 $500 71 $571 The decommissioning periods and site study costs for Plant Vogtle reflect the extended operating license approved by the NRC in June 2009. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. For ratemaking purposes, Alabama Power’s decommissioning costs are based on the site study, and Georgia Power’s decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2006. The estimates used in current rates are $575 million and $420 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Amounts expensed were $3 million annually for Plant Vogtle Units 1 and 2 for 2008 through 2010. Effective for the years 2011 through 2013, the annual decommissioning cost for ratemaking is $2 million for Plant Hatch. Georgia Power projects the external trust funds for Plant Vogtle Units 1 and 2 would be adequate to meet the decommissioning obligations of the NRC with no further contributions. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively. As a result of license extensions, amounts previously contributed to the external trust funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. II-57 SoCo FOIA Response 002414 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized In accordance with regulatory treatment, the traditional operating companies record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies’ regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 12.5%, 15.3%, and 11.2% of net income for 2010, 2009, and 2008, respectively. Cash payments for interest totaled $789 million, $788 million, and $787 million in 2010, 2009, and 2008, respectively, net of amounts capitalized of $86 million, $84 million, and $71 million, respectively. Impairment of Long-Lived Assets and Intangibles Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. Storm Damage Reserves Each traditional operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $32 million in 2010 and $44 million in 2009. Alabama Power, Gulf Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2010 and 2009, such additional accruals totaled $48 million and $40 million, respectively, all at Alabama Power. There were no material accruals for 2008. See Note 3 under “Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve” for additional information regarding Alabama Power’s natural disaster reserve. Leveraged Leases Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. Southern Company’s net investment in domestic leveraged leases consists of the following at December 31: 2009 2010 (in millions) Net rentals receivable Unearned income Investment in leveraged leases Deferred taxes from leveraged leases Net investment in leveraged leases $475 (207) 268 (223) $ 45 $487 (218) 269 (211) $ 58 II-58 SoCo FOIA Response 002415 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report A summary of the components of income from domestic leveraged leases was as follows: 2010 2009 2008 (in millions) Pretax leveraged lease income Income tax expense Net leveraged lease income $4 (3) $1 $12 (5) $ 7 $14 (6) $ 8 Southern Company’s net investment in international leveraged leases consists of the following at December 31: 2009 2010 (in millions) Net rentals receivable Unearned income Investment in leveraged leases Current taxes payable Deferred taxes from leveraged leases Net investment in leveraged leases $ 734 (393) 341 (40) $ 301 $ 733 (377) 356 (40) $ 316 A summary of the components of income from international leveraged leases was as follows: 2010 2009 2008 (in millions) Pretax leveraged lease income (loss) Income tax benefit (expense) Net leveraged lease income (loss) $14 (5) $9 $19 (7) $12 $(99) 35 $(64) The Company terminated two international leveraged lease investments during 2009. The proceeds were used to extinguish all debt related to leveraged lease investments, a portion of which had make-whole redemption provisions. This resulted in a $17 million loss which partially offset a $26 million gain on the terminations. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost. Financial Instruments Southern Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information. Substantially all of Southern Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional operating companies’ fuel hedging programs. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any II-59 SoCo FOIA Response 002416 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2010, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was not material. Southern Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income. Accumulated OCI (loss) balances, net of tax effects, were as follows: Qualifying Hedges Marketable Securities $(49) 14 $(35) $10 (3) $7 Pension and Other Accumulated Other Postretirement Comprehensive Benefit Plans Income (Loss) (in millions) Balance at December 31, 2009 Current period change Balance at December 31, 2010 $(49) 7 $(42) $ (88) 18 $ (70) Variable Interest Entities Effective January 1, 2010, the traditional operating companies and Southern Power adopted new accounting guidance which modified the consolidation model and expanded disclosures related to variable interest entities (VIE). The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the traditional operating companies or Southern Power consolidating any VIEs that were not already consolidated under previous guidance, nor deconsolidating any VIEs. Certain of the traditional operating companies have established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, Southern Company and the applicable traditional operating companies are not considered the primary beneficiaries of the trusts. Therefore, the investments in these trusts are reflected as other investments, and the related loans from the trusts are reflected in long-term debt in the balance sheets. 2. RETIREMENT BENEFITS Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2010, the traditional operating companies and certain other subsidiaries contributed approximately $620 million to the qualified pension plan. No contributions to the qualified pension plan are expected for the year ending December 31, 2011. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2011, other postretirement trust contributions are expected to total approximately $31 million. II-60 SoCo FOIA Response 002417 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2007 for the 2008 plan year using a discount rate of 6.30% and an annual salary increase of 3.75%. 2009 2008 5.52% 5.40 3.84 5.93% 5.83 4.18 6.75% 6.75 3.75 8.75 7.40 8.50 7.51 8.50 7.59 2010 Discount rate: Pension plans Other postretirement benefit plans Annual salary increase Long-term return on plan assets: Pension plans Other postretirement benefit plans The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate of 8.25% for 2011, decreasing gradually to 5.0% through the year 2019 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2010 as follows: 1 Percent 1 Percent Increase Decrease (in millions) Benefit obligation Service and interest costs $128 7 $108 6 Pension Plans The total accumulated benefit obligation for the pension plans was $6.7 billion in 2010 and $6.3 billion in 2009. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2010 2009 (in millions) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial loss (gain) Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability $6,758 172 391 (296) 198 7,223 $5,879 146 387 (282) 628 6,758 5,627 859 644 (296) 6,834 $ (389) 5,093 792 24 (282) 5,627 $(1,131) At December 31, 2010, the projected benefit obligations for the qualified and non-qualified pension plans were $6.7 billion and $0.5 billion, respectively. All pension plan assets are related to the qualified pension plan. II-61 SoCo FOIA Response 002418 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s pension plans consist of the following: 2010 2009 (in millions) Prepaid pension costs Other regulatory assets, deferred Other current liabilities Employee benefit obligations Accumulated OCI $ 88 1,749 (28) (449) 68 $ 1,894 (25) (1,106) 74 Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2010 and 2009 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2011. Prior Service Cost Net (Gain) Loss (in millions) Balance at December 31, 2010: Accumulated OCI Regulatory assets Total $ 8 159 $ 167 $ 60 1,590 $ 1,650 Balance at December 31, 2009: Accumulated OCI Regulatory assets Total $ 10 188 $198 $ 64 1,706 $1,770 Estimated amortization in net periodic pension cost in 2011: Accumulated OCI Regulatory assets Total $ 1 31 $32 $ 1 20 $21 The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2010 and 2009 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) $54 21 - Balance at December 31, 2008 Net loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net gain Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 (1) (1) 20 74 (4) (1) (1) (2) (6) $ 68 $1,579 355 1 (34) (7) (41) 315 1,894 (106) 2 (32) (9) (41) (145) $1,749 II-62 SoCo FOIA Response 002419 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Components of net periodic pension cost were as follows: 2009 2010 2008 (in millions) Service cost Interest cost Expected return on plan assets Recognized net loss Net amortization Net periodic pension cost $ 146 387 (541) 7 35 $ 34 $ 172 391 (552) 10 33 $ 54 $ 146 348 (525) 9 37 $ 15 Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2010, estimated benefit payments were as follows: Benefit Payments (in millions) 2011 2012 2013 2014 2015 2016 to 2020 $ 335 353 372 392 413 2,368 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2009 2010 (in millions) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial loss (gain) Plan amendments Retiree drug subsidy Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability $1,759 25 100 (95) (41) (2) 6 1,752 $1,733 26 113 (93) 34 (59) 5 1,759 743 82 66 (89) 802 $ (950) 631 127 72 (87) 743 $(1,016) II-63 SoCo FOIA Response 002420 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s other postretirement benefit plans consist of the following: 2009 2010 (in millions) Other regulatory assets, deferred Other current liabilities Employee benefit obligations Accumulated OCI $ $ 292 (1) (949) 3 374 (1,016) 5 Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2010 and 2009 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2011. Prior Service Cost Net (Gain) Loss Transition Obligation (in millions) Balance at December 31, 2010: Accumulated OCI Regulatory assets Total Balance at December 31, 2009: Accumulated OCI Regulatory assets Total $ 34 $34 Estimated amortization as net periodic postretirement benefit cost in 2011: Accumulated OCI Regulatory assets Total $ 3 233 $236 $ 25 $25 $ $ 41 $41 5 298 $303 $ 35 $35 $5 $5 $4 $4 $ 10 $10 The components of OCI, along with the changes in the balance of regulatory assets, related to the other postretirement benefit plans for the plan years ended December 31, 2010 and 2009 are presented in the following table: Accumulated OCI Regulatory Assets (in millions) Balance at December 31, 2008 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 $8 (3) $489 (33) (56) (3) 5 (2) - (13) (8) (5) (26) (115) 374 (60) (2) (2) $3 (10) (5) (5) (20) (82) $292 II-64 SoCo FOIA Response 002421 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Components of the other postretirement benefit plans’ net periodic cost were as follows: 2010 2009 2008 (in millions) Service cost Interest cost Expected return on plan assets Net amortization Net postretirement cost $ 25 100 (63) 20 $ 82 $ 26 113 (61) 25 $103 $ 28 111 (59) 31 $111 The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced Southern Company’s expenses for the years ended December 31, 2010, 2009, and 2008 by approximately $28 million, $33 million, and $35 million, respectively, and is expected to have a similar impact on future expenses. Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows: Benefit Payments Subsidy Receipts Total (in millions) 2011 2012 2013 2014 2015 2016 to 2020 $108 114 121 127 133 695 $ (8) (9) (10) (12) (13) (69) $100 105 111 115 120 626 Benefit Plan Assets Pension plan and other postretirement plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policies for both the pension and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. II-65 SoCo FOIA Response 002422 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report The composition of the Company’s pension plan and other postretirement benefit plan assets as of December 31, 2010 and 2009, along with the targeted mix of assets for each plan, is presented below: Pension plan assets: Domestic equity International equity Fixed income Special situations Real estate investments Private equity Total Target 2010 2009 29% 28 15 3 15 10 100% 29% 27 22 13 9 100% 33% 29 15 13 10 100% Other postretirement benefit plan assets: Domestic equity 42% International equity 18 Domestic fixed income 27 Global fixed income 4 Special situations 1 Real estate investments 5 Private equity 3 Total 100% 40% 21 29 3 4 3 100% 37% 24 32 4 3 100% The investment strategy for plan assets related to the Company’s qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is longterm in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches. • International equity. An actively-managed mix of growth stocks and value stocks with both developed and emerging market exposure. • Fixed income. A mix of domestic and international bonds. • Trust-owned life insurance. Investments of the Company’s taxable trusts aimed at minimizing the impact of taxes on the portfolio. • Special situations. Though currently unfunded, established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. II-66 SoCo FOIA Response 002423 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2010 and 2009. The fair values presented are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund. The fair values of pension plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $1,266 1,277 $511 443 $1 - $1,778 1,720 2 184 $2,729 304 247 594 201 478 $2,778 2 674 638 $1,315 304 247 596 201 480 858 638 $6,822 (1) $2,728 $2,778 $1,315 (1) $6,821 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. II-67 SoCo FOIA Response 002424 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $1,117 1,444 $462 144 3 174 $2,738 (5) $2,733 $ - $1,579 1,588 416 113 279 10 341 $1,765 547 555 $1,102 416 113 279 10 344 721 555 $5,605 (1) $1,764 $1,102 (6) $5,599 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 were as follows: 2009 2010 Real Estate Investments Private Equity Real Estate Investments Private Equity (in millions) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $547 $555 $ 839 $490 59 18 77 50 $674 67 18 85 (2) $638 (240) (65) (305) 13 $ 547 37 10 47 18 $555 The fair values of other postretirement benefit plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. II-68 SoCo FOIA Response 002425 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Special situations Real estate investments Private equity Total $176 49 $45 50 $- $221 99 7 $232 15 10 23 34 41 291 $509 26 23 $49 15 10 23 34 41 291 33 23 $790 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Special situations Real estate investments Private equity Total $149 62 $42 36 $- $191 98 7 $218 22 5 12 18 54 270 $459 24 24 $48 22 5 12 18 54 270 31 24 $725 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 were as follows: II-69 SoCo FOIA Response 002426 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report 2009 2010 Real Estate Investments Private Equity Real Estate Investments Private Equity (in millions) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $24 $24 $36 $21 2 2 $26 1 1 (2) $23 (10) (3) (13) 1 $24 2 2 1 $24 Employee Savings Plan Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2010, 2009, and 2008 were $76 million, $78 million, and $76 million, respectively. 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements. Environmental Matters New Source Review Actions In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coalfired generating facilities operated by Alabama Power and Georgia Power, including facilities co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against Alabama Power is ongoing. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against II-70 SoCo FOIA Response 002427 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. Southern Company believes that the traditional operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the II-71 SoCo FOIA Response 002428 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Remediation Southern Company’s subsidiaries must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the subsidiaries may also incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. Within limits approved by the state PSCs, these rates are adjusted annually or as necessary. Georgia Power’s environmental remediation liability as of December 31, 2010 was $13 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and CERCLA NPL are anticipated. In September 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices regarding this site from the EPA. Georgia Power, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, in April 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, it is not expected to have a material impact on Southern Company’s financial statements. Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $62 million as of December 31, 2010. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates. The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the financial statements. Right of Way Litigation Southern Company and certain of its subsidiaries, including Mississippi Power, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company believes that its subsidiaries have complied with applicable laws and that the plaintiffs’ claims are without merit. Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and the related cases have been dismissed. These agreements have not resulted in any material effects on Southern Company’s financial statements. In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network Inc. a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are II-72 SoCo FOIA Response 002429 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. On August 24, 2010, the defendants filed a motion to dismiss the suit for lack of prosecution. In January 2011, the court indicated that it intended to deny the defendant’s motion to dismiss the claim; however, no written order denying the motion has been entered into the record. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined. Nuclear Fuel Disposal Costs Alabama Power and Georgia Power have contracts with the U.S., acting through the U.S. Department of Energy (DOE), that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract. In July 2007, the U.S. Court of Federal Claims awarded Georgia Power approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley, Hatch, and Vogtle from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April 2008. On May 5, 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay. In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of December 31, 2010 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of each plant. Income Tax Matters Georgia State Income Tax Credits Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia DOR has appealed to the Georgia Court of Appeals and a decision is expected later this year. Any decision may be subject to further appeal to the Georgia Supreme Court. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers in accordance with the Georgia PSC - approved Alternate Rate Plan for Georgia Power which became effective January 1, 2011 and will continue through December 31, 2013 (the 2010 ARP). If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s cash flow. See Note 5 under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot now be determined. Tax Method of Accounting for Repairs Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. On a consolidated basis, the new tax method resulted in net positive cash flow in 2010 of approximately $297 million. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been II-73 SoCo FOIA Response 002430 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report recorded for the change in the tax accounting method for repair costs. See Note 5 under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. Retail Regulatory Matters Alabama Power Rate RSE Alabama Power operates under the rate stabilization and equalization plan (Rate RSE) approved by the Alabama PSC. Alabama Power’s Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. Retail rates remain unchanged when the retail return on common equity (ROE) is projected to be between 13.0% and 14.5%. If Alabama Power’s actual retail ROE is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. The Rate RSE increase for 2010 was 3.24%, or $152 million annually, and was effective in January 2010. In December 2010, Alabama Power made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2011 and earnings were within the specified return range. Consequently, the retail rates will remain unchanged in 2011 under Rate RSE. Under the terms of Rate RSE, the maximum increase for 2012 cannot exceed 5.00%. Rate CNP Alabama Power’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated power purchase agreements (PPA) under Rate CNP. There was no adjustment to the Rate CNP to recover certificated PPA costs in 2008 or 2009. Effective April 2010, rate certificated new plant (Rate CNP) was reduced by approximately $70 million annually, primarily due to the expiration on May 31, 2010, of the PPA with Southern Power covering the capacity of Plant Harris Unit 1. It is estimated that there will be a slight decrease to the current Rate CNP effective April 2011. Rate CNP also allows for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Retail rates increased approximately 2.4% in January 2008 and 4.3% in January 2010 due to environmental costs. In October 2008, Alabama Power agreed to defer collection of any increase in rates under this portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations, from 2009 until 2010. The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no significant effect on the Company’s revenues or net income. On December 1, 2010, Alabama Power submitted calculations associated with its cost of complying with environmental mandates, as provided under Rate CNP Environmental. The filing reflects an incremental increase in the revenue requirement associated with such environmental compliance, which would be recoverable in the billing months of January 2011 through December 2011. In order to afford additional rate stability to customers as the economy continues to recover from the recession, the Alabama PSC ordered on January 4, 2011 that Alabama Power leave in effect for 2011 the factors associated with Alabama Power’s environmental compliance costs for the year 2010. Any recoverable amounts associated with 2011 will be reflected in the 2012 filing. The ultimate outcome of this matter cannot be determined at this time. Fuel Cost Recovery Alabama Power has established fuel cost recovery rates under Alabama Power’s energy cost recovery rate mechanism (Rate ECR) as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per kilowatt hour (KWH). The Rate ECR factor as of January 1, 2011 is 2.403 cents per KWH. Effective with billings beginning in April 2011, the Rate ECR factor will be 2.681 cents per KWH. II-74 SoCo FOIA Response 002431 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report As of December 31, 2010, Alabama Power had an under recovered fuel balance of approximately $4 million which is included in deferred under recovered regulatory clause revenues in the balance sheets. As of December 31, 2009, Alabama Power had an over recovered fuel balance of approximately $200 million of which approximately $22 million was included in deferred over recovered regulatory clause revenues in the balance sheets. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs or recovery of under recovered fuel costs. Natural Disaster Reserve Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly natural disaster rate mechanism (Rate NDR) charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Alabama Power has discretionary authority to accrue certain additional amounts as circumstances warrant. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the reserve. For the year ended December 31, 2010, Alabama Power accrued an additional $48 million to the NDR, resulting in an accumulated balance of approximately $127 million. For the year ended December 31, 2009, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $75 million. These accruals are included in the balance sheets under other regulatory liabilities, deferred and are reflected as operations and maintenance expense in the statements of income. Georgia Power Retail Rate Plans The economic recession significantly reduced Georgia Power’s revenues upon which retail rates were set by the Georgia PSC for 2008 through 2010 (the 2007 Retail Rate Plan). In June 2009, despite stringent efforts to reduce expenses, Georgia Power’s projected retail ROE for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, in June 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. In August 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, Georgia Power could amortize up to $108 million of the regulatory liability in 2009 and up to $216 million in 2010, limited to the amount needed to earn no more than a 9.75% and 10.15% retail ROE in 2009 and 2010, respectively. For the years ended December 31, 2009 and 2010, Georgia Power amortized $41 million and $174 million of the regulatory liability, respectively. On December 21, 2010, the Georgia PSC approved an Alternate Rate Plan for Georgia Power which became effective January 1, 2011 and continuing through December 31, 2013 (the 2010 ARP). The terms of the 2010 ARP reflect a settlement agreement among Georgia Power, the Georgia PSC’s Public Interest Advocacy Staff (PSC Staff) and eight other intervenors. Under the terms of the 2010 ARP, Georgia Power will amortize approximately $92 million of its remaining regulatory liability related to other cost of removal obligations over the three years ending December 31, 2013. Also under the terms of the 2010 ARP, effective January 1, 2011, Georgia Power increased its (1) traditional base tariff rates by approximately $347 million; (2) Demand-Side Management (DSM) tariff rates by approximately $31 million; (3) ECCR tariff rate by II-75 SoCo FOIA Response 002432 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report approximately $168 million; and (4) Municipal Franchise Fee (MFF) tariff rate by approximately $16 million, for a total increase in base revenues of approximately $562 million. Under the 2010 ARP, the following additional base rate adjustments will be made to Georgia Power’s tariffs in 2012 and 2013:  Effective January 1, 2012, the DSM tariffs will increase by $17 million;  Effective April 1, 2012, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Units 4 and 5 for the period from commercial operation through December 31, 2013;  Effective January 1, 2013, the DSM tariffs will increase by $18 million;  Effective January 1, 2013, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Unit 6 for the period from commercial operation through December 31, 2013; and  The MFF tariff will increase consistent with these adjustments. Georgia Power currently estimates these adjustments will result in annualized base revenue increases of approximately $190 million in 2012 and $93 million in 2013. Under the 2010 ARP, Georgia Power’s retail ROE is set at 11.15% and earnings will be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. If at any time during the term of the 2010 ARP, Georgia Power projects that retail earnings will be below 10.25% for any calendar year, it may petition the Georgia PSC for the implementation of an Interim Cost Recovery (ICR) tariff to adjust Georgia Power’s earnings back to a 10.25% retail ROE. The Georgia PSC will have 90 days to rule on any such request. If approved, any ICR tariff would expire at the earlier of January 1, 2014 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR, Georgia Power may file a full rate case. Except as provided above, Georgia Power will not file for a general base rate increase while the 2010 ARP is in effect. Georgia Power is required to file a general rate case by July 1, 2013, in response to which the Georgia PSC would be expected to determine whether the 2010 ARP should be continued, modified, or discontinued. Georgia Power currently expects to file an update to its integrated resource plan (IRP) in June 2011. Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets (resulting from new or revised environmental regulations) through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Such costs that may be deferred as a regulatory asset include any impairment losses that may result from a decision to retire certain units that are no longer cost effective in light of new or modified environmental regulations. In addition, in connection with the 2010 ARP, the Georgia PSC also approved revised depreciation rates that will recover the remaining book value of certain of Georgia Power’s existing coal-fired units by December 31, 2014. The ultimate outcome of these matters cannot be determined at this time. Fuel Cost Recovery Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved increases in Georgia Power’s total annual billings of approximately $222 million effective June 1, 2008 and $373 million effective April 1, 2010. In addition, the Georgia PSC has authorized an interim fuel rider, which would allow Georgia Power to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered fuel balance exceeds budget by more than $75 million. Georgia Power is currently required to file its next fuel case by March 1, 2011. As of December 31, 2010, Georgia Power’s under recovered fuel balance totaled approximately $398 million, of which approximately $214 million is included in deferred charges and other assets in the balance sheets. Fuel cost recovery revenues as recorded in the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in the billing factor has no significant effect on Southern Company’s revenues or net income, but does impact annual cash flow. II-76 SoCo FOIA Response 002433 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Nuclear Construction In August 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of Georgia Power, Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light and Sinking Fund Commissioners (collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). See Note 4 for additional information on these co-owners. In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units. If licensed by the NRC, Plant Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively. In April 2008, Georgia Power, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts (MWs) each and related facilities, structures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement). The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that will be subject to certain price escalations and adjustments, including fixed escalation amounts and certain indexbased adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. Georgia Power’s proportionate share is 45.7%. The Owners and the Consortium have agreed to certain liquidated damages upon the Consortium’s failure to comply with the schedule and performance guarantees. The Consortium’s liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events. In March 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve inclusion of the related construction work in progress accounts in rate base. In April 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows Georgia Power to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. The Georgia PSC has ordered Georgia Power to report against this total certified cost of approximately $6.1 billion. In addition, on December 21, 2010, the Georgia PSC approved Georgia Power’s Nuclear Construction Cost Recovery (NCCR) tariff. The NCCR tariff became effective January 1, 2011 and is expected to collect approximately $223 million in revenues during 2011. On February 21, 2011, the Georgia PSC voted to approve Georgia Power’s third semi-annual construction monitoring report including total costs of $1.048 billion for Plant Vogtle Units 3 and 4 incurred through June 30, 2010. In connection with its certification of Plant Vogtle Units 3 and 4, the Georgia PSC ordered Georgia Power and the PSC Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize Georgia Power’s earnings if and when overruns are due to mandates from governing agencies. Such discussions have continued through the third semi-annual construction monitoring proceedings; however, the Georgia PSC has deferred a decision with respect to any related incentive or risk-sharing mechanism until a later date. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period. II-77 SoCo FOIA Response 002434 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report In 2009, the Southern Alliance for Clean Energy (SACE) and the Fulton County Taxpayers Foundation, Inc. (FCTF) filed separate petitions in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. On May 5, 2010, the court dismissed as premature the plaintiffs’ claim challenging the Georgia Nuclear Energy Financing Act. FCTF appealed the decision, and the Georgia Supreme Court ruled against FCTF, finding the suit premature. In addition, on May 5, 2010, the Superior Court of Fulton County issued an order remanding the Georgia PSC’s certification order for inclusion of further findings of fact and conclusions of law by the Georgia PSC. In compliance with the court’s order, the Georgia PSC issued its order on remand to include further findings of fact and conclusions of law on June 23, 2010. On July 5, 2010, SACE and FCTF filed separate motions with the Georgia PSC for reconsideration of the order on remand. On August 17, 2010, the Georgia PSC voted to reaffirm its order. The matter is no longer subject to judicial review and is now concluded. On December 2, 2010, Westinghouse submitted an AP1000 Design Certification Amendment (DCA) to the NRC. On February 10, 2011, the NRC announced that it was seeking public comment on a proposed rule to approve the DCA and amend the certified AP1000 reactor design for use in the U.S. The Advisory Committee on Reactor Safeguards also issued a letter on January 24, 2011 endorsing the issuance of the COL for Plant Vogtle Units 3 and 4. Georgia Power currently expects to receive the COL for Plant Vogtle Units 3 and 4 from the NRC in late 2011 based on the NRC's February 16, 2011 release of its COL schedule framework. There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds. The ultimate outcome of these matters cannot now be determined. Other Construction On May 6, 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. As a result, the units are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. The Georgia PSC has approved Georgia Power’s quarterly construction monitoring reports, including actual project expenditures incurred, through June 30, 2010. Georgia Power will continue to file quarterly construction monitoring reports throughout the construction period. Mississippi Power Integrated Coal Gasification Combined Cycle In January 2009, Mississippi Power filed for a Certificate of Public Convenience and Necessity (CPCN) with the Mississippi PSC to allow the acquisition, construction, and operation of a new electric generating plant located in Kemper County, Mississippi that would utilize an integrated coal gasification combined cycle (IGCC) technology with an output capacity of 582 MWs. The estimated cost of the plant is $2.4 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2). The plant will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. In conjunction with the Kemper IGCC, Mississippi Power will own a lignite mine and equipment and will acquire mineral reserves located around the plant site in Kemper County. The estimated capital cost of the mine is approximately $214 million. On May 27, 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations. The agreement is effective June 1, 2010 through the end of the mine reclamation. The plant, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. On April 29, 2010, the Mississippi PSC issued an order finding that Mississippi Power’s application to acquire, construct, and operate the plant did not satisfy the requirement of public convenience and necessity in the form that the project and the related cost recovery were originally proposed by Mississippi Power, unless Mississippi Power accepted certain conditions on the issuance of the CPCN, including a cost cap of approximately $2.4 billion. Following additional proceedings, on May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order (1) approved an alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the cost of the lignite mine and equipment and the carbon dioxide pipeline facilities), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity; (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal; (3) approved financing cost recovery on construction work in progress (CWIP) balances, which provides for the accrual of AFUDC in 2010 and 2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives II-78 SoCo FOIA Response 002435 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the CPCN for the Kemper IGCC. On August 19, 2010, the National Environmental Policy Act (NEPA) Record of Decision (ROD) by the DOE for Mississippi Power’s CCPI2 grants was noted in the Federal Register. The NEPA ROD and its accompanying final environmental impact statement were the final major hurdles necessary for Mississippi Power to receive grand funds of $245 million during the construction of the plant and $25 million during the initial operation of the Kemper IGCC. As of December 31, 2010, Mississippi Power has received $23 million and billed an additional $9 million associated with this grant. In April 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more. Mississippi Power expects the Kemper IGCC, including the gasification portion, to be a qualifying project under the law. On June 17, 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant the CPCN for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). On December 22, 2010, the Chancery Court denied Mississippi Power’s motion to dismiss the suit. A decision on the Sierra Club’s appeal from the Chancery Court is expected in March 2011. In addition, in a separate proceeding, the Sierra Club has requested an evidentiary hearing regarding the issuance of a modified Prevention of Significant Deterioration air permit for the Kemper IGCC. Mississippi Power has been awarded certain tax credits available to projects using clean and advance coal technologies under the Energy Policy Act of 2005 (Phase I tax credits) and under the Energy Improvement and Extension Act of 2008 (Phase II tax credits). In November 2006, the IRS allocated $133 million of Phase I tax credits to Mississippi Power and in April 2010, the IRS allocated $279 million of Phase II tax credits to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 2014 for the Phase I credits. In order to remain eligible for the Phase II tax credits, Mississippi Power must also capture and sequester at least 65% of the carbon dioxide produced by the plant during operations in accordance with recapture rules for Section 48A tax credits. Through December 31, 2010, Mississippi Power received tax benefits of $22 million for these tax credits. In February 2008, Mississippi Power requested that the DOE transfer the remaining funds previously granted under the CCPI2 from a cancelled IGCC project of one of Southern Company’s affiliates that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. On July 27, 2010, Mississippi Power and South Mississippi Electric Power Association (SMEPA) entered into an Asset Purchase Agreement whereby SMEPA will purchase a 17.5% undivided ownership interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. On December 2, 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval for SMEPA’s 17.5% ownership of the Kemper IGCC. The Mississippi PSC has issued orders allowing Mississippi Power to defer the costs associated with the generation resource planning, evaluation, and screening activities for the Kemper IGCC as a regulatory asset. In addition, on November 12, 2010, Mississippi Power filed a petition with the Mississippi PSC requesting an accounting order that would establish regulatory assets for certain noncapital costs related to the Kemper IGCC. In its petition, Mississippi Power outlined three categories of non-capital, plant-related costs that it proposed to defer in a regulatory asset until construction is complete and a cost recovery mechanism is established for the Kemper IGCC: (1) regulatory costs; (2) cost of executing nonconstruction contracts; and (3) other project-related costs not permitted to be capitalized. As of December 31, 2010, Mississippi Power had spent a total of $255 million on the Kemper IGCC, including regulatory filing costs. Of this total, $208 million was included in CWIP (net of $33 million of CCPI2 grant funds), $12 million was recorded in other regulatory assets, $2 million was recorded in other deferred charges and assets, and $1 million was previously expensed. The ultimate outcome of these matters cannot be determined at this time. II-79 SoCo FOIA Response 002436 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report 4. JOINT OWNERSHIP AGREEMENTS Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and related facilities jointly with Power South Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with OPC, MEAG Power, the City of Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Florida Power Corporation for a combustion turbine unit at Intercession City, Florida. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. At December 31, 2010, Alabama Power’s, Georgia Power’s, and Southern Power’s percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation with the above entities were as follows: Percent Ownership Amount of Investment Accumulated Depreciation (in millions) Plant Vogtle (nuclear) Units 1 and 2 Plant Hatch (nuclear) Plant Miller (coal) Units 1 and 2 Plant Scherer (coal) Units 1 and 2 Plant Wansley (coal) Rocky Mountain (pumped storage) Intercession City (combustion turbine) Plant Stanton (combined cycle) Unit A 45.7% 50.1 $3,292 962 $1,935 534 91.8 1,253 477 8.4 53.5 25.4 33.3 148 700 175 12 74 208 109 3 65.0 156 25 At December 31, 2010, the portion of total construction work in progress related to Plants Miller, Scherer, Wansley, and Vogtle Units 3 and 4 was $125 million, $110 million, $11 million, and $1.3 billion, respectively. Construction at Plants Miller, Wansley, and Scherer relates primarily to environmental projects. See Note 3 under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” for information on Plant Vogtle Units 3 and 4. Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly owned facilities, except for Rocky Mountain and Intercession City, as agents for their respective co-owners. The companies’ proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing. 5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. II-80 SoCo FOIA Response 002437 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Current and Deferred Income Taxes Details of income tax provisions are as follows: 2010 2009 2008 (in millions) Federal – Current Deferred State – Current Deferred Total 42 898 940 $771 40 811 $628 177 805 (54) 140 86 $1,026 100 (15) 85 $896 72 38 110 $915 $ Net cash payments for income taxes in 2010, 2009, and 2008 were $276 million, $975 million, and $537 million, respectively. The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2009 2010 (in millions) Deferred tax liabilities – Accelerated depreciation Property basis differences Leveraged lease basis differences Employee benefit obligations Under recovered fuel clause Premium on reacquired debt Regulatory assets associated with employee benefit obligations Regulatory assets associated with asset retirement obligations Other Total Deferred tax assets – Federal effect of state deferred taxes State effect of federal deferred taxes Employee benefit obligations Over recovered fuel clause Other property basis differences Deferred costs Cost of removal Unbilled revenue Other comprehensive losses Asset retirement obligations Other Total Total deferred tax liabilities, net Portion included in prepaid expenses (accrued income taxes), net Deferred state tax assets Valuation allowance Accumulated deferred income taxes $6,833 1,150 263 485 179 78 814 509 246 10,557 $5,938 986 251 384 271 100 939 486 216 9,571 386 50 1,179 40 119 100 52 126 69 509 523 3,153 7,404 117 91 (58) $7,554 302 108 1,435 119 132 65 109 96 81 486 458 3,391 6,180 229 105 (59) $6,455 At December 31, 2010, Southern Company had a State of Georgia net operating loss (NOL) carryforward totaling $0.9 billion, which could result in net state income tax benefits of $53 million, if utilized. However, Southern Company has established a valuation allowance for the potential $53 million tax benefit due to the remote likelihood that the tax benefit will be realized. These NOLs expire between 2011 and 2021. Beginning in 2002, the State of Georgia allowed Southern Company to file a combined return, which has prevented the creation of any additional NOL carryforwards. At December 31, 2010, the tax-related regulatory assets and liabilities were $1.3 billion and $237 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than II-81 SoCo FOIA Response 002438 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report the current enacted tax law, and to taxes applicable to capitalized interest. In 2010, $82 million was deferred as a regulatory asset related to the impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (together, the Acts). The Acts eliminated the deductibility of healthcare costs that are covered by federal Medicare subsidy payments. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits. In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $23 million in 2010, $24 million in 2009, and $23 million in 2008. At December 31, 2010, all investment tax credits available to reduce federal income taxes payable had been utilized. On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013). The application of the bonus depreciation provisions in these acts in 2010 significantly increased deferred tax liabilities related to accelerated depreciation. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Federal statutory rate State income tax, net of federal deduction Employee stock plans dividend deduction Non-deductible book depreciation Difference in prior years’ deferred and current tax rate AFUDC-Equity Production activities deduction ITC basis difference Leveraged lease termination MC Asset Recovery Donations Other Effective income tax rate 2010 2009 2008 35.0% 1.8 (1.2) 0.8 (0.1) (2.2) (0.4) (0.2) 33.5% 35.0% 2.1 (1.4) 0.9 (0.1) (2.7) (0.7) (0.9) 2.7 (0.4) (0.1) 34.4% 35.0% 2.6 (1.3) 0.8 (0.2) (1.9) (0.4) (1.0) 33.6% Southern Company’s effective tax rate is lower than the statutory rate primarily due to the employee stock plans’ dividend deduction and AFUDC equity, which is not taxable. Southern Company’s 2010 effective tax rate decreased from 2009 primarily due to the $202 million charge recorded for the MC Asset Recovery litigation settlement in 2009, which completed and resolved all claims by MC Asset Recovery against Southern Company. Southern Company is currently evaluating potential recovery of the settlement payment through various means including insurance, claims in U.S. Bankruptcy Court, and other avenues. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. The ultimate outcome of any such recovery and/or income tax treatment cannot be determined at this time. The decrease in Southern Company’s effective tax rate was partially offset by the elimination of the production activities deduction in 2010. The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to Southern Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions, there was no domestic production deduction available to Southern Company for 2010. II-82 SoCo FOIA Response 002439 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Unrecognized Tax Benefits For 2010, the total amount of unrecognized tax benefits increased by $97 million, resulting in a balance of $296 million as of December 31, 2010. Changes during the year in unrecognized tax benefits were as follows: 2010 2009 2008 (in millions) Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions increase from prior periods Tax positions decrease from prior periods Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year $199 62 62 (27) $296 $146 53 12 (10) (2) $199 $264 49 130 (297) $146 The tax positions from current periods relate primarily to the Georgia state tax credits litigation, tax accounting method change for repairs, and other miscellaneous uncertain tax positions. The tax positions increase from prior periods relates primarily to the tax accounting method change for repairs and other miscellaneous positions. The tax positions decrease from prior periods relates primarily to the Georgia state tax credit litigation and miscellaneous tax positions. See Note 3 under “Income Tax Matters – Georgia State Income Tax Credits” and “Tax Method of Accounting for Repairs” for additional information. The impact on Southern Company’s effective tax rate, if recognized, is as follows: 2010 2009 2008 (in millions) Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits $217 79 $296 $199 $199 $143 3 $146 The tax positions impacting the effective tax rate primarily relate to Georgia state tax credit litigation at Georgia Power and the production activities deduction tax position. However, as discussed in Note 3 under “Income Tax Matters,” if Georgia Power is successful in its claim against the Georgia DOR, a significant portion of the tax benefit is expected to be deferred and returned to retail customers and therefore no material impact to net income is expected. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note 3 under “Income Tax Matters – Georgia State Income Tax Credits” and “Tax Method of Accounting for Repairs” for additional information. Accrued interest for unrecognized tax benefits was as follows: 2010 2009 2008 (in millions) Interest accrued at beginning of year Interest reclassified due to settlements Interest accrued during the year Balance at end of year $21 8 $29 $15 6 $21 $31 (49) 33 $15 Southern Company classifies interest on tax uncertainties as interest expense. The net amount of interest accrued during 2010 was primarily associated with the Georgia state tax credit litigation. Southern Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of Southern Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the Georgia state tax credit litigation would substantially reduce the balances. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. II-83 SoCo FOIA Response 002440 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report The IRS has audited and closed all tax returns prior to 2007. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006. 6. FINANCING Long-Term Debt Payable to Affiliated Trusts Certain of the traditional operating companies have formed certain wholly-owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the applicable traditional operating company through the issuance of junior subordinated notes totaling $412 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as long-term debt. Each traditional operating company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trust’s payment obligations with respect to these securities. At December 31, 2010, preferred securities of $400 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities. Securities Due Within One Year A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows: 2009 2010 (in millions) Pollution control revenue bonds Capitalized leases Senior notes Other long-term debt Total $ 8 23 600 670 $1,301 $ 21 1,090 2 $ 1,113 Maturities through 2015 applicable to total long-term debt are as follows: $1.3 billion in 2011; $1.8 billion in 2012; $1.7 billion in 2013; $441 million in 2014; and $1.2 billion in 2015. Bank Term Loans Certain of the traditional operating companies have entered into bank term loan agreements. In 2010, Mississippi Power entered into a one-year $125 million aggregate principal amount long-term floating rate bank loan that bears interest based on one-month London Interbank Offered Rate (LIBOR). The proceeds from this loan were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes, including Mississippi Power’s continuous construction program. At December 31, 2010 and 2009, certain of the traditional operating companies had outstanding bank term loans totaling $615 million and $490 million, respectively. Senior Notes Southern Company and its subsidiaries issued a total of $2.9 billion of senior notes in 2010. Southern Company issued $400 million, and the traditional operating companies’ combined issuances totaled $2.5 billion. The proceeds of these issuances were used to repay long-term and short-term indebtedness and for other general corporate purposes including the applicable subsidiary’s continuous construction program. At December 31, 2010 and 2009, Southern Company and its subsidiaries had a total of $15.2 billion and $14.7 billion, respectively, of senior notes outstanding. At December 31, 2010 and 2009, Southern Company had a total of $1.6 billion and $1.8 billion, respectively, of senior notes outstanding. Subsequent to December 31, 2010, Georgia Power issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay a portion of Georgia Power’s outstanding short-term indebtedness and for general corporate purposes, including Georgia Power’s continuous construction program. II-84 SoCo FOIA Response 002441 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Pollution Control and Other Revenue Bonds Pollution control obligations represent loans to the traditional operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The traditional operating companies have $3.1 billion of outstanding pollution control revenue bonds and are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. In December 2010, Mississippi Power incurred obligations relating to the issuance of $100 million of revenue bonds in two series, each of which is due December 1, 2040. The first series of $50 million was issued with an initial fixed rate of 2.25% through January 14, 2013 and the second series of $50 million was issued with a floating rate. Proceeds from the second series bonds were classified as restricted cash at December 31, 2010 and these bonds were redeemed on February 8, 2011. The proceeds from the first series bonds were used to finance the acquisition and construction of buildings and immovable equipment in connection with Mississippi Power’s construction of the Kemper IGCC. Assets Subject to Lien Each of Southern Company’s subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. Alabama Power and Gulf Power have granted one or more liens on certain of their respective property in connection with the issuance of certain pollution control revenue bonds with an outstanding principal amount of $194 million. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. Bank Credit Arrangements The following table outlines the credit arrangements by company: Executable Term-Loans Company Total Unused One Year Two Years Expires 2011 (in millions) Southern Company Alabama Power Georgia Power Gulf Power Mississippi Power Southern Power Other Total (a) $ 950 1,271 1,715 240 161 400 60 $4,797 $ 950 1,271 1,703 240 161 400 60 $4,785 2012 2013 Expires Within One Year(a) Term No Term Loan Loan Option Option (in millions) $ 372 220 210 65 60 $927 $ 40 41 $81 $ 506 595 240 161 60 $1,562 $950 $ 765 1,120 400 $ 3,235 $ (in millions) - $ 372 260 210 106 60 $1,008 $ 134 335 30 55 $554 Reflects facilities expiring on or before December 31, 2011. All of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average approximately ½ of 1% or less for Southern Company, the traditional operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal. Most of the credit arrangements with banks have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities. At December 31, 2010, Southern Company, Southern Power, and the traditional operating companies were each in compliance with their respective debt limit covenants. II-85 SoCo FOIA Response 002442 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report In addition, the credit arrangements typically contain cross default provisions that would be triggered if the borrower defaulted on other indebtedness above a specified threshold. The cross default provisions are restricted only to the indebtedness, including any guarantee obligations, of the company that has such credit arrangements. Southern Company and its subsidiaries are currently in compliance with all such covenants. A portion of the $4.8 billion unused credit with banks is allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2010 was approximately $1.3 billion. Subsequent to December 31, 2010, Georgia Power’s remarketing of $137 million of puttable variable rate pollution control bonds increased the total requiring liquidity support to $522 million. Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of committed bank credit arrangements. Southern Company and the traditional operating companies may also borrow through various other arrangements with banks. The amount of short-term bank loans included in notes payable in the balance sheets at December 31, 2010 was $1 million. There were no short term-bank loans included in notes payable in the balance sheets at December 31, 2009. At December 31, 2010, the Southern Company system had approximately $1.3 billion of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During 2010, Southern Company had an average of $690 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $1.3 billion. At December 31, 2009, the Southern Company system had approximately $638 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During 2009, Southern Company had an average of $956 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $1.4 billion. Changes in Redeemable Preferred Stock of Subsidiaries Each of the traditional operating companies has issued preferred and/or preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary’s board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as “Redeemable Preferred Stock of Subsidiaries” in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision that would allow the holders to elect a majority of such subsidiary’s board. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are required to be shown as “noncontrolling interest,” separately presented as a component of “Stockholders’ Equity” on Southern Company’s balance sheets, statements of capitalization, and statements of stockholders’ equity. The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company: Redeemable Preferred Stock of Subsidiaries (in millions) $498 (125) 2 $375 $375 $375 Balance at December 31, 2007 Issued Redeemed Other Balance at December 31, 2008 Issued Redeemed Balance at December 31, 2009 Issued Redeemed Balance at December 31, 2010 II-86 SoCo FOIA Response 002443 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report 7. COMMITMENTS Construction Program The construction programs of the Company’s subsidiaries are currently estimated to include a base level investment of $4.9 billion in 2011, $5.1 billion in 2012, and $4.5 billion in 2013. These amounts include $335 million, $207 million, and $220 million in 2011, 2012, and 2013, respectively, for construction expenditures related to contractual purchase commitments for nuclear fuel included herein under “Fuel and Purchased Power Commitments.” Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. The capital budget amounts for 2011-2013 include amounts for the construction of Plant Vogtle Units 3 and 4. Of the estimated total $4.4 billion in capital costs for Plant Vogtle Units 3 and 4, approximately $943 million is expected to be incurred from 2014 through 2017. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirement and replacement decisions, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2010, significant purchase commitments were outstanding in connection with the ongoing construction program, which includes new facilities and capital improvements to transmission, distribution, and generation facilities, including those to meet environmental standards. See Note 3 under “Retail Regulatory Matters – Georgia Power – Nuclear Construction,” “Retail Regulatory Matters – Georgia Power – Other Construction,” and “Retail Regulatory Matters – Mississippi Power Integrated Coal Gasification Combined Cycle” for additional information. Long-Term Service Agreements The traditional operating companies and Southern Power have entered into long-term service agreements (LTSAs) with General Electric (GE), Alstom Power, Inc., Mitsubishi Power Systems Americas, Inc., and Siemens AG for the purpose of securing maintenance support for the combined cycle and combustion turbine generating facilities owned or under construction by the subsidiaries. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs are also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments under the LTSAs, which are subject to price escalation, are made at various intervals based on actual operating hours or number of gas turbine starts of the respective units. Total remaining payments under these agreements for facilities owned are currently estimated at $2.1 billion over the remaining life of the agreements, which are currently estimated to range up to 23 years. However, the LTSAs contain various cancellation provisions at the option of the purchasers. Georgia Power has also entered into a LTSA with GE through 2014 for neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently estimated at $6 million. The contract contains cancellation provisions at the option of Georgia Power. Payments made under the LTSAs prior to the performance of any work are recorded as a prepayment in the balance sheets. All work performed is capitalized or charged to expense (net of any joint owner billings), as appropriate based on the nature of the work. Limestone Commitments As part of Southern Company’s program to reduce sulfur dioxide emissions from its coal plants, the traditional operating companies have entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. Southern Company has a minimum contractual obligation of 6.9 million tons, equating to approximately $282 million, through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $39 million in 2011, $40 million in 2012, $42 million in 2013, $43 million in 2014, and $29 million in 2015. II-87 SoCo FOIA Response 002444 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Fuel and Purchased Power Commitments To supply a portion of the fuel requirements of the generating plants, Southern Company has entered into various long-term commitments for the procurement of fossil, biomass fuel, and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emissions allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2010. Also, Southern Company has entered into various long-term commitments for the purchase of capacity and electricity. Total estimated minimum long-term obligations at December 31, 2010 were as follows: Natural Gas Commitments Nuclear Fuel Biomass Fuel Coal Purchased Power* (in millions) 2011 2012 2013 2014 2015 2016 and thereafter Total $1,357 1,226 1,054 908 779 3,413 $8,737 $ 3,810 1,882 1,362 873 783 1,798 $10,508 $ 335 207 220 208 141 807 $1,918 $ 14 18 18 18 110 $178 $ 260 269 237 268 291 2,439 $3,764 *Certain PPAs reflected in the table are accounted for as operating leases. Additional commitments for fuel will be required to supply Southern Company’s future needs. Total charges for nuclear fuel included in fuel expense amounted to $184 million in 2010, $160 million in 2009, and $147 million in 2008. Coal commitments for Mississippi Power include a minimum annual management fee of $38 million beginning in 2014 from the executed 40-year management contract with Liberty Fuels, LLC related to the Kemper IGCC. Operating Leases In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership whose investors are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease agreement is treated as an operating lease for accounting purposes as well as for both retail and wholesale rate recovery purposes. The initial lease term ends in 2011, and the lease includes a purchase and renewal option based on the cost of the facility at the inception of the lease. Mississippi Power is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. In April 2010, Mississippi Power was required to notify the lessor, Juniper, if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the Plant Daniel combined cycle generating units for approximately $354 million or renew the lease for approximately $31 million annually for 10 years. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. If the lease is renewed, the agreement calls for Mississippi Power to amortize an additional 17% of the initial completion cost over the renewal period. Upon termination of the lease, at Mississippi Power’s option, it may either exercise its purchase option or the facility can be sold to a third party. If Mississippi Power does not exercise either its purchase option or its renewal option, Mississippi Power could lose its rights to some or all of the 1,064 MWs of capacity at that time. The ultimate outcome of this matter cannot be determined at this time. The lease provides for a residual value guarantee, approximately 73% of the acquisition cost, by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the asset. A liability of approximately $2 million, $3 million, and $5 million for the fair market value of this residual value guarantee is included in the balance sheets as of December 31, 2010, 2009, and 2008, respectively. Southern Company also has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $188 million, $186 million, and $184 million for 2010, 2009, and 2008, respectively. Southern Company includes any step II-88 SoCo FOIA Response 002445 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. At December 31, 2010, estimated minimum lease payments for noncancelable operating leases were as follows: Plant Daniel Minimum Lease Payments Barges & Rail Cars Other Total (in millions) 2011 2012 2013 2014 2015 2016 and thereafter Total $28 $28 $ 74 58 48 39 14 16 $249 $ 52 35 29 24 17 87 $244 $154 93 77 63 31 103 $521 For the traditional operating companies, a majority of the barge and rail car lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2011, 2012, 2013, 2014, 2015, and 2016 and the maximum obligations under these leases are $40 million, $1 million, $39 million, $8 million, $5 million, and $4 million, respectively. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations. Guarantees As discussed earlier in this Note under “Operating Leases,” Alabama Power, Georgia Power, and Mississippi Power have entered into certain residual value guarantees. 8. COMMON STOCK Stock Issued During 2010, Southern Company issued 19.6 million shares of common stock for $629 million through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued 4.1 million shares of common stock through at-themarket issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $143 million, net of $1 million in fees and commissions. In 2009, Southern Company raised $673 million from the issuance of 22.6 million new common shares through the Southern Investment Plan and employee and director stock plans. In 2009, Southern Company issued 19.9 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $613 million, net of $6 million in fees and commissions. Shares Reserved At December 31, 2010, a total of 66 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (which includes stock options and performance shares units as discussed below). Of the total 66 million shares reserved, there were 10 million shares of common stock remaining available for awards under the stock option and performance share plans as of December 31, 2010. Stock Option Plan Southern Company provides non-qualified stock options to a large segment of Southern Company system employees ranging from line management to executives. As of December 31, 2010, there were 7,330 current and former employees participating in the stock option plan. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of II-89 SoCo FOIA Response 002446 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting. The estimated fair values of stock options granted in 2010, 2009, and 2008 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Dividend yield Weighted average grant-date fair value 2010 17.4% 5.0 2.4% 5.6% $2.23 2009 15.6% 5.0 1.9% 5.4% $1.80 2008 13.1% 5.0 2.8% 4.5% $2.37 Southern Company’s activity in the stock option plan for 2010 is summarized below: Outstanding at December 31, 2009 Granted Exercised Cancelled Outstanding at December 31, 2010 Exercisable at December 31, 2010 Shares Subject To Option 48,247,319 9,582,288 (7,024,176) (93,845) 50,711,586 34,564,434 Weighted Average Exercise Price $32.10 31.22 28.15 31.02 $32.48 $32.81 The number of stock options vested, and expected to vest in the future, as of December 31, 2010 was not significantly different from the number of stock options outstanding at December 31, 2010 as stated above. As of December 31, 2010, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $292 million and $188 million, respectively. As of December 31, 2010, there was $5 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months. For the years ended December 31, 2010, 2009, and 2008, total compensation cost for stock option awards recognized in income was $22 million, $23 million, and $20 million, respectively, with the related tax benefit also recognized in income of $9 million, $9 million, and $8 million, respectively. The total intrinsic value of options exercised during the years ended December 31, 2010, 2009, and 2008 was $57 million, $9 million, and $45 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $22 million, $4 million, and $17 million for the years ended December 31, 2010, 2009, and 2008, respectively. Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2010, 2009, and 2008 was $198 million, $19 million, and $113 million, respectively. Performance Share Plan In 2010, Southern Company implemented the performance share program under its omnibus incentive compensation plan, which provides performance share award units to a large segment of Southern Company system employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on II-90 SoCo FOIA Response 002447 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Southern Company’s total shareholder return (TSR) over the three-year performance period which measures Southern Company’s relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company’s actual TSR and may range from 0% to 200% of the original target performance share amount. The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company’s stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. Expected volatility used in the model of 20.7% was based on historical volatility of Southern Company’s stock over a period equal to the performance period. The risk-free rate of 1.4% was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units. The annualized dividend rate at the time of the grant was $1.75. During 2010, 1,050,052 performance share units were granted with a weighted-average grant date fair value of $30.13. During 2010, 141,711 performance share units were forfeited resulting in 908,341 unvested units outstanding at December 31, 2010. For the year ended December 31, 2010, total compensation cost for performance share units recognized in income was $9 million, with the related tax benefit also recognized in income of $4 million. As of December 31, 2010, there was $18 million of total unrecognized compensation cost related to performance share award units that will be recognized over the next two years. Diluted Earnings Per Share For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows: Average Common Stock Shares 2009 2008 2010 (in thousands) As reported shares Effect of options Diluted shares 832,189 4,792 836,981 794,795 1,620 796,415 771,039 3,809 774,848 Stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive were 13.1 million and 37.7 million at December 31, 2010 and 2009, respectively. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options would have increased by 0.8 million and 3.4 million shares for the years ended December 31, 2010 and 2009, respectively. Common Stock Dividend Restrictions The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2010, consolidated retained earnings included $5.9 billion of undistributed retained earnings of the subsidiaries. Southern Power’s credit facility contains potential limitations on the payment of common stock dividends; as of December 31, 2010, Southern Power was in compliance with all such requirements. 9. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies’ nuclear power plants. The Act provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of $17.5 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests, is $235 million and $237 million, respectively, per incident, but not more than an aggregate of $35 million per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013. II-91 SoCo FOIA Response 002448 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ operating nuclear generating facilities. Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Alabama Power and Georgia Power each purchase the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period. A builders’ risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion in limits for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $42 million and $70 million, respectively. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. 10. FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.    Level 1 consists of observable market data in an active market for identical assets or liabilities. Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. II-92 SoCo FOIA Response 002449 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives Interest rate derivatives Foreign currency derivatives Nuclear decommissioning trusts:(a) Domestic equity U.S. Treasury and government agency securities Municipal bonds Corporate bonds Mortgage and asset backed securities Other Cash equivalents and restricted cash Other Total Liabilities: Energy-related derivatives Interest rate derivatives Total $ - $ 10 10 3 $ - $ 10 10 3 604 20 351 9 $984 60 220 53 220 119 74 51 $820 19 $ 19 664 240 53 220 119 74 351 79 $1,823 $$- $206 1 $207 $$- $206 1 $207 (a) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under “Nuclear Decommissioning” for additional information. Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note 11 for additional information on how these derivatives are used. “Other investments” include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions. For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics. A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit II-93 SoCo FOIA Response 002450 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts’ judgment are also obtained when available. As of December 31, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: As of December 31, 2010: Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period $ 65 67 86 None None None Daily Daily Daily 351 None Daily Not applicable 2 None Daily Not applicable (in millions) Nuclear decommissioning trusts: Corporate bonds – commingled funds Other – commingled funds Trust-owned life insurance Cash equivalents and restricted cash: Money market funds Other: Money market funds 1 to 3 days Not applicable 15 days The commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset rate date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The corporate bonds – commingled funds represent the investment of cash collateral received under the Funds’ managers’ securities lending program that can only be sold upon the return of the loaned securities. See Note 1 under “Nuclear Decommissioning” for additional information. Alabama Power’s nuclear decommissioning trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the Securities and Exchange Commission and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company’s investment in the money market funds. II-94 SoCo FOIA Response 002451 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for the year ended December 31, 2010 were as follows: Level 3 Other (in millions) Beginning balance at December 31, 2009 Total gains (losses) - realized/unrealized: Included in earnings Included in OCI Transfers out of Level 3 Ending balance at December 31, 2010 $35 (1) 5 (20) $19 Transfers in and out of the levels of fair value hierarchy are recognized as of the end of the reporting period. The value of one of the investments was reclassified from Level 3 to Level 1 because the securities began trading on the public market. The reclassification is reflected in the table above as a transfer out of Level 3 at its fair value. As of December 31, 2010 and 2009, other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt: 2010 2009 $19,356 $19,145 $20,073 $19,567 The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). 11. DERIVATIVES Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company’s policies in areas such as counterparty exposure and risk management practices. Each company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities. Energy-Related Derivatives The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts. Certain of the traditional operating companies have recently started using significantly more financial options per the guidelines of their respective PSCs, which is expected to continue to mitigate price volatility. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the electric utilities may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the electric utilities may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. II-95 SoCo FOIA Response 002452 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Energy-related derivative contracts are accounted for in one of three methods:    Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies’ fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2010, the net volume of energy-related derivative contracts for power and natural gas positions for the Southern Company system, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Power Longest Net Sold Hedge Megawatt-hours Date Longest Non-Hedge Date (in millions) 1 Net Purchased mmBtu* Gas Longest Hedge Date Longest Non-Hedge Date 2015 2015 (in millions) 2011 2011 149 * million British thermal units In addition to the volumes discussed in the tables above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 4 million mmBtu. For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending December 31, 2011 are immaterial for Southern Company. Interest Rate Derivatives Southern Company and certain subsidiaries also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings, providing an offset with any difference representing ineffectiveness. II-96 SoCo FOIA Response 002453 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report At December 31, 2010, the following interest rate derivatives were outstanding: Notional Amount Interest Rate Received Interest Rate Paid Hedge Maturity Date (in millions) (in millions) Cash flow hedges of existing debt $300 3-month LIBOR + 0.40% spread Fair value hedges of existing debt 350 4.15% Total Fair Value Gain (Loss) December 31, 2010 1.24%* October 2011 3-month LIBOR + 1.96%* spread May 2014 $650 $(1) 10 $ 9 * Weighted Average For the year ended December 31, 2010, the Company had realized net gains of $2 million upon termination of certain interest rate derivatives at the same time the related debt was issued. The effective portion of these gains has been deferred in OCI and is being amortized to interest expense over the life of the original interest rate derivative, reflecting the period in which the forecasted hedged transaction affects earnings. Subsequent to December 31, 2010, Alabama Power entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million. The estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2011 is $17 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2037. Foreign Currency Derivatives Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives’ fair value gains or losses and the hedged items’ fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 2010, the following foreign currency derivatives were outstanding: Notional Amount Forward Rate Hedge Maturity Date (in millions) Fair Value Gain (Loss) December 31, 2010 (in millions) Cash flow hedges of forecasted transactions YEN82 85.326 Yen per Dollar* Fair value hedges of firm commitments EUR41.1 1.256 Dollars per Euro* Total Various through May 2011 $- Various through July 2012 3 $3 * Weighted Average II-97 SoCo FOIA Response 002454 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Derivative Financial Statement Presentation and Amounts At December 31, 2010 and 2009, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows: Derivative Category Asset Derivatives Balance Sheet Location 2010 Liability Derivatives Balance Sheet Location 2010 2009 (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets Other deferred charges and assets Total derivatives designated as hedging instruments for regulatory purposes Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Interest rate derivatives: Foreign currency derivatives: Other current assets Other current assets Other deferred charges and assets Other current assets Other deferred charges and assets Total derivatives designated as hedging instruments in cash flow and fair value hedges Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets Other deferred charges and assets Total derivatives not designated as hedging instruments Total 2009 (in millions) $4 $1 3 1 $7 $2 $- $3 6 3 4 - 2 - 1 - $13 $6 $2 $ 2 1 - $3 $23 $2 $10 Liabilities from risk management activities Other deferred credits and liabilities Liabilities from risk management activities Liabilities from risk management activities Other deferred credits and liabilities Liabilities from risk management activities Other deferred credits and liabilities Liabilities from risk management activities Other deferred credits and liabilities $145 $111 55 66 $200 $177 $1 $5 1 6 - - - - - - $2 $11 $5 $ 3 - - $5 $207 $3 $191 All derivative instruments are measured at fair value. See Note 10 for additional information. II-98 SoCo FOIA Response 002455 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report At December 31, 2010 and 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: Unrealized Losses Balance Sheet Location 2010 Derivative Category 2009 Unrealized Gains Balance Sheet Location 2010 (in millions) Energy-related derivatives: Other regulatory assets, current Other regulatory assets, deferred Total energy-related derivative gains (losses) $(145) $(111) (55) $(200) (66) $(177) 2009 (in millions) Other regulatory liabilities, current Other regulatory liabilities, deferred $4 $1 3 $7 1 $2 For the twelve months ended December 31, 2010, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statement of income were $10 million. This amount was offset with changes in the fair value of the hedged debt. For the twelve months ended December 31, 2010, the pre-tax gains from foreign currency derivatives designated as fair value hedging instruments on Southern Company’s statement of income were $3 million. These amounts were offset with changes in the fair value of the purchase commitment related to equipment purchases. For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Hedging Relationships Derivative Category Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount 2009 2008 Statements of Income Location 2010 Gain (Loss) Recognized in OCI on Derivative (Effective Portion) 2009 2008 2010 (in millions) (in millions) Energy-related derivatives Interest rate derivatives $1 (3) $(2) (5) $(1) (47) Foreign currency derivatives Total 1 $(1) $(7) $(48) Fuel Interest expense, net of amounts capitalized Other operations and maintenance $ - $ - $ - (25) 1 $ (24) (46) $(46) (19) $(19) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was as follows: Derivatives not Designated as Hedging Instruments Derivative Category Unrealized Gain (Loss) Recognized in Income Amount 2009 Statements of Income Location 2010 2008 (in millions) Energy-related derivatives: Wholesale revenues Fuel Purchased power Total $(2) 1 (1) $(2) $5 (6) (4) $(5) $ (2) 5 (2) $1 II-99 SoCo FOIA Response 002456 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2010, the fair value of derivative liabilities with contingent features was $40 million. At December 31, 2010, the Company had no collateral posted with its derivative counterparties. The maximum potential collateral requirement arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $40 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. II-100 SoCo FOIA Response 002457 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report 12. SEGMENT AND RELATED INFORMATION Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Southern Power’s revenues from sales to the traditional operating companies were $371 million, $544 million, and $638 million in 2010, 2009, and 2008, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications, renewable energy projects, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows: Electric Utilities Traditional Operating Companies Southern Power Eliminations Total All Other Eliminations Consolidated (in millions) 2010 Operating revenues Depreciation and amortization Interest income Interest expense Income taxes Segment net income (loss)* Total assets Gross property additions 2009 Operating revenues Depreciation and amortization Interest income Interest expense Income taxes Segment net income (loss)* Total assets Gross property additions 2008 Operating revenues Depreciation and amortization Interest income Interest expense Income taxes Segment net income (loss)* Total assets Gross property additions $16,713 1,375 22 757 1,039 1,859 51,145 4,029 $15,304 1,378 21 749 902 1,679 48,403 4,568 $16,521 1,325 32 689 944 1,703 44,794 4,058 $1,129 119 76 77 130 3,276 300 $(468) (128) - $17,374 1,494 22 833 1,116 1,989 54,293 4,329 $162 19 3 62 (90) (10) 1,279 114 $(80) (1) (4) (540) - $17,456 1,513 24 895 1,026 1,975 55,032 4,443 $ 947 98 85 86 156 3,043 331 $(609) (143) $ 165 27 3 71 (92) (193) 1,223 14 $(64) (1) 1 (480) - $15,642 1,476 21 834 988 1,835 51,303 4,899 $15,743 1,503 23 905 896 1,643 52,046 4,913 $(835) (139) - $17,000 1,414 33 772 1,037 1,847 47,468 4,108 $ 182 29 94 (122) (104) 1,407 14 $ 1,314 89 1 83 93 144 2,813 50 $ (55) (1) (528) - $17,127 1,443 33 866 915 1,742 48,347 4,122 *After dividends on preferred and preference stock of subsidiaries Products and Services Year Retail Electric Utilities’ Revenues Wholesale Other Total (in millions) 2010 2009 2008 $14,791 13,307 14,055 $1,994 1,802 2,400 $589 533 545 $17,374 15,642 17,000 II-101 SoCo FOIA Response 002458 NOTES (continued) Southern Company and Subsidiary Companies 2010 Annual Report 13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial data for 2010 and 2009 are as follows: Quarter Ended Operating Revenues March 2010 June 2010 September 2010 December 2010 $4,157 4,208 5,320 3,771 March 2009 June 2009 September 2009 December 2009 $3,666 3,885 4,682 3,510 Operating Income Consolidated Per Common Share Net Income After Dividends on Trading Preferred and Price Range Preference Stock Basic of Subsidiaries Earnings Dividends High Low (in millions) $ 922 951 1,459 470 $ 490 886 1,415 477 $495 510 817 153 $0.60 0.62 0.98 0.18 $0.4375 0.4550 0.4550 0.4550 $33.73 35.45 37.73 38.62 $30.85 32.04 33.00 37.10 $126* 478 790 249 $0.16* 0.61 0.99 0.31 $0.4200 0.4375 0.4375 0.4375 $37.62 32.05 32.67 34.47 $26.48 27.19 30.27 30.89 Southern Company’s business is influenced by seasonal weather conditions. * Southern Company’s MC Asset Recovery litigation settlement reduced earnings by $202 million, or 25 cents per share, during the first quarter 2009. II-102 SoCo FOIA Response 002459 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA For the Periods Ended December 2006 through 2010 Southern Company and Subsidiary Companies 2010 Annual Report 2010 Operating Revenues (in millions) $17,456 $55,032 Total Assets (in millions) Gross Property Additions (in millions) $4,443 12.71 Return on Average Common Equity (percent) Cash Dividends Paid Per Share of Common Stock $1.8025 Consolidated Net Income After Dividends on Preferred and Preference $1,975 Stock of Subsidiaries (in millions) Earnings Per Share -Basic $2.37 Diluted 2.36 Capitalization (in millions): Common stock equity $ 16,202 Preferred and preference stock of subsidiaries 707 Redeemable preferred stock of subsidiaries 375 Long-term debt 18,154 Total (excluding amounts due within one year) $35,438 Capitalization Ratios (percent): Common stock equity 45.7 Preferred and preference stock of subsidiaries 2.0 Redeemable preferred stock of subsidiaries 1.1 Long-term debt 51.2 Total (excluding amounts due within one year) 100.0 Other Common Stock Data: Book value per share $19.21 Market price per share: High $38.62 Low 30.85 Close (year-end) 38.23 Market-to-book ratio (year-end) (percent) 199.0 Price-earnings ratio (year-end) (times) 16.1 Dividends paid (in millions) $1,496 Dividend yield (year-end) (percent) 4.7 Dividend payout ratio (percent) 75.7 Shares outstanding (in thousands): Average 832,189 Year-end 843,340 Stockholders of record (year-end) 160,426* Traditional Operating Company Customers (year-end) (in thousands): Residential 3,813 Commercial 580 Industrial 15 Other 9 Total 4,417 Employees (year-end) 25,940 2009 2008 2007 2006 $15,743 $52,046 $4,913 11.67 $1.7325 $17,127 $48,347 $4,122 13.57 $1.6625 $15,353 $45,789 $3,658 14.60 $1.595 $14,356 $42,858 $3,072 14.26 $1.535 $1,643 $1,742 $1,734 $1,573 $2.07 2.06 $2.26 2.25 $2.29 2.28 $2.12 2.10 $ 14,878 707 375 18,131 $34,091 $13,276 707 375 16,816 $31,174 $ 12,385 707 373 14,143 $27,608 $ 11,371 246 498 12,503 $24,618 43.6 2.1 1.1 53.2 100.0 42.6 2.3 1.2 53.9 100.0 44.9 2.6 1.3 51.2 100.0 46.2 1.0 2.0 50.8 100.0 $18.15 $17.08 $16.23 $15.24 $37.62 26.48 33.32 183.6 16.1 $1,369 5.2 83.3 $40.60 29.82 37.00 216.6 16.4 $1,279 4.5 73.5 $39.35 33.16 38.75 238.8 16.9 $1,204 4.1 69.5 $37.40 30.48 36.86 241.9 17.4 $1,140 4.2 72.4 794,795 819,647 92,799 771,039 777,192 97,324 756,350 763,104 102,903 743,146 746,270 110,259 3,798 580 15 9 4,402 26,112 3,785 594 15 8 4,402 27,276 3,756 600 15 6 4,377 26,472 3,706 596 15 5 4,322 26,091 * In July 2010, Southern Company changed its transfer agent from Southern Company Services, Inc. to Mellon Investor Services LLC. The change in the number of stockholders of record is primarily attributed to the calculation methodology used by Mellon Investor Services LLC. II-103 SoCo FOIA Response 002460 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA For the Periods Ended December 2006 through 2010 Southern Company and Subsidiary Companies 2010 Annual Report Operating Revenues (in millions): Residential Commercial Industrial Other Total retail Wholesale Total revenues from sales of electricity Other revenues Total Kilowatt-Hour Sales (in millions): Residential Commercial Industrial Other Total retail Wholesale sales Total Average Revenue Per Kilowatt-Hour (cents): Residential Commercial Industrial Total retail Wholesale Total sales Average Annual Kilowatt-Hour Use Per Residential Customer Average Annual Revenue Per Residential Customer Plant Nameplate Capacity Ratings (year-end) (megawatts) Maximum Peak-Hour Demand (megawatts): Winter Summer System Reserve Margin (at peak) (percent) Annual Load Factor (percent) Plant Availability (percent): Fossil-steam Nuclear Source of Energy Supply (percent): Coal Nuclear Hydro Oil and gas Purchased power Total 2010 2009 2008 2007 2006 $ 6,319 5,252 3,097 123 14,791 1,994 16,785 671 $17,456 $ 5,481 4,901 2,806 119 13,307 1,802 15,109 634 $15,743 $ 5,476 5,018 3,445 116 14,055 2,400 16,455 672 $17,127 $5,045 4,467 3,020 107 12,639 1,988 14,627 726 $15,353 $4,716 4,117 2,866 102 11,801 1,822 13,623 733 $14,356 57,798 55,492 49,984 943 164,217 32,570 196,787 51,690 53,526 46,422 953 152,591 33,503 186,094 52,262 54,427 52,636 934 160,259 39,368 199,627 53,326 54,665 54,662 962 163,615 40,745 204,360 52,383 52,987 55,044 920 161,334 38,460 199,794 10.60 9.16 6.04 8.72 5.38 8.12 10.48 9.22 6.54 8.77 6.10 8.24 9.46 8.17 5.52 7.72 4.88 7.16 9.00 7.77 5.21 7.31 4.74 6.82 15,176 13,607 13,844 14,263 14,235 $1,659 $1,443 $1,451 $1,349 $1,282 42,963 42,932 42,607 41,948 41,785 35,593 36,321 23.3 62.2 33,519 34,471 26.4 60.6 32,604 37,166 15.3 58.7 31,189 38,777 11.2 57.6 30,958 35,890 17.1 60.8 91.4 92.1 91.3 90.1 90.5 91.3 90.5 90.8 89.3 91.5 55.0 14.1 2.5 23.7 4.7 100.0 54.7 14.9 3.9 22.5 4.0 100.0 64.0 14.0 1.4 15.4 5.2 100.0 67.1 13.4 0.9 15.0 3.6 100.0 67.2 14.0 1.9 12.9 4.0 100.0 10.93 9.46 6.20 9.01 6.12 8.53 II-104 SoCo FOIA Response 002461 ALABAMA POWER COMPANY FINANCIAL SECTION 105 SoCo FOIA Response 002462 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Alabama Power Company 2010 Annual Report The management of Alabama Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010. Charles D. McCrary President and Chief Executive Officer Philip C. Raymond Executive Vice President, Chief Financial Officer, and Treasurer February 25, 2011 II-106 SoCo FOIA Response 002463 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Alabama Power Company We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2010 and 2009, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule of the Company listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements (pages II-133 to II-177) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. Birmingham, Alabama February 25, 2011 II-107 SoCo FOIA Response 002464 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Alabama Power Company 2010 Annual Report OVERVIEW Business Activities Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located in the State of Alabama in addition to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. Key Performance Indicators In striving to maximize shareholder value while providing cost-effective energy to more than 1.4 million customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The fossil/hydro 2010 Peak Season EFOR was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The performance for 2010 was better than the target for these reliability measures. Net income after dividends on preferred and preference stock is the primary measure of the Company’s financial performance. The Company’s 2010 results compared with its targets for some of these key indicators are reflected in the following chart: Key Performance Indicator Customer Satisfaction Peak Season EFOR – fossil/hydro Net Income After Dividends on Preferred and Preference Stock 2010 Target Performance Top quartile in customer surveys 5.06% or less 2010 Actual Performance $696 million $707 million Top quartile 1.22% See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2010 reflects the continued emphasis that management places on these indicators, as well as the commitment shown by employees in achieving or exceeding management’s expectations. Earnings The Company’s 2010 net income after dividends on preferred and preference stock of $707 million increased $37 million (5.5%) over the prior year. The increase was primarily due to increases in rates under the rate stabilization and equalization plan (Rate RSE) and the rate certificated new plant environmental (Rate CNP Environmental) that took effect January 2010, colder weather in the first and fourth quarters 2010, and warmer weather in the second and third quarters 2010. The increases in retail revenues were partially offset by increases in operations and maintenance expenses, increases in depreciation and amortization, and reductions in wholesale revenues from sales to non-affiliates and allowance for funds used during construction (AFUDC) equity. The Company’s net income after dividends on preferred and preference stock of $670 million in 2009 increased $54 million (8.8%) over the prior year. The increase was primarily due to the corrective rate package providing for adjustments associated with customer charges to certain existing rate structures effective in January 2009, a decrease in other operations and maintenance expenses, and an II-108 SoCo FOIA Response 002465 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report increase in AFUDC equity. The increase was partially offset by an overall decline in base rate revenues attributable to a decline in kilowatt-hour (KWH) sales, resulting from a recessionary economy and unfavorable weather conditions. The Company’s net income after dividends on preferred and preference stock of $616 million in 2008 increased $36 million (6.2%) over the prior year. This improvement was primarily due to an increase in retail base rate revenues resulting from an increase in rates under the Rate RSE and the Rate CNP Environmental that took effect January 1, 2008, partially offset by higher non-fuel operating expenses and depreciation. RESULTS OF OPERATIONS A condensed income statement for the Company follows: Amount 2010 Increase (Decrease) from Prior Year 2009 2008 2010 $5,976 1,851 280 1,418 606 332 4,487 1,489 (280) 463 746 39 $ 707 $447 27 (27) 207 61 10 278 169 (53) 79 37 $ 37 (in millions) Operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Total other income and (expense) Income taxes Net income Dividends on preferred and preference stock Net income after dividends on preferred and preference stock $(548) (360) (231) (48) 25 15 (599) 51 19 16 54 $ 54 $717 422 100 73 48 20 663 54 2 17 39 3 $ 36 Operating Revenues Operating revenues for 2010 were $6.0 billion, reflecting a $447 million increase from 2009. The following table summarizes the principal factors that have affected operating revenues for the past three years: 2010 Amount 2009 2008 (in millions) Retail – prior year Estimated change in – Rates and pricing Sales growth (decline) Weather Fuel and other cost recovery Retail – current year Wholesale revenues – Non-affiliates Affiliates Total wholesale revenues Other operating revenues Total operating revenues Percent change $4,497 $4,862 $4,407 310 (11) 199 81 5,076 174 (109) (12) (418) 4,497 246 26 (70) 253 4,862 465 236 701 199 $5,976 8.1% 620 237 857 175 $5,529 (9.0)% 712 308 1,020 195 $6,077 13.4% II-109 SoCo FOIA Response 002466 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Retail revenues in 2010 were $5.1 billion. These revenues increased $579 million (12.9%) in 2010, decreased $365 million (7.5%) in 2009, and increased $455 million (10.3%) in 2008. The increase in 2010 was due to increases in rates and pricing under Rate RSE and Rate CNP Environmental that took effect January 2010, colder weather in the first and fourth quarters 2010, and warmer weather in the second and third quarters 2010. The decrease in 2009 was due to decreased fuel revenue and a decline in KWH sales, partially offset by the corrective rate package providing for adjustments associated with customer charges to certain existing rate structures. The increase in 2008 was primarily due to an increase in fuel revenue and a base rate increase of 5.6%. See FUTURE EARNINGS POTENTIAL – “PSC Matters” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather. Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information. Wholesale revenues from sales to non-affiliated utilities were as follows: 2010 2009 2008 (in millions) Unit power sales – Capacity Energy Total Other power sales – Capacity and other Energy Total Total non-affiliated $ 84 95 179 $158 207 365 $160 238 398 148 138 286 $465 133 122 255 $620 134 180 314 $712 Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to Florida utilities and sales to wholesale customers within the Company’s service territory. Capacity revenues under unit power sales contracts reflect the recovery of fixed costs and a return on investment, and under these contracts, energy is generally sold at variable cost. Fluctuations in the prices of oil and natural gas, which are the primary fuel sources for unit power sales customers, influence changes in these energy sales. However, because energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. In 2010, wholesale revenues from sales to non-affiliates decreased $155 million (25.0%), primarily due to a 39.5% decrease in KWH sales. In May 2010, the long-term unit power sales contracts expired and the unit power sales capacity revenues ceased. Beginning in June 2010, such capacity, which was subject to the unit power sales contracts, became available for retail service. The changes in wholesale revenues from sales to non-affiliates in 2009 and 2008 were not material. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Rate RSE” for additional information. Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company’s energy cost recovery clauses. The change in wholesale II-110 SoCo FOIA Response 002467 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report revenues from sales to affiliates for 2010 was not material. In 2009, wholesale revenues from sales to affiliates decreased $71 million (23.1%) primarily due to a 37.6% decrease in price, partially offset by a 23.2% increase in KWH sales to affiliates as a result of greater availability of the Company’s generating resources because of a decrease in customer demand within the Company’s service territory. In 2008, wholesale revenues from sales to affiliates increased $164 million (113.9%) primarily due to a 62.2% increase in KWH sales to affiliates as a result of greater availability of the Company’s generating resources because of a decrease in customer demand within the Company’s service territory. Other operating revenues increased $24 million (13.7%) in 2010 due to a $13 million increase in transmission sales and a $12 million increase in revenues from gas-fueled co-generation steam facilities as a result of greater sales volume. Other operating revenues in 2009 decreased $20 million (10.3%) from 2008 primarily due to a $43 million decrease in revenues from gas-fueled co-generation steam facilities as a result of lower gas prices. This decrease was partially offset by an increase of $10 million in customer charges related to late fees. In 2008, other operating revenues increased $13 million (7.1%) from 2007 primarily due to a $12 million increase in revenues from gas-fueled co-generation steam facilities. Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings for any year reported. Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2010 and the percent change by year were as follows: Total KWHs 2010 Total KWH Percent Change 2009 2008 2010 Weather-Adjusted Percent Change 2009 2008 2010 (in billions) Residential Commercial Industrial Other Total retail Wholesale Non-affiliates Affiliates Total wholesale Total energy sales 20.4 14.7 20.7 0.2 56.0 13.0% 3.8 11.1 (0.8) 9.7 (1.7)% (2.5) (15.9) 8.1 (7.6) (2.6)% (1.4) (3.2) 0.2 (2.5) 8.6 6.1 14.7 70.7 (39.5) (6.2) (29.2) (1.6)% (5.8) 23.2 1.6 (5.1)% (3.6) 62.2 7.6 - % (0.6)% (1.1) 11.1 (0.8) 3.5% (1.0)% (2.1) (15.9) 8.1 (7.2)% 2.2% 1.0 (3.2) 0.2 (0.3)% Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2010 were 9.7% greater than in 2009. Energy sales were up in 2010 across major classes of customers. Residential and commercial sales increased 13.0% and 3.8%, respectively, due primarily to significant weather-driven increases in KWH sales as a result of colder weather in the first and fourth quarters 2010 and warmer weather in the second and third quarters 2010. Industrial sales increased 11.1% in 2010 as a result of increased customer demand in most major sectors, including primary metals, chemicals, transportation, and textiles sectors, due to a recovering economy. Retail energy sales in 2009 were 7.6% less than in 2008. Energy sales were down in 2009 across major classes of customers. Residential and commercial sales decreased 1.7% and 2.5%, respectively, due primarily to unfavorable weather and decreased customer demand in 2009 as compared to 2008. Industrial sales decreased 15.9% during the year as a result of decreased customer demand in all sectors, most significantly in the chemical and primary metals sectors, due to a recessionary economy. Retail energy sales in 2008 were 2.5% less than in 2007. Energy sales were down in 2008 across major classes of customers. Residential and commercial sales decreased 2.6% and 1.4%, respectively, due primarily to unfavorable weather in 2008 compared to 2007. Industrial sales decreased 3.2% during the year primarily as a result of decreased customer demand in the chemical and pipeline, and textiles and food sectors, as a result of a slowing economy that worsened during the fourth quarter 2008. See “Operating Revenues” above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies as related to changes in price and KWH sales. II-111 SoCo FOIA Response 002468 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Fuel and Purchased Power Expenses Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Fuel and purchased power expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s energy cost recovery rate (Rate ECR). The Company, along with the Alabama Public Service Commission (PSC), continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information. Details of the Company’s electricity generated and purchased were as follows: Total generation (billions of KWHs) Total purchased power (billions of KWHs) Sources of generation (percent) – Coal Nuclear Gas Hydro Cost of fuel, generated (cents per net KWH) – Coal Nuclear Gas Average cost of fuel, generated (cents per net KWH)* Average cost of purchased power (cents per net KWH) 2010 2009 2008 69.2 5.0 68.8 6.3 70.0 9.2 61 19 15 5 58 20 13 9 66 20 11 3 3.02 0.60 4.47 2.76 6.42 3.02 0.56 5.24 2.79 6.05 2.94 0.50 8.30 3.00 7.44 *Fuel includes fuel purchased by the Company for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power. KWHs generated by hydro are excluded from the average cost of fuel, generated. Fuel and purchased power expenses were $2.1 billion in 2010. The increase over the prior year costs was not material. Fuel and purchased power expenses were $2.1 billion in 2009, a decrease of $591 million (21.7%) below the prior year costs. This decrease was the result of a $367 million decrease related to the volume of KWHs generated and purchased and a $225 million decrease in the cost of fuel resulting from lower natural gas prices and an increase in hydro generation. Fuel and purchased power expenses were $2.7 billion in 2008, an increase of $522 million (23.7%) above the prior year costs. This increase was the result of a $561 million increase in the cost of fuel, offset by a $39 million decrease related to the volume of KWHs generated and purchased. Purchased power consists of purchases from affiliates in the Southern Company system and non-affiliated companies. Purchased power transactions among the Company, its affiliates, and non-affiliates will vary from period to period depending on demand and the availability and variable production cost of generating resources at each company. In 2010, purchased power from non-affiliates decreased $16 million (18.2%) due to a 22.4% decrease in the amount of energy purchased, partially offset by a 6.7% increase in the average cost per KWH. In 2009, purchased power from non-affiliates decreased $91 million (50.8%) due to a 34.9% decrease in the amount of energy purchased and a 24.6% decrease in the average cost per KWH. In 2009, purchased power from affiliates decreased $140 million (39.0%) due to a 31.4% decrease in the amount of energy purchased. In 2008, the average cost of purchased power from non-affiliates increased $82 million (84.5%) due to a 67.9% increase in the amount of energy purchased. From an overall global market perspective, coal prices increased substantially in 2010 from the levels experienced in 2009, but remained lower than the unprecedented high levels of 2008. The slowly recovering U.S. economy and global demand from coal importing countries drove the higher prices in 2010, with concerns over regulatory actions, such as permitting issues, and their negative impact on production also contributing upward pressure. Domestic natural gas prices continued to be depressed by robust supplies, including production from shale gas, as well as lower demand. These lower natural gas prices contributed to increased use of natural gas-fueled generating units in 2009 and 2010. Uranium prices remained relatively constant during the early portion of 2010 II-112 SoCo FOIA Response 002469 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report but rose steadily during the second half of the year. At year end, uranium prices remained well below the highs set during 2007. Worldwide uranium production levels increased in 2010; however, secondary supplies and inventories were still required to meet worldwide reactor demand. Other Operations and Maintenance Expenses In 2010, other operations and maintenance expenses increased $207 million (17.1%) due to a $60 million increase in steam production expenses related to planned outage maintenance, environmental mandates (which are offset by revenues associated with Rate CNP Environmental) and maintenance costs related to increases in labor and materials expenses, a $59 million increase in administrative and general expenses related to affiliated service companies’ expenses, injuries and damages reserve, labor, and other general expenses, partially offset by a reduction in employee medical and other benefit-related expenses, a $57 million increase in transmission and distribution expenses related to line clearing costs and an additional accrual to the natural disaster reserve (NDR), and a $21 million increase in nuclear production expense related to scheduled outage costs and maintenance costs related to increases in labor. In 2009, other operations and maintenance expenses decreased $48 million (3.8%) primarily due to a $39 million decrease in transmission and distribution expenses related to a reduction in overhead line clearing and labor which was offset by a $40 million additional NDR accrual, an $18 million decrease in steam production expense related to fewer scheduled outages, a $13 million decrease in administrative and general expense related to reductions in employee medical and other benefit-related expenses and in the injuries and damages reserve, a $6 million decrease in customer accounts expense, and a $5 million decrease in customer service and information expense. In 2008, other operations and maintenance expenses increased $73 million (6.2%) primarily due to a $27 million increase in steam production expense related to environmental mandates (which were offset by revenues associated with Rate CNP Environmental) and scheduled outage costs, a $23 million increase in nuclear production expense related to operations and scheduled outage costs, and a $20 million increase in transmission and distribution expense related to overhead line clearing costs. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Reserve” herein for additional information. Depreciation and Amortization Depreciation and amortization increased $61 million (11.2%) in 2010, $25 million (4.8%) in 2009, and $48 million (10.2%) in 2008, primarily due to additions to property, plant, and equipment related to environmental mandates (which were offset by revenues associated with Rate CNP Environmental) and transmission and distribution projects. See Note 3 to financial statements under “Retail Regulatory Matters – Rate CNP” for additional information. Taxes Other Than Income Taxes Taxes other than income taxes increased $10 million (3.1%) in 2010, $15 million (4.9%) in 2009, and $20 million (7.0%) in 2008. The increase in 2010 was primarily due to increases in state and municipal public utility license tax bases and an increase in payroll taxes. The increases in 2009 and 2008 were primarily due to increases in state and municipal public utility license tax bases. Allowance for Funds Used During Construction Equity AFUDC equity decreased $43 million (54.4%) in 2010 from 2009 primarily due to the completion of construction projects related to environmental mandates at steam generating facilities, partially offset by an increase in nuclear production projects. AFUDC equity increased $33 million (71.7%) in 2009 and $11 million (31.4%) in 2008 primarily due to increases in construction work in progress related to environmental mandates at generating facilities, as well as transmission, distribution, and general plant projects compared to the prior years. See Note 1 to financial statements under “Allowance for Funds Used During Construction” for additional information. Interest Expense, Net of Amounts Capitalized Interest expense, net of amounts capitalized increased $5 million (1.7%) in 2010. The increase in 2010 was not material. Interest expense, net of amounts capitalized increased $20 million (6.9%) in 2009 primarily due to the issuance of long-term debt, partially offset by additional capitalized interest, as a result of increases in construction work in progress. Interest expense, net of amounts capitalized increased $5 million (1.9%) in 2008 which was not material when compared to the prior year. II-113 SoCo FOIA Response 002470 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Income Taxes Income taxes increased $79 million (20.6%) in 2010, primarily due to higher pre-tax income as compared to 2009, an increase in Alabama state taxes due to a decrease in the state deduction for federal income taxes paid, and an increase in the tax expense associated with a decrease in AFUDC equity and a decrease in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction. Income taxes increased $16 million (4.3%) in 2009, primarily due to higher pre-tax income as compared to 2008, prior year tax return actualization, and an increase in expense related to normal tax contingencies, partially offset by the tax benefits associated with an increase in AFUDC equity and an increase in the Internal Revenue Code, Section 199 production activities deduction. Income taxes increased $17 million (4.8%) in 2008, primarily due to higher pre-tax income as compared to 2007, partially offset by the tax benefit associated with an increase in AFUDC equity and a decrease in expense related to normal tax contingencies. Effects of Inflation The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company’s results of operations has not been substantial in recent years. See Note 3 to financial statements under “Retail Regulatory Matters – Rate RSE” for additional information. FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located in the State of Alabama in addition to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” and “FERC Matters” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information about regulatory matters. The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the Company’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company’s service area. Changes in economic conditions impact sales for the Company, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information. New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to each of the II-114 SoCo FOIA Response 002471 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report traditional operating companies. After the Company was dismissed from the original action, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of Alabama. In the lawsuit against the Company, the EPA alleges that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil action requests penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against the Company is ongoing. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving a portion of the Company’s lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of the Company with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against the Company, leaving only three claims for summary disposition or trial, including the claim relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. II-115 SoCo FOIA Response 002472 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Statutes and Regulations General The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2010, the Company had invested approximately $3.0 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of $130 million, $526 million, and $617 million for 2010, 2009, and 2008, respectively. The Company expects that capital expenditures to comply with existing statutes and regulations will be $47 million, $26 million, and $53 million for 2011, 2012, and 2013, respectively. These environmental costs that are known and estimable at this time are included in the Company’s approved construction program and capital expenditures under the heading “Capital” in the table FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. In addition, the Company currently estimates additional environmental expenditures may be required to comply with anticipated new statutes and regulations. Such additional environmental expenditures are estimated to be in amounts up to $48 million, $108 million, and $354 million for 2011, 2012, and 2013, respectively. The Company’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of any new or revised environmental statutes and regulations that are enacted, including the proposed environmental legislation and regulations described below; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel mix. Compliance with any new federal or state legislation or regulations relating to global climate change, air quality, coal combustion byproducts, including coal ash, water quality, or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the Company’s commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2010, the Company had spent approximately $2.6 billion in reducing sulfur dioxide (SO 2 ) and nitrogen oxide (NO x ) emissions and in monitoring emissions pursuant to the Clean Air Act. As a result, emissions control projects have been completed recently or are underway. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements. The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone air quality standard. No area within the Company’s service area is currently designated as nonattainment for the standard. In March 2008, the EPA issued a final II-116 SoCo FOIA Response 002473 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the level of the standard. Under the EPA’s current schedule, a final revision to the eight-hour ozone standard is expected in July 2011, with state implementation plans for any resulting nonattainment areas due in mid-2014. The revised eight-hour ozone standard is expected to result in designation of nonattainment areas within the Company’s service territory and could result in additional required reductions in NO x emissions. During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for one area within the Company’s service area. State implementation plans demonstrating attainment with the annual standard for all areas have been submitted to the EPA. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. In October 2009, the EPA designated the Birmingham area as nonattainment for the 24-hour standard. Although the Birmingham area was initially designated as nonattainment for the 24-hour standard, in September 2010, the EPA determined that the area had attained the standard. The EPA is expected to propose new annual and 24-hour fine particulate matter standards during the summer of 2011. Final revisions to the National Ambient Air Quality Standard for SO 2 , including the establishment of a new one-hour standard, became effective on August 23, 2010. Since the EPA intends to rely on computer modeling for implementation of the SO 2 standard, the identification of potential nonattainment areas remains uncertain and could ultimately include areas within the Company’s service territory. Implementation of the revised SO 2 standard could result in additional required reductions in SO 2 emissions and increased compliance and operation costs. Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO 2 ), which established a new one-hour standard, became effective on April 12, 2010. Although none of the areas within the Company’s service territory are expected to be designated as nonattainment for the NO 2 standard, based on current ambient air quality monitoring data, the new NO 2 standard could result in significant additional compliance and operational costs for units that require new source permitting. Twenty-eight eastern states, including the State of Alabama, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO x and/or SO 2 to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. The State of Alabama has completed its plan to implement CAIR, and emissions reductions are being accomplished by the installation and operation of emissions controls at the Company’s coal-fired facilities and/or by the purchase of emissions allowances. On August 2, 2010, the EPA published a proposed rule, referred to as the Transport Rule, to replace CAIR. This proposed rule would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO 2 and NO x that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, to reduce annual emissions of SO 2 and NO x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Alabama, to achieve additional reductions in NO x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requested comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA stated that it also intends to develop a second phase of the Transport Rule in 2011 to address the more stringent ozone air quality standards after they are finalized. The EPA expects to finalize the Transport Rule in June 2011 and require compliance beginning in 2012. The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO 2 and NO x, and no additional controls beyond CAIR are anticipated to be necessary at any of the Company’s facilities. The State of Alabama has completed its implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress. The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal and oil-fired electric generating units, which will establish emission limitations for numerous hazardous air pollutants, including mercury. As part of a proceeding in II-117 SoCo FOIA Response 002474 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report the U.S. District Court for the District of Columbia, the EPA has entered into a consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011. The impacts of the eight-hour ozone, fine particulate matter, SO 2 and NO 2 standards, the proposed Transport Rule, the Clean Air Visibility Rule, and the proposed MACT rule for electric generating units on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any pending and future legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company has already installed a number of SO 2 and NO x emissions controls to ensure continued compliance with applicable air quality requirements. Water Quality In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. In April 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is expected to propose revisions to the regulations in March 2011 and issue final regulations in mid-2012. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on the specific provisions of the EPA’s final rule and on the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time. However, if the final rules require the installation of cooling towers at certain existing facilities of the Company, the Company may be subject to significant additional compliance costs and capital expenditures that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. In December 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted, and the EPA has announced its intention to adopt such revisions by January 2014. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Company facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, and, therefore, cannot be determined at this time. Environmental Remediation The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” for additional information. Coal Combustion Byproducts The Company currently operates six electric generating plants with on-site coal combustion byproduct storage facilities (some with both “wet” (ash ponds) and “dry” (landfill) storage facilities). In addition to on-site storage, the Company also sells a portion of its coal combustion byproducts to third parties for beneficial reuse (approximately one-fourth in recent years). Historically, individual states have regulated coal combustion byproducts and the states in Southern Company’s service territory, including the State of Alabama, each have their own regulatory parameters. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments and compliance with applicable regulations. The EPA is currently evaluating whether additional regulation of coal combustion byproducts (including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June 21, 2010, the EPA published a proposed rule that requested comments II-118 SoCo FOIA Response 002475 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report on two potential regulatory options for the management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of, or significant change to, existing storage facilities and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. On November 19, 2010, Southern Company filed publicly available comments with the EPA regarding the rulemaking proposal. These comments included a preliminary cost analysis under various alternatives in the rulemaking proposal. The Company regards these estimates as pre-screening figures that should be distinguished from the more formalized cost estimates the Company provides for projects that are more definite as to the elements and timing of execution. Although its analysis was preliminary, Southern Company concluded that potential compliance costs under the proposed rules would be substantially higher than the estimates reflected in the EPA’s rulemaking proposal. The ultimate financial and operational impact of any new regulations relating to coal combustion byproducts cannot be determined at this time and will be dependent upon numerous factors. These factors include: whether coal combustion byproducts will be regulated as hazardous waste or non-hazardous waste; whether the EPA will require early closure of existing wet storage facilities; whether beneficial reuse will be limited or eliminated through a hazardous waste designation; whether the construction of lined landfills is required; whether hazardous waste landfill permitting will be required for on-site storage; whether additional waste water treatment will be required; the extent of any additional groundwater monitoring requirements; whether any equipment modifications will be required; the extent of any changes to site safety practices under a hazardous waste designation; and the time period over which compliance will be required. There can be no assurance as to the timing of adoption or the ultimate form of any such rules. While the ultimate outcome of this matter cannot be determined at this time, and will depend on the final form of any rules adopted and the outcome of any legal challenges, additional regulation of coal combustion byproducts could have a material impact on the generation, management, beneficial use, and disposal of such byproducts. Any material changes are likely to result in substantial additional compliance, operational, and capital costs that could affect future unit retirement and replacement decisions. Moreover, the Company could incur additional material asset retirement obligations with respect to closing existing storage facilities. The Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. Global Climate Issues Although the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas emissions, neither this legislation nor similar measures passed the U.S. Senate before the end of the 2010 session. Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are expected to continue to be considered in Congress. The financial and operational impacts of climate or energy legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates. While climate legislation has yet to be adopted, the EPA is moving forward with regulation of greenhouse gases under the Clean Air Act. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. In December 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the II-119 SoCo FOIA Response 002476 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, which began on January 2, 2011, applies to sources and projects that would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed settlement agreement to issue standards of performance for greenhouse gas emissions from new and modified fossil fuel-fired electric generating units and greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012. All of the EPA’s final Clean Air Act rulemakings have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit; however, the court declined motions to stay the rules pending resolution of those challenges. As a result, the rules may impact the amount of time it takes to obtain PSD permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate outcome of these rules cannot be determined at this time and will depend on the content of the final rules and the outcome of any legal challenges. International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The most recent round of negotiations took place in December 2010. The outcome and impact of the international negotiations cannot be determined at this time. Although the outcome of federal, state, and international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. In 2009, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 43 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2010 is approximately 45 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The Company continues to evaluate its future energy and emissions profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions. FERC Matters In July 2005, the Company filed two applications with the FERC for new 50-year licenses for the Company’s seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine projects expired in July and August 2007. Since the FERC did not act on the Company’s new license applications prior to the expiration of the existing licenses, the FERC is required by law to issue annual licenses to the Company, under the terms and conditions of the existing license, until action is taken on the new license applications. The FERC issued an annual license for the Coosa developments in August 2007 and issued an annual license for the Warrior developments in September 2007. These annual licenses were automatically renewed in 2010 without further action by the FERC to allow the Company to continue operation of the projects under the terms of the previous license while the FERC completes review of the applications for new licenses. In 2006, the Company initiated the process of developing an application to relicense the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license is expected to be filed with the FERC in 2011. II-120 SoCo FOIA Response 002477 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report In 2010, the Company initiated the process of developing an application to relicense the Holt hydroelectric project located on the Warrior River. The current Holt license will expire on August 31, 2015, and the application for a new license is expected to be filed prior to that time. On March 31, 2010, the FERC issued a new 30-year license for the Lewis Smith and Bankhead developments on the Warrior River. The new license authorizes the Company to continue operating these facilities in a manner consistent with past operations. On April 30, 2010, a stakeholders group filed a request for rehearing of the FERC order issuing the new license. On May 27, 2010, the FERC granted the rehearing request for the limited purpose of allowing the FERC additional time to consider the substantive issues raised in the request. The ultimate outcome of this matter cannot be determined at this time. Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain requirements that could result in additional costs to the Company. The timing and final outcome of the Company’s relicense applications cannot be determined at this time. PSC Matters Retail Rate Adjustments Rate RSE Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. Retail rates remain unchanged when the retail return on common equity is projected to be between 13.0% and 14.5%. If the Company’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. The Rate RSE increase for 2010 was 3.24%, or $152 million annually, and was effective in January 2010. In December 2010, the Company made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2011 and earnings were within the specified return range. Consequently, the retail rates will remain unchanged in 2011 under Rate RSE. Under the terms of Rate RSE, the maximum increase for 2012 cannot exceed 5.00%. Rate CNP The Company’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated power purchase agreements (PPAs) under a Rate CNP. There was no adjustment to the Rate CNP to recover certificated PPA costs in 2008 or 2009. Effective April 2010, Rate CNP was reduced by approximately $70 million annually, primarily due to the expiration on May 31, 2010, of the PPA with Southern Power covering the capacity of Plant Harris Unit 1. It is estimated that there will be a slight decrease to the current Rate CNP effective April 2011. Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Retail rates increased approximately 2.4% in January 2008 and 4.3% in January 2010 due to environmental costs. In October 2008, the Company agreed to defer collection of any increase in rates under this portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations, from 2009 until 2010. The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no significant effect on the Company’s revenues or net income. On December 1, 2010, the Company submitted calculations associated with its cost of complying with environmental mandates, as provided under Rate CNP Environmental. The filing reflects an incremental increase in the revenue requirement associated with such environmental compliance, which would be recoverable in the billing months of January 2011 through December 2011. In order to afford additional rate stability to customers as the economy continues to recover from the recession, the Alabama PSC ordered on January 4, 2011 that the Company leave in effect for 2011 the factors associated with the Company’s environmental compliance costs for the year 2010. Any recoverable amounts associated with 2011 will be reflected in the 2012 filing. See Note 3 to the financial statements under “Retail Regulatory Matters – Rate CNP” for further information. The ultimate outcome of this matter cannot be determined at this time. II-121 SoCo FOIA Response 002478 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Fuel Cost Recovery The Company has established fuel cost recovery rates under Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company’s net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. The Rate ECR factor as of January 1, 2011 was 2.403 cents per KWH. Effective with billings beginning in April 2011, the Rate ECR factor will be 2.681 cents per KWH. As of December 31, 2010, the Company had an under recovered fuel balance of approximately $4 million which is included in deferred under recovered regulatory clause revenues in the balance sheets. As of December 31, 2009, the Company had an over recovered fuel balance of approximately $200 million, of which approximately $22 million was included in deferred over recovered regulatory clause revenues in the balance sheets. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs or recovery of under recovered fuel costs. See Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for further information. Natural Disaster Reserve Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate Natural Disaster Reserve (Rate NDR) charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has discretionary authority to accrue certain additional amounts as circumstances warrant. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows the Company to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the reserve. For the year ended December 31, 2010, the Company accrued an additional $48 million to the NDR, resulting in an accumulated balance of approximately $127 million. For the year ended December 31, 2009, the Company accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $75 million. These accruals are included in the balance sheets under other regulatory liabilities, deferred and are reflected as operations and maintenance expense in the statements of income. Steam Service In February 2009, the Alabama PSC granted a Certificate of Abandonment of Steam Service for the downtown area of the City of Birmingham. The order allows the Company to discontinue general steam service by the earlier of three years from May 14, 2008 or when it has no such remaining steam service customers. The Company was also authorized to honor other contractual obligations to provide steam service, which extend until 2013. Impacts related to the abandonment of steam service are recognized in operating income and are not material to the earnings of the Company. II-122 SoCo FOIA Response 002479 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Nuclear Outage Accounting Order On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Previously, the Company accrued nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period. The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012, these deferred costs will be amortized to nuclear operations and maintenance expenses over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012, these deferred costs will be amortized to nuclear operations and maintenance expenses over an 18-month period. The Company will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period. Legislation Stimulus Funding On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S. Department of Energy (DOE), formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009 (ARRA). This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. The Company will receive, and will match, $65 million under this agreement. On May 12, 2010, the Company signed an agreement with the DOE formally accepting a $6 million grant under the ARRA. This funding will be used for hydro generation upgrades. The total upgrade project is expected to cost $30 million and the Company plans to spend $24 million on the project. The ultimate outcome of these matters cannot be determined at this time. Healthcare Reform On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, the Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of the Company. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and related employee benefit plan costs. Any future impact on the financial statements of the Company cannot be determined at this time. See Note 5 to the financial statements under “Current and Deferred Income Taxes” for additional information. Income Tax Matters Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method II-123 SoCo FOIA Response 002480 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report resulted in net positive cash flow in 2010 of approximately $141 million for the Company. Although the Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. Bonus Depreciation On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which could have a significant impact on the future cash flows of the Company. The application of the bonus depreciation provisions in these acts in 2010 provided approximately $132 million in increased cash flow. The Company estimates the potential increased cash flow for 2011 to be between approximately $150 million and $200 million. Internal Revenue Code Section 199 Domestic Production Deduction The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code. The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 2010, and none is projected to be available for 2011. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. Other Matters In accordance with accounting standards related to employers’ accounting for pensions, the Company recorded non-cash pre-tax pension income of approximately $19 million, $24 million, and $26 million in 2010, 2009, and 2008, respectively. Postretirement benefit costs for the Company were $14 million, $19 million, and $23 million in 2010, 2009, and 2008, respectively. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements. The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues. ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the II-124 SoCo FOIA Response 002481 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors. Electric Utility Regulation The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations and financial condition than they would on a nonregulated company. As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements. Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following: • Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters. • Changes in existing income tax regulations or changes in IRS or Alabama Department of Revenue interpretations of existing regulations. • Identification of sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party. • Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. • Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, the Alabama Department of Revenue, the FERC, or the EPA. Unbilled Revenues Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. Recorded revenue includes both billed and unbilled KWH sales. Billings to individual customers are based on the reading of their meters, which is performed on a systematic basis throughout the month. II-125 SoCo FOIA Response 002482 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report The Company’s unbilled KWH sales include a measured component and an estimated component. Automated meters measure unbilled energy delivered through month-end. Readings from these meters are used to determine the measured unbilled KWH sales and associated revenues. At month-end for customers where automated meter readings are not available, amounts of unbilled electricity delivered are estimated. Components of the estimate include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, estimated unbilled revenues could be significantly affected. However, as of December 31, 2010, the measured unbilled KWH sales are greater than the estimated unbilled KWH sales. Pension and Other Postretirement Benefits The Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. Key elements in determining the Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company’s investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company’s target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. A 25 basis point change in any significant assumption would result in a $6 million or less change in total benefit expense and a $73 million or less change in projected obligations. FINANCIAL CONDITION AND LIQUIDITY Overview The Company’s financial condition remained stable at December 31, 2010. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information. The Company’s investments in the qualified pension plan and the nuclear decommissioning trust funds remained stable in value as of December 31, 2010. In December 2010, the Company contributed $38 million to the qualified pension plan. The Company’s funding obligations for the nuclear decommissioning trust fund are based on the site study, and the next study is expected to be conducted in 2013. Net cash provided from operating activities in 2010 totaled $1.4 billion, a decrease of $231 million as compared to 2009. The decrease in cash provided from operating activities was primarily due to receivables and other current liabilities related to less cash collections of regulatory clause revenues when compared to the prior year. This is partially offset by an increase in deferred income taxes related to bonus depreciation. Net cash provided from operating activities in 2009 totaled $1.6 billion, an increase of $424 million as compared to 2008. The increase was primarily due to an increase in net income, a decrease in receivables, and an increase in other current liabilities attributable to collections on regulatory clauses. Net cash provided from operating activities in 2008 totaled $1.2 billion, an increase of $30 million as compared to 2007. The increase included additional use of funds for fossil fuel inventory and payment of operating expenses along with a higher receivables balance as compared to 2007. This use of funds was offset by an increase in cash from net income and higher depreciation along with a decrease in the payments for federal taxes as compared to 2007. II-126 SoCo FOIA Response 002483 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Net cash used for investing activities totaled $1.0 billion, $1.2 billion, and $1.6 billion for 2010, 2009, and 2008, respectively, primarily due to gross property additions to utility plant of $0.9 billion, $1.2 billion, and $1.5 billion for 2010, 2009, and 2008, respectively. These additions were primarily related to environmental mandates, construction of transmission and distribution facilities, replacement of steam generation equipment, and purchases of nuclear fuel. Net cash used for financing activities totaled $600 million in 2010 primarily due to payment of common stock dividends. In 2009, net cash used for financing activities totaled $35 million primarily due to redemptions of debt securities and dividends paid in excess of debt issuances and cash raised from common stock sales. In 2008, net cash provided from financing activities totaled $375 million primarily due to long-term debt issuances and cash raised from common stock sales in excess of redemptions of securities and dividends paid. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities. Significant balance sheet changes for 2010 included increases of $454 million in accumulated deferred income taxes, $340 million in gross plant related to environmental mandates and transmission and distribution projects, $124 million in prepaid pension costs, $101 million in deferred charges related to income taxes, and a $214 million decrease in cash and cash equivalents. In 2009, significant balance sheet changes included increases of $340 million in cash primarily from collections on regulatory clauses. These cash collections correspondingly decreased current and deferred under recovered regulatory clause revenues by $297 million and increased current and deferred over recovered regulatory clause revenues by $204 million. Other changes include increases of $939 million in gross plant related to environmental mandates and transmission and distribution projects and $478 million in long-term debt. The Company’s ratio of common equity to total capitalization, including short-term debt, was 44.0% in 2010, 43.3% in 2009, and 42.5% in 2008. See Note 6 to the financial statements for additional information. Sources of Capital The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past. The Company has primarily utilized funds from operating cash flows, short-term debt, security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended. The amounts of securities authorized by the Alabama PSC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. The Company’s current liabilities sometimes exceed current assets because of the Company’s debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At December 31, 2010, the Company had approximately $154 million of cash and cash equivalents and $1.3 billion of unused credit arrangements with banks, as described below. In addition, the Company has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs. The Company maintains committed lines of credit in the amount of $1.3 billion, of which $506 million will expire at various times during 2011. $372 million of the credit facilities expiring in 2011 allow for the execution of term loans for an additional one-year period. $765 million of credit facilities expire in 2012. A portion of the unused credit with banks is allocated to provide liquidity support to the Company’s variable rate pollution control revenue bonds. During 2010, the Company remarketed $307 million of pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support is $798 million as of December 31, 2010. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. II-127 SoCo FOIA Response 002484 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other traditional operating company. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support. The Company had no commercial paper outstanding as of December 31, 2010 or December 31, 2009. During 2010, the Company had an average of $7 million of commercial paper outstanding at a weighted average interest rate of 0.22% per annum and the maximum amount outstanding was $135 million. During 2009, the Company had an average of $30 million of commercial paper outstanding at a weighted average interest rate of 0.23% per annum and the maximum amount outstanding was $237 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash. Financing Activities In October 2010, the Company issued $250 million aggregate principal amount of Series 2010A 3.375% Senior Notes due October 1, 2020. The net proceeds were used for the redemption of $150 million aggregate principal amount of the Company’s Series AA 5.625% Senior Notes due April 15, 2034 and for other general corporate purposes, including the Company’s continuous construction program. In December 2010, the Company’s $100 million Series R 4.70% Senior Notes due December 1, 2010 matured. Subsequent to December 31, 2010, the Company’s $200 million Series HH 5.10% Senior Notes due February 1, 2011 matured. Subsequent to December 31, 2010, the Company entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million. In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Credit Rating Risk The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At December 31, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $322 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market. Market Price Risk Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. To mitigate future exposure to changes in interest rates, the Company enters into derivatives that have been designated as hedges. The weighted average interest rate on $989 million of long-term variable interest rate exposure that has not been hedged at January 1, 2011 II-128 SoCo FOIA Response 002485 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report was 0.95%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $9.9 million at January 1, 2011. For further information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements. To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The Company continues to manage a retail fuel hedging program implemented per the guidelines of the Alabama PSC. In addition, Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company’s electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75% of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5% of the Company’s natural gas budget for that year. The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the years ended December 31 were as follows: 2009 2010 Changes Changes Fair Value (in millions) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes(a) Contracts outstanding at the end of the period, assets (liabilities), net $(44) 61 (55) $(38) $(92) 123 (75) $(44) (a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any. The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2010 was an increase of $6 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 2010, the Company had a net hedge volume of 33.9 million mmBtu with a weighted average contract cost approximately $1.14 per mmBtu above market prices, and 36.3 million mmBtu at December 31, 2009 with a weighted average contract cost approximately $1.22 per mmBtu above market prices. All of the natural gas hedges are recovered through the Company’s fuel cost recovery clause. At December 31, 2010 and 2009, substantially all of the Company’s energy-related derivative contracts were designated as regulatory hedges and are related to the Company’s fuel hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energyrelated derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented. The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 10 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2010 were as follows: December 31, 2010 Fair Value Measurements Total Maturity Fair Value Year 1 Years 2&3 Years 4&5 (in millions) Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period $ (38) $(38) $ (30) $(30) $ (8) $(8) $$- II-129 SoCo FOIA Response 002486 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s Investors Service and Standard & Poor’s, a division of The McGraw Hill Companies, Inc., or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized. Capital Requirements and Contractual Obligations The approved construction program of the Company includes a base level investment of $0.9 billion for 2011, $0.9 billion for 2012, and $1.1 billion for 2013. Over the next three years, the Company estimates spending $579 million on Plant Farley (including nuclear fuel), $886 million on distribution facilities, and $548 million on transmission additions. Also included in the Company’s approved construction program are estimated environmental expenditures to comply with existing statutes and regulations of $47 million, $26 million, and $53 million for 2011, 2012, and 2013, respectively. The Company currently anticipates that additional environmental expenditures may be required to comply with anticipated new statutes and regulations. Such additional environmental expenditures are estimated to be in amounts up to $48 million, $108 million, and $354 million for 2011, 2012, and 2013, respectively. These potential incremental investments are not included in the approved construction program. See Note 7 to the financial statements under “Construction Program” for additional details. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. As a result of Nuclear Regulatory Commission requirements, the Company has external trust funds for nuclear decommissioning costs; however, the Company currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” In addition to the funds required for the Company’s construction program, approximately $950 million will be required by the end of 2013 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost securities and replace these obligations with lower cost capital if market conditions permit. The Company has also established an external trust fund for postretirement benefits as ordered by the Alabama PSC. The cumulative effect of funding these items over an extended period will diminish internally funded capital for other purposes and may require the Company to seek capital from other sources. See Note 2 to the financial statements for additional information. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 6, 7, and 11 to the financial statements for additional information. II-130 SoCo FOIA Response 002487 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Contractual Obligations 2011 20122013 20142015 After 2015 Uncertain Timing (d) Total (in millions) Long-term debt(a) – Principal Interest Preferred and preference stock dividends(b) Energy-related derivative obligations(c) Operating leases Unrecognized tax benefits and interest(d) Purchase commitments(e) – Capital(f) Limestone(g) Coal Nuclear fuel Natural gas(h) Purchased power Long-term service agreements(i) Pension and other postretirement benefit plans(j) Total (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) $ 200 290 39 31 20 - $ 750 536 79 9 29 - $ 54 483 79 13 - $ 5,182 4,308 8 - $ 45 $ 6,186 5,617 197 40 70 45 834 16 1,304 83 288 30 23 9 $3,167 1,900 33 1,441 94 402 62 41 17 $5,393 28 861 86 280 75 35 $1,994 49 579 222 147 270 18 $10,783 - 2,734 126 4,185 485 1,117 437 117 26 $21,382 $45 All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2011, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only. For additional information, see Notes 1 and 11 to the financial statements. The timing related to the realization of $45 million in unrecognized tax benefits and corresponding interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Note 5 to the financial statements for additional information. The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2010, 2009, and 2008 were $1.4 billion, $1.2 billion, and $1.3 billion, respectively. The Company provides forecasted capital expenditures for a three-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for nuclear fuel. Such amounts exclude the Company’s estimates of potential incremental investments to comply with anticipated new environmental regulations of up to $48 million, $108 million, and $354 million for 2011, 2012, and 2013, respectively. At December 31, 2010, significant purchase commitments were outstanding in connection with the construction program. As part of the Company’s program to reduce SO 2 emissions from certain of its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2010. Long-term service agreements include price escalation based on inflation indices. The Company forecasts contributions to the qualified pension and other postretirement benefit plans over a three-year period. The Company does not expect to be required to make any contributions to the qualified pension plan during the next three years. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company’s corporate assets. II-131 SoCo FOIA Response 002488 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2010 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company’s 2010 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales and retail rates, customer growth, economic recovery, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plan, and nuclear decommissioning trust fund contributions, financing activities, start and completion of construction projects, filings with state and federal regulatory authorities, impacts of adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: • • • • • • • • • • • • • • • • • • • • • the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters and the pending EPA civil action against the Company; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures; available sources and costs of fuels; effects of inflation; ability to control costs and avoid cost overruns during the development and construction of facilities; investment performance of the Company’s employee benefit plans and nuclear decommissioning trust funds; advances in technology; state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers; the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings; the ability of the Company to obtain additional generating capacity at competitive prices; catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC. The Company expressly disclaims any obligation to update any forward-looking statements. II-132 SoCo FOIA Response 002489 STATEMENTS OF INCOME For the Years Ended December 31, 2010, 2009, and 2008 Alabama Power Company 2010 Annual Report 2010 2009 2008 (in millions) Operating Revenues: Retail revenues Wholesale revenues, non-affiliates Wholesale revenues, affiliates Other revenues Total operating revenues Operating Expenses: Fuel Purchased power, non-affiliates Purchased power, affiliates Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Interest income Interest expense, net of amounts capitalized Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Net Income Dividends on Preferred and Preference Stock Net Income After Dividends on Preferred and Preference Stock $5,076 465 236 199 5,976 $4,497 620 237 175 5,529 $4,862 712 308 195 6,077 1,851 72 208 1,418 606 332 4,487 1,489 1,824 88 219 1,211 545 322 4,209 1,320 2,184 179 359 1,259 520 307 4,808 1,269 36 17 (303) (30) (280) 1,209 463 746 39 $ 707 79 17 (298) (25) (227) 1,093 384 709 39 $ 670 46 19 (279) (32) (246) 1,023 368 655 39 $ 616 The accompanying notes are an integral part of these financial statements. II-133 SoCo FOIA Response 002490 STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2010, 2009, and 2008 Alabama Power Company 2010 Annual Report 2009 2010 2008 (in millions) Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating activities -Depreciation and amortization, total Deferred income taxes Allowance for equity funds used during construction Pension, postretirement, and other employee benefits Pension and postretirement funding Stock based compensation expense Natural disaster reserve Other, net Changes in certain current assets and liabilities --Receivables -Fossil fuel stock -Materials and supplies -Other current assets -Accounts payable -Accrued taxes -Accrued compensation -Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Investment in restricted cash from pollution control bonds Distribution of restricted cash from pollution control bonds Nuclear decommissioning trust fund purchases Nuclear decommissioning trust fund sales Cost of removal net of salvage Change in construction payables Other investing activities Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds -Common stock issued to parent Capital contributions from parent company Pollution control revenue bonds Senior notes issuances Redemptions -Preferred stock Pollution control revenue bonds Senior notes Payment of preferred and preference stock dividends Payment of common stock dividends Other financing activities Net cash provided from (used for) financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Supplemental Cash Flow Information: Cash paid during the period for -Interest (net of $14, $33 and $20 capitalized, respectively) Income taxes (net of refunds) Noncash transactions - accrued property additions at year-end $ 746 $ 709 $ 655 694 410 (36) (15) (55) 5 52 (27) 637 (66) (79) (8) (17) 4 55 8 600 127 (46) (26) 3 16 12 (29) (1) (20) (4) (54) (140) 28 (181) 1,373 310 (77) (22) (16) (19) 24 (32) 193 1,604 (32) (134) (18) (1) (9) 37 (5) 1,179 (903) 18 (237) 236 (44) (45) (12) (987) (1,234) (6) 49 (245) 244 (38) 26 (25) (1,229) (1,478) (96) 36 (301) 300 (42) 42 (61) (1,600) 28 250 (250) (39) (586) (3) (600) (214) 368 $ 154 $288 188 28 (25) 25 203 24 79 500 300 21 265 850 (250) (39) (523) (4) (35) 340 28 $ 368 $255 426 74 (125) (11) (410) (41) (491) (8) 375 (46) 74 $ 28 $259 214 107 The accompanying notes are an integral part of these financial statements. II-134 SoCo FOIA Response 002491 BALANCE SHEETS At December 31, 2010 and 2009 Alabama Power Company 2010 Annual Report Assets 2009 2010 (in millions) Current Assets: Cash and cash equivalents Restricted cash Receivables -Customer accounts receivable Unbilled revenues Under recovered regulatory clause revenues Other accounts and notes receivable Affiliated companies Accumulated provision for uncollectible accounts Fossil fuel stock, at average cost Materials and supplies, at average cost Vacation pay Prepaid expenses Other regulatory assets, current Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Plant in service, net of depreciation Nuclear fuel, at amortized cost Construction work in progress Total property, plant, and equipment Other Property and Investments: Equity investments in unconsolidated subsidiaries Nuclear decommissioning trusts, at fair value Miscellaneous property and investments Total other property and investments Deferred Charges and Other Assets: Deferred charges related to income taxes Prepaid pension costs Deferred under recovered regulatory clause revenues Other regulatory assets, deferred Other deferred charges and assets Total deferred charges and other assets Total Assets $ 154 18 362 153 5 35 57 (10) 391 346 55 208 38 10 1,822 $ 368 37 322 135 37 34 62 (10) 395 326 54 111 34 6 1,911 19,966 6,931 13,035 283 547 13,865 18,575 6,559 12,016 253 1,256 13,525 64 552 71 687 60 490 69 619 488 257 4 675 196 1,620 $17,994 387 133 750 199 1,469 $17,524 The accompanying notes are an integral part of these financial statements. II-135 SoCo FOIA Response 002492 BALANCE SHEETS At December 31, 2010 and 2009 Alabama Power Company 2010 Annual Report Liabilities and Stockholder's Equity 2009 2010 (in millions) Current Liabilities: Securities due within one year Accounts payable -Affiliated Other Customer deposits Accrued taxes -Accrued income taxes Other accrued taxes Accrued interest Accrued vacation pay Accrued compensation Liabilities from risk management activities Over recovered regulatory clause revenues Other current liabilities Total current liabilities Long-Term Debt (See accompanying statements) Deferred Credits and Other Liabilities: Accumulated deferred income taxes Deferred credits related to income taxes Accumulated deferred investment tax credits Employee benefit obligations Asset retirement obligations Other cost of removal obligations Other regulatory liabilities, deferred Deferred over recovered regulatory clause revenues Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Redeemable Preferred Stock (See accompanying statements) Preference Stock (See accompanying statements) Common Stockholder's Equity (See accompanying statements) Total Liabilities and Stockholder's Equity Commitments and Contingent Matters (See notes) $ 200 $ 100 210 273 86 195 328 87 2 32 63 45 99 31 22 41 1,104 5,987 15 32 65 45 71 38 182 40 1,198 6,082 2,747 85 157 311 520 701 217 87 4,825 11,916 342 343 5,393 $17,994 2,293 89 165 388 491 668 169 22 37 4,322 11,602 342 343 5,237 $17,524 The accompanying notes are an integral part of these financial statements. II-136 SoCo FOIA Response 002493 STATEMENTS OF CAPITALIZATION At December 31, 2010 and 2009 Alabama Power Company 2010 Annual Report 2009 2010 (in millions) Long-Term Debt: Long-term debt payable to affiliated trusts -Variable rate (3.39% at 1/1/11) due 2042 Long-term notes payable -4.70% due 2010 5.10% due 2011 4.85% due 2012 5.80% due 2013 3.375% to 6.375% due 2016-2047 Total long-term notes payable Other long-term debt -Pollution control revenue bonds -1.40% to 5.00% due 2030-2038 Variable rates (0.26% to 0.44% at 1/1/11) due 2015-2038 Total other long-term debt Unamortized debt premium (discount), net Total long-term debt (annual interest requirement -- $290.4 million) Less amount due within one year Long-term debt excluding amount due within one year $ 206 $ 2010 2009 (percent of total) 206 200 500 250 3,875 4,825 100 200 500 250 3,775 4,825 367 554 788 1,155 1 601 1,155 (4) 6,187 200 5,987 6,182 100 6,082 49.6% II-137 SoCo FOIA Response 002494 50.7% STATEMENTS OF CAPITALIZATION (continued) At December 31, 2010 and 2009 Alabama Power Company 2010 Annual Report 2009 2010 (in millions) Redeemable Preferred Stock: Cumulative redeemable preferred stock $100 par or stated value -- 4.20% to 4.92% Authorized - 3,850,000 shares Outstanding - 475,115 shares $1 par value -- 5.20% to 5.83% Authorized - 27,500,000 shares Outstanding - 12,000,000 shares: $25 stated value (annual dividend requirement -- $18.1 million) Total redeemable preferred stock Preference Stock: Authorized - 40,000,000 shares Outstanding - $1 par value -- 5.63% to 6.50% - 14,000,000 shares (non-cumulative) $25 stated value (annual dividend requirement -- $21.4 million) Common Stockholder's Equity: Common stock, par value $40 per share -Authorized: 40,000,000 shares Outstanding: 30,537,500 shares Paid-in capital Retained earnings Accumulated other comprehensive income (loss) Total common stockholder's equity Total Capitalization 2009 2010 (percent of total) 48 48 294 342 294 342 2.8 2.8 343 343 2.9 2.9 44.7 100.0% 43.6 100.0% 1,222 2,156 2,022 (7) 5,393 $12,065 1,222 2,119 1,901 (5) 5,237 $12,004 The accompanying notes are an integral part of these financial statements. II-138 SoCo FOIA Response 002495 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2010, 2009, and 2008 Alabama Power Company 2010 Annual Report Number of Common Shares Issued Common Stock Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total (in millions) Balance at December 31, 2007 Net income after dividends on preferred and preference stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Other Balance at December 31, 2008 Net income after dividends on preferred and preference stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Other Balance at December 31, 2009 Net income after dividends on preferred and preference stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2010 18 $719 $2,065 $1,631 - - - 616 7 25 300 1,019 26 2,091 - - - 5 1 31 203 1,222 31 $1,222 (491) (2) 1,754 $(4) (6) (10) $4,411 616 300 26 (6) (491) (2) 4,854 670 - 670 28 2,119 (523) 1,901 5 (5) 203 28 5 (523) 5,237 37 $2,156 707 (586) $2,022 (2) $(7) 707 37 (2) (586) $5,393 The accompanying notes are an integral part of these financial statements. II-139 SoCo FOIA Response 002496 STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2010, 2009, and 2008 Alabama Power Company 2010 Annual Report 2010 2009 2008 (in millions) Net income after dividends on preferred and preference stock Other comprehensive income (loss): Qualifying hedges: Changes in fair value, net of tax of $-, $(2), and $(4), respectively Reclassification adjustment for amounts included in net income, net of tax of $(1), $5, and $1, respectively Total other comprehensive income (loss) Comprehensive Income $707 (2) (2) $705 $670 (3) 8 5 $675 The accompanying notes are an integral part of these financial statements. II-140 SoCo FOIA Response 002497 $616 (8) 2 (6) $610 NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2010 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants, including the Company’s Plant Farley. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment, but is not the primary beneficiary. The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Alabama Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $371 million, $325 million, and $321 million during 2010, 2009, and 2008, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $218 million, $183 million, and $196 million during 2010, 2009, and 2008, respectively. The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $11 million in 2010, $10 million in 2009, and $11 million in 2008. See Note 4 for additional information. Southern Company’s 30% ownership interest in Alabama Fuel Products, LLC (AFP), which produced synthetic fuel, was terminated in July 2006. The Company had an agreement with an indirect subsidiary of Southern Company that provided services for AFP. Under this agreement, the Company provided certain accounting functions, including processing and paying fuel transportation invoices, and the Company was reimbursed for its expenses. Amounts billed under this agreement totaled approximately $1 million in II-141 SoCo FOIA Response 002498 NOTES (continued) Alabama Power Company 2010 Annual Report 2008. In addition, the Company purchased synthetic fuel from AFP for use at several of the Company’s plants. Synthetic fuel purchases totaled $6 million in 2008. The Company had an agreement with Southern Power under which the Company operated and maintained Plant Harris at cost. On August 1, 2007, that agreement was terminated and replaced with a service agreement under which the Company provides to Southern Power specifically requested services. In 2010, 2009, and 2008, the Company billed Southern Power $1 million, $1 million, and $1 million, respectively, under these agreements. Under a power purchase agreement (PPA) with Southern Power, the Company’s purchased power costs from Plant Harris in 2010, 2009, and 2008 totaled $15 million, $62 million, and $63 million, respectively. The Company also provides the fuel, at cost, associated with the PPA. The fuel cost recognized by the Company was $21 million in 2010, $63 million in 2009, and $120 million in 2008. The Company recorded no prepaid capacity expenses in 2010 due to the expiration of the PPA with Southern Power in May 2010. The Company recorded $8.3 million of prepaid capacity expenses included in other deferred charges and other assets in the balance sheets at December 31, 2009 and 2008. See Note 3 under “Retail Regulatory Matters” and Note 7 under “Purchased Power Commitments” for additional information. The Company has an agreement with Gulf Power under which the Company will make transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA. In March 2009, Gulf Power entered into a PPA for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. The total cost committed by the Company related to the upgrades is approximately $82 million over the next four years. The Company expects to recover a majority of these costs from Gulf Power over the next ten years. The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any significant services to or from affiliates in 2010, 2009, and 2008. Also, see Note 4 for information regarding the Company’s ownership in and PPA with Southern Electric Generating Company (SEGCO). The traditional operating companies, including the Company, and Southern Power jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information. II-142 SoCo FOIA Response 002499 NOTES (continued) Alabama Power Company 2010 Annual Report Regulatory Assets and Liabilities The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2010 2009 Note (in millions) Deferred income tax charges Loss on reacquired debt Vacation pay Under/(over) recovered regulatory clause revenues Fuel-hedging (realized and unrealized) losses Other assets Asset retirement obligations Other cost of removal obligations Deferred income tax credits Fuel-hedging (realized and unrealized) gains Mine reclamation and remediation Nuclear outage Deferred purchased power Natural disaster reserve Other liabilities Retiree benefit plans Total assets (liabilities), net $ 488 74 55 (13) 39 30 (77) (701) (85) (1) (10) (127) (3) 569 $ 238 $ 387 74 54 (166) 45 8 (43) (668) (89) (1) (12) (27) (8) (75) (3) 657 $ 133 (a, j, l) (b) (c, k) (d) (e) (f, g) (a) (a) (a) (e) (h) (d) (g) (i) (d) (j, k) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. (b) Recovered over the remaining life of the original issue, which may range up to 50 years. (c) Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. (d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding five years. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally does not exceed three years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. (f) Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects. (g) Recovered over the life of the PPA for periods up to 13.5 years. (h) Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. (i) Recovered as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. (j) Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. (k) Not earning a return as offset in rate base by a corresponding asset or liability. (l) Included in the deferred income tax charges is $21 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years. See Note 5 for additional information. In the event that a portion of the Company’s operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off or reclassify to accumulated other comprehensive income (OCI) related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Retail Regulatory Matters” for additional information. II-143 SoCo FOIA Response 002500 NOTES (continued) Alabama Power Company 2010 Annual Report Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under “Retail Regulatory Matters – Fuel Cost Recovery” and “Retail Regulatory Matters – Rate CNP” for additional information. The Company has a diversified base of customers. No single customer comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under “Nuclear Fuel Disposal Costs” for additional information. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction. The Company’s property, plant, and equipment consisted of the following at December 31: 2009 2010 (in millions) Generation Transmission Distribution General Plant acquisition adjustment Total plant in service $10,598 2,826 5,267 1,262 12 $19,965 $ 9,627 2,702 5,046 1,187 12 $18,574 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. During 2010, the Company accrued estimated nuclear refueling outage costs in advance of the unit’s next refueling outage. The refueling cycle is 18 months for each unit. During 2010, the Company accrued $53 million for the applicable refueling cycles and paid $80 million for outages at Plant Farley Units 1 and 2. At December 31, 2010, the reserve balance was zero. II-144 SoCo FOIA Response 002501 NOTES (continued) Alabama Power Company 2010 Annual Report On August 17, 2010, the Alabama PSC approved the Company’s request to stop accruing for nuclear refueling outage costs in advance of the refueling outages when the most recent 18-month cycle ended in December 2010 and to begin deferring nuclear outage expenses. The amortization will begin after each outage has occurred and the associated outage expenses are known. The first 18month amortization cycle for expenses associated with the fall 2011 outage will begin in January 2012. The second cycle will begin in July 2012 for expenses associated with the spring 2012 outage. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2010 and 3.2% in 2009 and 2008. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facility, Plant Farley. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See “Nuclear Decommissioning” for further information on amounts included in rates. Details of the asset retirement obligations included in the balance sheets are as follows: 2010 2009 (in millions) Balance at beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions (a) Balance at end of year $491 (2) 33 (2) $520 $461 (1) 31 $491 (a) Updated based on results from the 2009 Nuclear Interim Study Nuclear Decommissioning The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (the Funds) to comply with the NRC’s regulations. Use of the Funds is restricted to nuclear decommissioning activities and the Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds’ managers to exercise the standard of care in investing that a “prudent investor” would use in the same circumstances. The FERC regulations also require, except for investments tied to market indices or other II-145 SoCo FOIA Response 002502 NOTES (continued) Alabama Power Company 2010 Annual Report mutual funds, that the Funds’ managers may not invest in any securities of the utility for which it manages funds or its affiliates. While the Company is allowed to prescribe an overall investment policy to the Funds’ managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the Company’s management. The Funds’ managers are authorized, within broad limits, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. At December 31, 2010, investment securities in the Funds totaled $552 million consisting of equity securities of $406 million, debt securities of $139 million, and $7 million of other securities. At December 31, 2009, investment securities in the Funds totaled $488 million consisting of equity securities of $346 million, debt securities of $134 million, and $9 million of other securities. These amounts exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases. Sales of the securities held in the Funds resulted in cash proceeds of $236 million, $244 million, and $300 million in 2010, 2009, and 2008, respectively, all of which were reinvested. For 2010, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $65 million, of which $31 million related to securities held in the Funds at December 31, 2010. For 2009, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $96 million, of which $80 million related to securities held in the Funds at December 31, 2009. For 2008, fair value reductions, including reinvested interest and dividends and excluding the Funds’ expenses, were $(134) million. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of and purpose for which the securities were acquired. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2010, the accumulated provisions for decommissioning were as follows: (in millions) $553 24 $577 External trust funds Internal reserves Total Site study cost is the estimate to decommission the facility as of the site study year. The estimated costs of decommissioning based on the most current study performed in 2008 for Plant Farley was as follows: Decommissioning periods: Beginning year Completion year 2037 2065 (in millions) Site study costs: Radiated structures Non-radiated structures Total $1,060 72 $1,132 The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. II-146 SoCo FOIA Response 002503 NOTES (continued) Alabama Power Company 2010 Annual Report For ratemaking purposes, the Company’s decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be conducted in 2013. Amounts previously contributed to the external trust fund are currently projected to be adequate to meet the decommissioning obligations. The Company will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with the NRC and other applicable requirements. Allowance for Funds Used During Construction (AFUDC) In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 9.4% in 2010 and 9.2% in 2009 and 2008. AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 6.3% in 2010, 14.9% in 2009, and 9.4% in 2008. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. Natural Disaster Reserve Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate Natural Disaster Reserve (Rate NDR) charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has discretionary authority to accrue certain additional amounts as circumstances warrant. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows the Company to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the reserve. II-147 SoCo FOIA Response 002504 NOTES (continued) Alabama Power Company 2010 Annual Report Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel hedging program. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2010. The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income after dividends on preferred and preference stock, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. Variable Interest Entities The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, the Company is not considered the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as other investments, and the related loans from the trusts are reflected as long-term debt in the balance sheets. II-148 SoCo FOIA Response 002505 NOTES (continued) Alabama Power Company 2010 Annual Report 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2010, the Company contributed approximately $38 million to the qualified pension plan. No contributions to the qualified pension plan are expected for the year ending December 31, 2011. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2011, other postretirement trust contributions are expected to total approximately $9 million. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2007 for the 2008 plan year using a discount rate of 6.30% and an annual salary increase of 3.75%. Discount rate: Pension plans Other postretirement benefit plans Annual salary increase Long-term return on plan assets: Pension plans Other postretirement benefit plans 2010 2009 2008 5.52% 5.41 3.84 5.93% 5.84 4.18 6.75% 6.75 3.75 8.75 7.43 8.50 7.52 8.50 7.66 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate of 8.25% for 2011, decreasing gradually to 5.00% through the year 2019 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2010 as follows: 1 Percent Increase 1 Percent Decrease (in millions) Benefit obligation Service and interest costs $32 2 $28 1 Pension Plans The total accumulated benefit obligation for the pension plans was $1.7 billion in 2010 and $1.6 billion in 2009. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: II-149 SoCo FOIA Response 002506 NOTES (continued) Alabama Power Company 2010 Annual Report 2009 2010 (in millions) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial loss (gain) Balance at end of year $1,675 41 97 (81) 47 1,779 $1,460 34 96 (77) 162 1,675 Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Prepaid pension asset, net 1,712 258 44 (81) 1,933 $ 154 1,539 245 5 (77) 1,712 $ 37 At December 31, 2010, the projected benefit obligations for the qualified and non-qualified pension plans were $1.7 billion and $103 million, respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s pension plans consist of the following: 2009 2010 (in millions) Prepaid pension costs Other regulatory assets, deferred Other current liabilities Employee benefit obligations $133 549 (6) (90) $257 497 (7) (96) Presented below are the amounts included in regulatory assets at December 31, 2010 and 2009 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2011. 2010 2009 Estimated Amortization in 2011 (in millions) Prior service cost Net (gain) loss Other regulatory assets, deferred $ 41 456 $497 $ 50 499 $549 $ 9 4 II-150 SoCo FOIA Response 002507 NOTES (continued) Alabama Power Company 2010 Annual Report The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2010 and 2009 are presented in the following table: Regulatory Assets (in millions) $479 79 1 Balance at December 31, 2008 Net loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net gain Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 (9) (1) (10) 70 549 (42) 1 (9) (2) (11) (52) $497 Components of net periodic pension cost (income) were as follows: 2009 2010 2008 (in millions) Service cost Interest cost Expected return on plan assets Recognized net (gain) loss Net amortization Net periodic pension cost (income) $ 41 97 (168) 2 9 $ (19) $ 34 96 (164) 1 9 $ (24) $ 35 87 (160) 2 10 $ (26) Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the marketrelated value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2010, estimated benefit payments were as follows: Benefit Payments (in millions) 2011 2012 2013 2014 2015 2016 to 2020 $ 90 95 99 103 108 596 II-151 SoCo FOIA Response 002508 NOTES (continued) Alabama Power Company 2010 Annual Report Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2009 2010 (in millions) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial loss (gain) Plan amendments Retiree drug subsidy Balance at end of year $ 461 6 26 (26) (16) 3 454 $ 446 6 29 (26) 19 (15) 2 461 Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability 295 35 16 (23) 323 $(131) 252 47 20 (24) 295 $(166) Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s other postretirement benefit plans consist of the following: 2010 2009 (in millions) Regulatory assets Employee benefit obligations $ 72 (131) $ 108 (166) Presented below are the amounts included in regulatory assets at December 31, 2010 and 2009 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2011. 2010 2009 Estimated Amortization in 2011 (in millions) Prior service cost Net (gain) loss Transition obligation Regulatory assets $ 30 37 5 $ 72 $ 33 67 8 $108 $ 4 3 II-152 SoCo FOIA Response 002509 NOTES (continued) Alabama Power Company 2010 Annual Report The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2010 and 2009 are presented in the following table: Regulatory Assets (in millions) Balance at December 31, 2008 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 $135 (4) (15) (4) (4) (8) (27) 108 (29) (3) (4) (7) (36) $ 72 Components of the other postretirement benefit plans’ net periodic cost were as follows: 2010 2009 2008 (in millions) Service cost Interest cost Expected return on plan assets Net amortization Net postretirement cost $ 6 26 (25) 7 $ 14 $ 6 29 (24) 8 $ 19 $ 7 29 (22) 9 $ 23 The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2010, 2009, and 2008 by approximately $8 million, $9 million, and $11 million, respectively, and is expected to have a similar impact on future expenses. Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows: Benefit Payments Subsidy Receipts Total (in millions) 2011 2012 2013 2014 2015 2016 to 2020 $ 29 31 33 35 36 184 $ (3) (3) (3) (3) (4) (22) $ 26 28 30 32 32 162 II-153 SoCo FOIA Response 002510 NOTES (continued) Alabama Power Company 2010 Annual Report Benefit Plan Assets Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The composition of the Company’s pension plan and other postretirement benefit plan assets as of December 31, 2010 and 2009, along with the targeted mix of assets for each plan, is presented below: Target 2010 2009 Pension plan assets: Domestic equity International equity Fixed income Special situations Real estate investments Private equity Total 29% 28 15 3 15 10 100% 29% 27 22 13 9 100% 33% 29 15 13 10 100% Other postretirement benefit plan assets: Domestic equity International equity Domestic fixed income Special situations Real estate investments Private equity Total 47% 12 32 1 5 3 100% 41% 16 36 4 3 100% 42% 16 35 4 3 100% The investment strategy for plan assets related to the Company’s qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is longterm in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. An actively-managed mix of growth stocks and value stocks with both developed and emerging market exposure. • Fixed income. A mix of domestic and international bonds. • Trust-owned life insurance. Investments of the Company’s taxable trusts aimed at minimizing the impact of taxes on the portfolio. II-154 SoCo FOIA Response 002511 NOTES (continued) Alabama Power Company 2010 Annual Report • Special situations. Though currently unfunded, established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private-market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2010 and 2009. The fair values presented are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund. The fair values of pension plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total $358 361 $144 125 $ - $ 502 486 1 52 $772 86 70 168 57 135 $785 1 191 180 $372 86 70 169 57 136 243 180 $1,929 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well diversified with no significant concentrations of risk. II-155 SoCo FOIA Response 002512 NOTES (continued) Alabama Power Company 2010 Annual Report As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $339 439 $141 44 $ - $ 480 483 1 53 $832 127 34 85 3 104 $538 166 169 $335 127 34 85 3 105 219 169 $1,705 (1) $831 $538 $335 (1) $1,704 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well diversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 were as follows: 2010 Real Estate Investments Private Equity 2009 Real Estate Investments Private Equity (in millions) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $166 $169 $254 $148 14 3 17 8 $191 9 3 12 (1) $180 (72) (20) (92) 4 $166 13 3 16 5 $169 The fair values of other postretirement benefit plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. II-156 SoCo FOIA Response 002513 NOTES (continued) Alabama Power Company 2010 Annual Report As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Special situations Real estate investments Private equity Total $62 19 $ 7 6 $ - $ 69 25 3 $84 5 4 9 3 24 159 $217 10 9 $19 5 4 9 3 24 159 13 9 $320 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well diversified with no significant concentrations of risk. As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Special situations Real estate investments Private equity Total $54 24 $ 8 2 $ - $ 62 26 3 $81 7 2 5 23 144 $191 9 10 $19 7 2 5 23 144 12 10 $291 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well diversified with no significant concentrations of risk. II-157 SoCo FOIA Response 002514 NOTES (continued) Alabama Power Company 2010 Annual Report Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 were as follows: 2010 Real Estate Investments Private Equity 2009 Real Estate Investments Private Equity (in millions) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $ 9 $10 $15 $8 1 1 $10 (1) $ 9 (5) (1) (6) $9 2 2 $10 Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2010, 2009, and 2008 were $18 million, $19 million, and $18 million, respectively. 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. Environmental Matters New Source Review Actions In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to each of the traditional operating companies. After the Company was dismissed from the original action, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of Alabama. In the lawsuit against the Company, the EPA alleges that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil action requests penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against the Company is ongoing. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving a portion of the Company’s lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of the Company with respect to its II-158 SoCo FOIA Response 002515 NOTES (continued) Alabama Power Company 2010 Annual Report other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against the Company, leaving only three claims for summary disposition or trial, including the claim relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political II-159 SoCo FOIA Response 002516 NOTES (continued) Alabama Power Company 2010 Annual Report question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Remediation The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. Nuclear Fuel Disposal Costs The Company has a contract with the U.S., acting through the U.S. Department of Energy (DOE), that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. In July 2007, the U.S. Court of Federal Claims awarded the Company approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plant Farley from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April 2008. On May 5, 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay. In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of December 31, 2010 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on the Company’s net income is expected as any damage amounts collected from the government are expected to be returned to customers. An on-site dry spent fuel storage facility at Plant Farley is operational and can be expanded to accommodate spent fuel through the expected life of the plant. Income Tax Matters Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $141 million for the Company. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. II-160 SoCo FOIA Response 002517 NOTES (continued) Alabama Power Company 2010 Annual Report Retail Regulatory Matters Rate RSE Rate stabilization and equalization plan (Rate RSE) adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. Retail rates remain unchanged when the retail return on common equity is projected to be between 13.0% and 14.5%. If the Company’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. The Rate RSE increase for 2010 was 3.24%, or $152 million annually, and was effective in January 2010. In December 2010, the Company made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2011 and earnings were within the specified return range. Consequently, the retail rates will remain unchanged in 2011 under Rate RSE. Under the terms of Rate RSE, the maximum increase for 2012 cannot exceed 5.00%. Rate CNP The Company’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under a rate certificated new plant (Rate CNP). There was no adjustment to the Rate CNP to recover certificated PPA costs in 2008 or 2009. Effective April 2010, Rate CNP was reduced by approximately $70 million annually, primarily due to the expiration on May 31, 2010 of the PPA with Southern Power covering the capacity of Plant Harris Unit 1. It is estimated that there will be a slight decrease to the current Rate CNP effective April 2011. Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Retail rates increased approximately 2.4% in January 2008 and 4.3% in January 2010 due to environmental costs. In October 2008, the Company agreed to defer collection of any increase in rates under this portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations, from 2009 until 2010. The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no significant effect on the Company’s revenues or net income. On December 1, 2010, the Company submitted calculations associated with its cost of complying with environmental mandates, as provided under rate certificated new plant environmental. The filing reflects an incremental increase in the revenue requirement associated with such environmental compliance, which would be recoverable in the billing months of January 2011 through December 2011. In order to afford additional rate stability to customers as the economy continues to recover from the recession, the Alabama PSC ordered on January 4, 2011 that the Company leave in effect for 2011 the factors associated with the Company’s environmental compliance costs for the year 2010. Any recoverable amounts associated with 2011 will be reflected in the 2012 filing. The ultimate outcome of this matter cannot be determined at this time. Fuel Cost Recovery The Company has established fuel cost recovery rates under rate energy cost recovery (Rate ECR) as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company’s net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per kilowatt-hour (KWH) sales. The Rate ECR factor as of January 1, 2011 is 2.403 cents per KWH. Effective with billings beginning in April 2011, the Rate ECR factor will be 2.681 cents per KWH. As of December 31, 2010, the Company had an under recovered fuel balance of approximately $4 million which is included in deferred under recovered regulatory clause revenues in the balance sheets. As of December 31, 2009, the Company had an over recovered fuel balance of approximately $200 million, of which approximately $22 million was included in deferred over recovered regulatory clause revenues in the balance sheets. These classifications are based on estimates, which include such factors as weather, II-161 SoCo FOIA Response 002518 NOTES (continued) Alabama Power Company 2010 Annual Report generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs or recovery of under recovered fuel costs. Natural Disaster Reserve Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has discretionary authority to accrue certain additional amounts as circumstances warrant. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows the Company to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the reserve. For the year ended December 31, 2010, the Company accrued an additional $48 million to the NDR, resulting in an accumulated balance of approximately $127 million. For the year ended December 31, 2009, the Company accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $75 million. These accruals are included in the balance sheets under other regulatory liabilities, deferred and are reflected as operations and maintenance expense in the statements of income. 4. JOINT OWNERSHIP AGREEMENTS The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense, and a return on equity, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two years’ notice. The Company’s share of purchased power totaled $101 million in 2010, $82 million in 2009, and $124 million in 2008, and is included in “Purchased power from affiliates” in the statements of income. The Company accounts for SEGCO using the equity method. In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO’s generating units, pursuant to which $25 million principal amount of pollution control revenue bonds are outstanding. Also, the Company has guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty. At December 31, 2010, the capitalization of SEGCO consisted of $90 million of equity and $75 million of long-term debt on which the annual interest requirement is $3 million. SEGCO paid dividends of $5 million in 2010, none in 2009, and $8 million in 2008, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO’s net income. II-162 SoCo FOIA Response 002519 NOTES (continued) Alabama Power Company 2010 Annual Report In addition to the Company’s ownership of SEGCO, the Company’s percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2010 is as follows: Facility Total Megawatt Capacity Company Ownership Amount of Investment Accumulated Depreciation (in millions) Greene County Plant Miller Units 1 and 2 500 60.00% (1) $ 140 $ 76 1,320 91.84% (2) 1,253 477 (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with PowerSouth. At December 31, 2010, the Company’s portion of Plant Miller construction work in progress was $125 million. The Company has contracted to operate and maintain the jointly owned facilities as agent for their co-owners. The Company’s proportionate share of its plant operating expenses is included in operating expenses in the statements of income and the Company is responsible for providing its own financing. 5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. In addition, the Company files a separate company income tax return for the State of Tennessee. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2010 2009 2008 (in millions) Federal – Current Deferred State – Current Deferred Total $ 52 333 $ 385 $374 (41) $333 $198 121 $319 $ $ 76 (25) 51 $384 $ 43 6 49 $368 1 77 78 $ 463 II-163 SoCo FOIA Response 002520 NOTES (continued) Alabama Power Company 2010 Annual Report The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2009 2010 (in millions) Deferred tax liabilities: Accelerated depreciation Property basis differences Premium on reacquired debt Pension and other benefits Fuel clause under recovered Regulatory assets associated with employee benefit obligations Regulatory assets associated with asset retirement obligations Other Total Deferred tax assets: Federal effect of state deferred taxes State effect of federal deferred taxes Unbilled revenue Storm reserve Pension and other benefits Other comprehensive losses Fuel clause over recovered Asset retirement obligations Other Total Total deferred tax liabilities, net Portion included in current assets (liabilities), net Accumulated deferred income taxes $2,415 396 31 210 10 239 220 85 3,606 $2,010 376 30 184 295 208 82 3,185 177 50 41 41 264 8 220 87 888 2,718 29 $2,747 88 107 29 23 334 9 75 208 93 966 2,219 74 $2,293 At December 31, 2010, the Company’s tax-related regulatory assets and liabilities were $488 million and $85 million, respectively. These assets are attributable to tax benefits that flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest. In 2010, the Company deferred $21 million as a regulatory asset related to the impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (together, the Acts). The Acts eliminated the deductibility of health care costs that are covered by federal Medicare subsidy payments. The Company will amortize the regulatory asset to income tax expense over the average remaining service period which may range up to 15 years, as approved by the Alabama PSC. These liabilities are attributable to unamortized investment tax credits. In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $8 million in each of 2010, 2009, and 2008. At December 31, 2010, all investment tax credits available to reduce federal income taxes payable had been utilized. On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013). The application of the bonus depreciation provisions in these acts in 2010 significantly increased deferred tax liabilities related to accelerated depreciation. II-164 SoCo FOIA Response 002521 NOTES (continued) Alabama Power Company 2010 Annual Report Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2010 35.0% 4.2 0.8 (0.1) (1.0) (0.6) 38.3% Federal statutory rate State income tax, net of federal deduction Non-deductible book depreciation Differences in prior years’ deferred and current tax rates AFUDC-equity Production activities deduction Other Effective income tax rate 2009 35.0% 3.0 0.8 (0.2) (2.5) (0.8) (0.2) 35.1% 2008 35.0% 3.1 0.9 (0.1) (1.6) (0.5) (0.8) 36.0% State income tax, net of federal deduction increased in 2010 due to a decrease in the state deduction for federal income taxes paid, which is a result of increased bonus depreciation and pension contributions. The tax benefit of AFUDC-equity decreased in 2010 from prior years due to a decrease in AFUDC, resulting from the completion of construction projects related to environmental mandates at generating facilities. See Note 1 under “Allowance for Funds Used During Construction (AFUDC)” for additional information. The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 2010. Unrecognized Tax Benefits For 2010, the total amount of unrecognized tax benefits increased by $37 million, resulting in a balance of $43 million as of December 31, 2010. Changes during the year in unrecognized tax benefits were as follows: 2010 2009 2008 (in millions) Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions from prior periods Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year $ 6 6 31 $43 $3 2 1 $6 $5 1 (2) (1) $3 The tax positions increases from current periods and from prior periods relate primarily to the tax accounting method change for repairs and other miscellaneous uncertain tax positions. See Note 3 under “Income Tax Matters – Tax Method of Accounting for Repairs” for additional information. The impact on the Company’s effective tax rate, if recognized, was as follows: 2010 2009 2008 (in millions) Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits $ 6 37 $43 $6 $6 $3 $3 II-165 SoCo FOIA Response 002522 NOTES (continued) Alabama Power Company 2010 Annual Report The tax positions impacting the effective tax rate primarily relate to the production activities deduction tax position. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note 3 under “Income Tax Matters – Tax Method of Accounting for Repairs” for additional information. Accrued interest for unrecognized tax benefits was as follows: 2010 2009 2008 (in millions) Interest accrued at beginning of year Interest reclassified due to settlements Interest accrued during the year Balance at end of year $0.3 1.2 $1.5 $0.3 $0.3 $0.4 (0.3) 0.2 $0.3 The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has audited and closed all tax returns prior to 2007. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006. 6. FINANCING Long-Term Debt Payable to Affiliated Trusts The Company has formed certain wholly-owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as long-term debt payable. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2010, preferred securities of $200 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities. Securities Due Within One Year At December 31, 2010 and 2009, the Company had scheduled maturities of senior notes due within one year totaling $200 million and $100 million, respectively. Maturities of senior notes through 2015 applicable to total long-term debt are as follows: $200 million in 2011; $500 million in 2012; $250 million in 2013; and none in 2014 and 2015. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of solid waste disposal facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company incurred no obligations related to the issuance of pollution control revenue bonds in 2010. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. II-166 SoCo FOIA Response 002523 NOTES (continued) Alabama Power Company 2010 Annual Report Senior Notes The Company issued a total of $250 million of unsecured senior notes in 2010. The proceeds of these issuances were used to redeem $150 million aggregate principle amount of the Company’s Series AA 5.625% Senior Notes due April 15, 2034 and for other general corporate purposes, including the Company’s continuous construction program. In December 2010, the Company’s $100 million Series R 4.70% Senior Notes due December 1, 2010 matured. Subsequent to December 31, 2010, the Company’s $200 million Series HH 5.10% Senior Notes due February 1, 2011 matured. At December 31, 2010 and 2009, the Company had $4.8 billion and $4.8 billion, respectively, of senior notes outstanding. These senior notes are effectively subordinate to all secured debt of the Company which amounted to approximately $153 million at December 31, 2010. Preference and Common Stock In 2010, the Company issued no new shares of preference stock or common stock. Outstanding Classes of Capital Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized and outstanding. The Company’s preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The preferred stock and Class A preferred stock of the Company contain a feature that allows the holders to elect a majority of the Company’s board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, the preferred stock and Class A preferred stock is presented as “Redeemable Preferred Stock” in a manner consistent with temporary equity under applicable accounting standards. The preference stock does not contain such a provision that would allow the holders to elect a majority of the Company’s board. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preferred stock, Class A preferred stock, and preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance). Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Assets Subject to Lien The Company has granted liens on certain property in connection with the issuance of certain series of pollution control revenue bonds with an outstanding principal amount of $153 million as of December 31, 2010. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. Bank Credit Arrangements The Company maintains committed lines of credit in the amount of $1.3 billion, of which $506 million will expire at various times during 2011. $372 million of the credit facilities expiring in 2011 allow for the execution of term loans for an additional one-year period. $765 million of credit facilities expire in 2012. A portion of the unused credit with banks is allocated to provide liquidity support to the Company’s variable rate pollution control revenue bonds. During 2010, the Company remarketed $307 million of pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support is $798 million as of December 31, 2010. Most of the credit arrangements require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Commitment fees average less than ¼ of 1% for the Company. Compensating balances are not legally restricted from withdrawal. II-167 SoCo FOIA Response 002524 NOTES (continued) Alabama Power Company 2010 Annual Report Most of the Company’s credit arrangements with banks have covenants that limit the Company’s debt to 65% of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2010, the Company was in compliance with the debt limit covenants. In addition, the credit arrangements typically contain cross default provisions that would be triggered if the Company defaulted on other indebtedness (including guarantee obligations) above a specified threshold. None of the arrangements contain material adverse change clauses at the time of borrowings. The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, the Company borrows from time to time through uncommitted credit arrangements. As of December 31, 2010 and 2009, the Company had no commercial paper outstanding. During 2010 and 2009, the maximum amount outstanding for commercial paper was $135 million and $237 million, respectively. The average amount outstanding in 2010 and 2009 was $7 million and $30 million, respectively. The weighted average annual interest rate on commercial paper was 0.22% in 2010 and 0.23% in 2009. Short-term borrowings are included in notes payable in the balance sheets. At December 31, 2010, the Company had regulatory approval to have outstanding up to $2.0 billion of short-term borrowings. 7. COMMITMENTS Construction Program The approved construction program of the Company includes a base level investment of $0.9 billion in 2011, $0.9 billion in 2012, and $1.1 billion in 2013. These amounts include $83 million, $59 million, and $35 million in 2011, 2012, and 2013, respectively, for construction expenditures related to contractual purchase commitments for nuclear fuel included herein under “Fuel Commitments.” Also included in the Company’s approved construction program are estimated environmental expenditures to comply with existing statutes and regulations of $47 million, $26 million, and $53 million for 2011, 2012, and 2013, respectively. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirement and replacement decisions, to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; storm impacts; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2010, significant purchase commitments were outstanding in connection with the ongoing construction program. The Company has no generating plants under construction. Construction of new transmission and distribution facilities and capital improvements, including those to meet environmental standards for existing generation, transmission, and distribution facilities, will continue. Long-Term Service Agreements The Company has entered into long-term service agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. The LTSAs provide that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract. In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments to GE, which are subject to price escalation, are made at various intervals based on actual operating hours of the respective units. Total remaining payments to GE under these agreements for facilities owned are currently estimated at $117 million over the remaining life of the agreements, which are currently estimated to range up to six years. However, the LTSAs contain various cancellation provisions at the option of the Company. Payments made to GE prior to the performance of any planned maintenance are recorded as either prepayments or other deferred charges and assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed. Limestone Commitments As part of the Company’s program to reduce sulfur dioxide emissions from its coal plants, the Company has entered into various longterm commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are II-168 SoCo FOIA Response 002525 NOTES (continued) Alabama Power Company 2010 Annual Report structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. The Company has a minimum contractual obligation of 2.6 million tons, equating to approximately $126 million, through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $16 million in 2011, $16 million in 2012, $17 million in 2013, $17 million in 2014, and $11 million in 2015. Fuel Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emissions allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2010. Total estimated minimum long-term commitments at December 31, 2010 were as follows: Natural Gas Commitments Coal Nuclear Fuel (in millions) 2011 2012 2013 2014 2015 2016 and thereafter Total commitments $ 288 227 175 156 124 147 $1,117 $1,304 832 609 424 437 579 $4,185 $ 83 59 35 43 43 222 $485 Additional commitments for fuel will be required to supply the Company’s future needs. Total charges for nuclear fuel included in fuel expense amounted to $79 million in 2010, $78 million in 2009, and $70 million in 2008. SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Purchased Power Commitments The Company has entered into various long-term commitments for the purchase of capacity and energy. Total estimated minimum long-term obligations at December 31, 2010 were as follows: Commitments Non-Affiliated (in millions) 2011 2012 2013 2014 2015 2016 and thereafter Total commitments $ 30 31 31 37 38 270 $437 Certain PPAs reflected in the table are accounted for as operating leases. II-169 SoCo FOIA Response 002526 NOTES (continued) Alabama Power Company 2010 Annual Report Operating Leases The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration dates. These expenses amounted to $25 million in 2010, $27 million in 2009, and $26 million in 2008. Of these amounts, $20 million, $20 million, and $19 million for 2010, 2009, and 2008, respectively, relate to the rail car leases and are recoverable through the Company’s Rate ECR. At December 31, 2010, estimated minimum lease payments for noncancelable operating leases were as follows: Rail Cars Minimum Lease Payments Vehicles & Other Total (in millions) 2011 2012 2013 2014 2015 2016 and thereafter Total * $16 15 11 6 5 7 $60 $ 4 2 1 1 1 1 $ 10 $20 17 12 7 6 8 $70 * Total does not include payments related to a non-affiliated PPA that is accounted for as an operating lease. Obligations related to this agreement are included in the above purchased power commitments table. In addition to the above rental commitments payments, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. The Company’s maximum obligations under these leases are $1 million in 2012, $39 million in 2013, $8 million in 2014, $5 million in 2015, and $4 million in 2016. Upon termination of the leases, the Company has the option to negotiate an extension, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company’s payments under the residual value obligations. Guarantees At December 31, 2010, the Company had outstanding guarantees related to SEGCO’s purchase of certain pollution control facilities and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets as described above in “Operating Leases.” 8. STOCK COMPENSATION Stock Option Plan Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2010, there were 1,313 current and former employees of the Company participating in the stock option plan and there were 10 million shares of Southern Company common stock remaining available for awards under this plan and the Performance Share Plan discussed below. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting. The estimated fair values of stock options granted in 2010, 2009, and 2008 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. II-170 SoCo FOIA Response 002527 NOTES (continued) Alabama Power Company 2010 Annual Report The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Dividend yield Weighted average grant-date fair value 2010 17.4% 5.0 2.4% 5.6% $2.23 2009 15.6% 5.0 1.9% 5.4% $1.80 2008 13.1% 5.0 2.8% 4.5% $2.37 The Company’s activity in the stock option plan for 2010 is summarized below: Outstanding at December 31, 2009 Granted Exercised Cancelled Outstanding at December 31, 2010 Exercisable at December 31, 2010 Shares Subject to Option 8,749,474 1,532,979 (1,512,059) (25,410) 8,744,984 5,920,732 Weighted Average Exercise Price $31.74 31.25 27.76 31.33 $ 32.35 $ 32.61 The number of stock options vested, and expected to vest in the future, as of December 31, 2010 was not significantly different from the number of stock options outstanding at December 31, 2010 as stated above. As of December 31, 2010, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $52 million and $33 million, respectively. As of December 31, 2010, there was $1 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months. For the years ended December 31, 2010, 2009, and 2008, total compensation cost for stock option awards recognized in income was $3 million, $4 million, and $3 million, respectively, with the related tax benefit also recognized in income of $1 million, $1 million, and $1 million, respectively. The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. The total intrinsic value of options exercised during the years ended December 31, 2010, 2009, and 2008 was $12 million, $2 million, and $5 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $4 million, $1 million, and $2 million for the years ended December 31, 2010, 2009, and 2008, respectively. Performance Share Plan In 2010, Southern Company implemented the performance share program under its omnibus incentive compensation plan, which provides performance share award units to a large segment of employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company’s total shareholder return (TSR) over the three-year performance period which measures Southern Company’s relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company’s actual TSR and may range from 0% to 200% of the original target performance share amount. II-171 SoCo FOIA Response 002528 NOTES (continued) Alabama Power Company 2010 Annual Report The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company’s stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. Expected volatility used in the model of 20.7% was based on historical volatility of Southern Company’s stock over a period equal to the performance period. The risk-free rate of 1.4% was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units. The annualized dividend rate at the time of the grant was $1.75. During 2010, 166,725 performance share units were granted to the Company’s employees with a weighted-average grant date fair value of $30.13. During 2010, 14,923 performance share units were forfeited by the Company’s employees resulting in 151,802 unvested units outstanding at December 31, 2010. For the year ended December 31, 2010, the Company’s total compensation cost for performance share units recognized in income was $1 million, with the related tax benefit also recognized in income of $1 million. As of December 31, 2010, there was $3 million of total unrecognized compensation cost related to performance share award units that will be recognized over the next two years. 9. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of $17.5 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $235 million per incident but not more than an aggregate of $35 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013. The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ operating nuclear generating facilities. Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.3 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL and has elected a 12-week deductible waiting period. Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $42 million. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. II-172 SoCo FOIA Response 002529 NOTES (continued) Alabama Power Company 2010 Annual Report 10. FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.    Level 1 consists of observable market data in an active market for identical assets or liabilities. Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: Fair Value Measurements Using Quoted Prices Significant in Active Other Significant Markets for Observable Unobservable Identical Inputs Inputs Assets As of December 31, 2010: (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Energy-related derivatives Nuclear decommissioning trusts:(a) Domestic equity U.S. Treasury and government agency securities Corporate bonds Mortgage and asset backed securities Other Cash equivalents and restricted cash Total Liabilities: Energy-related derivatives $ - $ 2 $ - $ 2 347 20 109 $476 59 7 82 30 7 $187 $ - 406 27 82 30 7 109 $663 $ $ 40 $ - $ 40 - (a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and London Interbank Offered Rate interest rates. See Note 11 for additional information on how these derivatives are used. For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics. A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit II-173 SoCo FOIA Response 002530 NOTES (continued) Alabama Power Company 2010 Annual Report information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts’ judgment are also obtained when available. As of December 31, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: As of December 31, 2010: Unfunded Commitments Redemption Frequency Redemption Notice Period $ 86 None Daily 15 days 109 None Daily Not applicable Fair Value (in millions) Nuclear decommissioning trusts: Trust-owned life insurance Cash equivalents and restricted cash: Money market funds The nuclear decommissioning trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis, up to the full amount of the Company’s investment in the money market funds. As of December 31, 2010 and 2009, other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt: 2010 2009 $6,187 $6,182 $6,463 $6,357 The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). 11. DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities. II-174 SoCo FOIA Response 002531 NOTES (continued) Alabama Power Company 2010 Annual Report Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Alabama PSC, through the use of financial derivative contracts, and recently has started using financial options, which is expected to continue to mitigate price volatility. To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. Energy-related derivative contracts are accounted for in one of three methods:    Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause. Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2010, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Gas Net Purchased mmBtu* Longest Hedge Date Longest Non-Hedge Date 2015 - (in millions) 34 *mmBtu – million British thermal units For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending December 31, 2011 are immaterial. Interest Rate Derivatives The Company also enters into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. At December 31, 2010, the Company did not have any interest rate derivatives outstanding. Subsequent to December 31, 2010, the Company entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million. II-175 SoCo FOIA Response 002532 NOTES (continued) Alabama Power Company 2010 Annual Report The estimated pre-tax gains that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2011 is $1 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2035. Derivative Financial Statement Presentation and Amounts At December 31, 2010 and 2009, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Derivative Category Asset Derivatives Balance Sheet Location 2010 Liability Derivatives Balance Sheet Location 2010 2009 (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Total derivatives designated as hedging instruments for regulatory purposes Derivatives designated as hedging instruments in cash flow hedges Interest rate derivatives: Other current assets Other deferred charges and assets Other current assets Total 2009 (in millions) $1 $1 1 - $2 $1 $$2 $$1 Liabilities from risk management activities Other deferred credits and liabilities Liabilities from risk management activities $31 $34 9 11 $40 $45 $ $40 $ 4 $49 All derivative instruments are measured at fair value. See Note 10 for additional information. At December 31, 2010 and 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: Derivative Category Unrealized Losses Balance Sheet Location 2010 2009 Unrealized Gains Balance Sheet Location (in millions) Energy-related derivatives: Other regulatory assets, current Other regulatory assets, deferred Total energy-related derivative gains (losses) $(31) $(34) (9) $(40) (11) $(45) 2010 2009 (in millions) Other current liabilities Other regulatory liabilities, deferred $1 $1 1 $2 $1 II-176 SoCo FOIA Response 002533 NOTES (continued) Alabama Power Company 2010 Annual Report For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Derivative Category 2010 2009 Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Statements of Income 2009 2008 Location 2010 2008 (in millions) Interest rate derivatives $- $(5) (in millions) Interest expense, net of amounts capitalized $(11) $3 $(12) $(3) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2010, the fair value of derivative liabilities with contingent features was $6 million. At December 31, 2010, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-riskrelated contingent features, at a rating below BBB- and/or Baa3, is $40 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. 12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2010 and 2009 are as follows: Net Income After Dividends on Preferred and Preference Stock Quarter Ended Operating Revenues Operating Income March 2010 June 2010 September 2010 December 2010 $1,495 1,462 1,706 1,313 $399 389 497 204 $203 190 259 55 March 2009 June 2009 September 2009 December 2009 $1,340 1,366 1,592 1,231 $299 349 483 189 $146 177 261 86 (in millions) The Company’s business is influenced by seasonal weather conditions. II-177 SoCo FOIA Response 002534 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 Alabama Power Company 2010 Annual Report Operating Revenues (in millions) Net Income after Dividends on Preferred and Preference Stock (in millions) Cash Dividends on Common Stock (in millions) Return on Average Common Equity (percent) Total Assets (in millions) Gross Property Additions (in millions) Capitalization (in millions) : Common stock equity Preference stock Redeemable preferred stock Long-term debt Total (excluding amounts due within one year) Capitalization Ratios (percent): Common stock equity Preference stock Redeemable preferred stock Long-term debt Total (excluding amounts due within one year) Customers (year-end): Residential Commercial Industrial Other Total Employees (year-end) 2010 $5,976 2009 $5,529 2008 $6,077 2007 $5,360 2006 $5,015 $707 $670 $616 $580 $518 $586 13.31 $17,994 $956 $523 13.27 $17,524 $1,323 $491 13.30 $16,536 $1,533 $465 13.73 $15,747 $1,203 $441 13.23 $14,655 $961 $5,393 343 342 5,987 $12,065 $5,237 343 342 6,082 $12,004 $4,854 343 342 5,605 $11,144 $4,411 343 340 4,750 $9,844 $4,032 147 465 4,148 $8,792 44.7 2.9 2.8 49.6 100.0 43.6 2.9 2.8 50.7 100.0 43.6 3.1 3.0 50.3 100.0 44.8 3.5 3.4 48.3 100.0 45.9 1.7 5.3 47.1 100.0 1,235,128 197,336 5,770 782 1,439,016 6,552 1,229,134 198,642 5,912 780 1,434,468 6,842 1,220,046 211,119 5,906 775 1,437,846 6,997 1,207,883 216,830 5,849 772 1,431,334 6,980 1,194,696 214,723 5,750 766 1,415,935 6,796 II-178 SoCo FOIA Response 002535 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 (continued) Alabama Power Company 2010 Annual Report Operating Revenues (in millions) : Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total revenues from sales of electricity Other revenues Total Kilowatt-Hour Sales (in millions) : Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total Average Revenue Per Kilowatt-Hour (cents): Residential Commercial Industrial Total retail Wholesale Total sales Residential Average Annual Kilowatt-Hour Use Per Customer Residential Average Annual Revenue Per Customer Plant Nameplate Capacity Ratings (year-end) (megawatts) Maximum Peak-Hour Demand (megawatts) : Winter Summer Annual Load Factor (percent) Plant Availability (percent): Fossil-steam Nuclear Source of Energy Supply (percent): Coal Nuclear Hydro Gas Purchased power From non-affiliates From affiliates Total 2010 2009 2008 2007 2006 $2,283 1,535 1,231 27 5,076 465 236 5,777 199 $5,976 $1,962 1,430 1,080 25 4,497 620 237 5,354 175 $5,529 $1,998 1,459 1,381 24 4,862 712 308 5,882 195 $6,077 $1,834 1,314 1,238 21 4,407 627 144 5,178 182 $5,360 $1,664 1,172 1,140 20 3,996 635 215 4,846 169 $5,015 20,417 14,719 20,622 216 55,974 8,655 6,074 70,703 18,071 14,186 18,555 218 51,030 14,317 6,473 71,820 18,380 14,551 22,075 201 55,207 15,204 5,256 75,667 18,874 14,761 22,806 201 56,642 15,769 3,241 75,652 18,633 14,355 23,187 199 56,374 15,979 5,145 77,498 11.18 10.43 5.97 9.07 4.76 8.17 10.86 10.08 5.82 8.81 4.12 7.45 10.87 10.03 6.26 8.81 4.99 7.77 9.71 8.90 5.43 7.78 4.06 6.84 8.93 8.17 4.92 7.09 4.03 6.25 16,570 14,716 15,162 15,696 15,663 $1,853 $1,597 $1,648 $1,525 $1,399 12,222 12,222 12,222 12,222 12,222 11,349 11,488 62.6 10,701 10,870 59.8 10,747 11,518 60.9 10,144 12,211 59.4 10,309 11,744 61.8 90.1 94.1 88.2 87.5 89.6 93.3 92.9 88.4 88.5 93.3 56.6 17.7 5.0 14.0 53.4 18.6 7.9 11.8 58.5 17.8 2.9 9.2 60.9 16.5 1.8 8.7 60.2 17.4 3.8 7.6 1.6 5.1 100.0 2.0 6.3 100.0 2.9 8.7 100.0 1.8 10.3 100.0 2.1 8.9 100.0 II-179 SoCo FOIA Response 002536 GEORGIA POWER COMPANY FINANCIAL SECTION 180 SoCo FOIA Response 002537 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Georgia Power Company 2010 Annual Report The management of Georgia Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010. W. Paul Bowers President and Chief Executive Officer Ronnie R. Labrato Executive Vice President, Chief Financial Officer, and Treasurer February 25, 2011 II-181 SoCo FOIA Response 002538 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Georgia Power Company We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2010 and 2009, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule of the Company listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements (pages II-211 to II-256) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. Atlanta, Georgia February 25, 2011 II-182 SoCo FOIA Response 002539 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Georgia Power Company 2010 Annual Report OVERVIEW Business Activities Georgia Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. The Company is currently constructing two new nuclear and three new combined cycle generating units. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. On December 21, 2010, the Georgia Public Service Commission (PSC) approved an Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), including a base rate increase of approximately $562 million effective January 1, 2011. The Company is currently required to file its next fuel case by March 1, 2011. Key Performance Indicators In striving to maximize shareholder value while providing cost-effective energy to more than two million customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The 2010 fossil/hydro Peak Season EFOR of 1.89% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The 2010 performance was better than the target for these reliability measures. Net income after dividends on preferred and preference stock is the primary measure of the Company’s financial performance. The Company’s 2010 results compared to its targets for some of these key indicators are reflected in the following chart: Key Performance Indicator Customer Satisfaction Peak Season EFOR – fossil/hydro Net Income after dividends on preferred and preference stock 2010 Target Performance 2010 Actual Performance Top quartile in customer surveys 5.06% or less Top quartile in customer surveys 1.89% $905 million $950 million See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2010 reflects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations. II-183 SoCo FOIA Response 002540 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Earnings The Company’s 2010 net income after dividends on preferred and preference stock totaled $950 million representing a $136 million, or 16.7%, increase over the previous year. The increase was due primarily to higher residential base revenues resulting from colder weather in the first and fourth quarters of 2010 and warmer weather in the second and third quarters of 2010 and increased amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC, partially offset by increases in operations and maintenance expenses. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Rate Plans” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Rate Plans” for additional information. The Company’s 2009 net income after dividends on preferred and preference stock totaled $814 million representing an $89 million, or 9.8%, decrease from 2008. The decrease was primarily related to lower commercial and industrial base revenues resulting from the recessionary economy and decreased revenues from market-response rates to large commercial and industrial customers that were partially offset by cost containment activities, increased recognition of environmental compliance cost recovery revenues, and the amortization of the regulatory liability related to other cost of removal obligations. The Company’s 2008 net income after dividends on preferred and preference stock totaled $903 million representing a $67 million, or 8.0%, increase over 2007. The increase was primarily related to increased contributions from market-response rates for large commercial and industrial customers, higher retail base revenues resulting from the retail rate increase effective January 1, 2008 (2007 Retail Rate Plan), and increased allowance for equity funds used during construction. These increases were partially offset by increased depreciation and amortization resulting from more plant in service and changes to depreciation rates. RESULTS OF OPERATIONS A condensed income statement for the Company follows: Amount 2010 Increase (Decrease) from Prior Year 2009 2008 2010 (in millions) Operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Total other income and (expense) Income taxes Net income Dividends on preferred and preference stock Net income after dividends on preferred and preference stock $ 8,349 3,102 946 1,734 558 344 6,684 1,665 (245) 453 967 17 $ 657 385 (33) 240 (97) 27 522 135 44 43 136 - $(720) (95) (426) (88) 18 1 (590) (130) (37) (78) (89) - $ 840 171 355 21 126 24 697 143 5 70 78 11 $ $ 136 $ (89) $ 67 950 II-184 SoCo FOIA Response 002541 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Operating Revenues Operating revenues in 2010, 2009, and 2008 and the percent of change from the prior year were as follows: 2010 Amount 2009 2008 (in millions) Retail – prior year Estimated change in – Rates and pricing Sales growth (decline) Weather Fuel cost recovery Retail – current year Wholesale revenues – Non-affiliates Affiliates Total wholesale revenues Other operating revenues Total operating revenues Percent change $ 6,912 48 207 441 7,608 380 53 433 308 $ 8,349 8.5% $ 7,286 (64) (92) (6) (212) 6,912 395 112 507 273 $ 7,692 (8.6)% $ 6,498 397 (22) (37) 450 7,286 569 286 855 271 $ 8,412 11.1% Retail base revenues of $4.2 billion in 2010 increased by $255 million, or 6.5%, from 2009 primarily due to colder weather in the first and fourth quarters of 2010 and warmer weather in the second and third quarters of 2010. Residential base revenues increased $187 million, or 10.9%, commercial base revenues increased $50 million, or 3.1%, and industrial base revenues increased $17 million, or 3.1%. Revenues from changes in rates and pricing in 2010 were flat as the increased recognition of environmental compliance cost recovery revenues in accordance with the 2007 Retail Rate Plan were offset by pricing reductions from the structure of the Company’s base rate tariffs. Retail base revenues of $3.9 billion in 2009 decreased by $162 million, or 3.9%, from 2008 primarily due to lower industrial and commercial base revenues resulting from the recessionary economy and decreased revenues from market-response rates to large commercial and industrial customers. Industrial base revenues decreased $207 million, or 27.9%, and commercial base revenues decreased $36 million, or 2.1%. These decreases were partially offset by an increase in residential base revenues of $78 million, or 4.8%. All customer classes were positively affected by increased recognition of environmental compliance cost recovery revenues. Retail base revenues of $4.1 billion in 2008 increased by $338 million, or 9.0%, from 2007 primarily due to an increase in revenues from market-response rates to large commercial and industrial customers, the retail rate increase effective January 1, 2008, and a 0.7% increase in retail customers. The increase was partially offset by a weak economy in the Southeast and less favorable weather in 2008 than in 2007. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information. II-185 SoCo FOIA Response 002542 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Wholesale revenues from sales to non-affiliated utilities were as follows: 2010 2009 2008 (in millions) Unit power sales – Capacity Energy Total Other power sales – Capacity and other Energy Total Total non-affiliated $18 13 31 $ 43 26 69 $ 40 44 84 155 194 349 $380 140 186 326 $395 129 356 485 $ 569 Wholesale revenues from sales to non-affiliates consist of power purchase agreements (PPA), unit power sales (UPS) contracts, and short-term opportunity sales. Wholesale revenues from PPAs and unit power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues from sales to nonaffiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Revenues from unit power sales decreased $38 million, or 55.1%, in 2010 as a result of the UPS contract expiring on May 31, 2010. Revenues from unit power sales decreased $15 million, or 18.9%, in 2009 primarily due to a 26.0% decrease in kilowatt-hour (KWH) energy sales due to the recessionary economy and generally unfavorable weather. Revenues from unit power sales increased $18 million, or 27.4%, in 2008 driven by higher fuel costs and an 8.2% increase in the KWH sales primarily related to sales by the Company’s generating units when other Southern Company system units were unavailable. Revenues from other non-affiliated sales increased $23 million, or 7.1%, in 2010, decreased $159 million, or 32.7%, in 2009, and increased $13 million, or 2.7%, in 2008. The increase in 2010 was primarily due to higher fuel costs and revenues from a PPA that replaced the expired UPS contract discussed previously. The decrease in 2009 was due to lower natural gas prices and a 49.7% decrease in KWH sales due to the recessionary economy and generally unfavorable weather. The increase in 2008 was primarily driven by higher fuel and purchased power costs, partially offset by a 9.8% decrease in KWH sales and lower emissions allowance prices. Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). In 2010, wholesale revenues from sales to affiliates decreased 52.7% due to a 60.1% decrease in KWH sales as a result of lower demand because the market cost of available energy was lower than the cost of the Company’s available generation. In 2009, wholesale revenues from sales to affiliates decreased 60.9% due to lower natural gas prices and a 32.2% decrease in KWH sales due to the recessionary economy and generally unfavorable weather. In 2008, KWH sales to affiliated companies decreased 28.8% while revenues from sales to affiliates increased 3.0%. The revenue increase in 2008 was primarily due to the increased cost of fuel and other marginal generation components of the rates. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost. Other operating revenues increased $35 million, or 12.8%, in 2010 primarily due to a $25 million increase in transmission revenues related to increased usage of the Company’s transmission system by non-affiliated companies, an increase of $4 million in outdoor lighting revenues primarily as a result of new customer sales associated with government stimulus programs, and an increase of $6 million in late payment fees and customer maintenance request revenues. Other operating revenues remained relatively flat in 2009. Other operating revenues increased $13 million, or 4.8%, in 2008 primarily due to a $7 million increase in revenues from outdoor lighting and an $8 million increase in customer fees resulting from higher rates that went into effect in 2008, partially offset by a $2 million decrease in equipment rentals revenue. II-186 SoCo FOIA Response 002543 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Energy Sales Changes in revenues are influenced heavily by the change in volume of energy sold from year to year. KWH sales for 2010 and the percent change by year were as follows: Total KWHs 2010 Total KWH Percent Change 2009 2008 2010 Weather-Adjusted Percent Change 2009 2008 2010 (in billions) Residential Commercial Industrial Other Total retail 29.4 33.9 23.2 0.7 87.2 Wholesale Non-affiliates Affiliates Total wholesale Total energy sales 4.6 1.0 5.6 92.8 12.0% 3.9 6.4 (1.2) 7.1 (0.5)% (1.4) (9.7) 0.1 (3.5) (1.6)% 0.0 (5.2) (3.8) (2.1) 0.9% (0.4) 5.1 (1.9) 1.5% (0.5)% (0.9) (9.5) 0.4 (3.2)% (0.6)% 1.2 (4.8) (3.6) (1.2)% (46.6) (7.8) (10.5) (32.2) (28.8) (60.1) (42.7) (14.7) (26.6) 4.2% (8.9)% (4.0)% Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. In 2010, residential KWH sales increased 12.0%, commercial KWH sales increased 3.9%, and industrial KWH sales increased 6.4% compared to 2009 primarily due to colder weather in the first and fourth quarters of 2010 and warmer weather in the second and third quarters of 2010 and an improving economy. Residential KWH sales decreased 0.5% in 2009 compared to 2008 primarily due to slightly less favorable weather, partially offset by an increase of 0.2% in residential customers. Commercial and industrial KWH sales decreased 1.4% and 9.7%, respectively, in 2009 compared to 2008 due to the recessionary economy. During 2009, there was a broad decline in demand across all industrial segments, most significantly in the chemical, primary metals, textiles, and stone, clay, and glass sectors. Residential KWH sales decreased 1.6% in 2008 compared to 2007 primarily due to less favorable weather, partially offset by a 0.7% increase in residential customers. Commercial KWH sales remained flat in 2008 compared to 2007 despite a 0.2% increase in commercial customers. Industrial KWH sales decreased 5.2% in 2008 over 2007 primarily due to reduced demand and closures within the textile and primary and fabricated metal industries, which were a result of the slowing economy that worsened during the fourth quarter 2008. See “Operating Revenues” above for a discussion of significant changes in sales to non-affiliates and sales to affiliated companies. II-187 SoCo FOIA Response 002544 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Fuel and Purchased Power Expenses Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows: Total generation (billions of KWHs) Total purchased power (billions of KWHs) Sources of generation (percent) Coal Nuclear Gas Hydro Cost of fuel, generated (cents per net KWH) Coal Nuclear Gas Average cost of fuel, generated (cents per net KWH)* Average cost of purchased power (cents per net KWH) 2010 75.3 21.7 2009 72.4 20.4 2008 80.8 21.3 67 21 10 2 67 21 10 2 74 19 6 1 4.53 0.66 5.75 3.82 5.64 4.12 0.55 5.30 3.48 6.06 3.44 0.51 6.90 3.11 8.10 *Fuel includes fuel purchased by the Company for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power. Fuel and purchased power expenses were $4.0 billion in 2010, an increase of $352 million, or 9.5%, compared to 2009. This increase was due to a $160 million increase in the average cost of fossil and nuclear fuel and a $192 million increase related to more KWHs generated primarily due to higher customer demand as a result of colder weather in the first and fourth quarters 2010 and warmer weather in the second and third quarters 2010. Fuel and purchased power expenses were $3.7 billion in 2009, a decrease of $521 million, or 12.4%, below prior year costs. This decrease was due to a $371 million decrease related to fewer KWHs generated and purchased primarily due to lower customer demand as a result of the recessionary economy and a $150 million decrease in the average cost of purchased power, partially offset by an increase in the average cost of fuel. Fuel and purchased power expenses were $4.2 billion in 2008, an increase of $526 million, or 14.3%, above prior year costs. Substantially all of this increase was due to the higher average cost of fuel and purchased power. From an overall global market perspective, coal prices increased substantially in 2010 from the levels experienced in 2009, but remained lower than the unprecedented high levels of 2008. The slowly recovering U.S. economy and global demand from coal importing countries drove the higher prices in 2010, with concerns over regulatory actions, such as permitting issues, and their negative impact on production also contributing upward pressure. Domestic natural gas prices continued to be depressed by robust supplies, including production from shale gas, as well as lower demand. These lower natural gas prices contributed to increased use of natural gas fueled generating units in 2009 and 2010. Uranium prices remained relatively constant during the early portion of 2010 but rose steadily during the second half of the year. At year end, uranium prices remained well below the highs set during 2007. Worldwide uranium production levels increased in 2010; however, secondary supplies and inventories were still required to meet worldwide reactor demand. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information. II-188 SoCo FOIA Response 002545 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Other Operations and Maintenance Expenses In 2010, other operations and maintenance expenses increased $240 million, or 16.1%, compared to 2009. The increase was due to increases of $142 million in power generation, $74 million in transmission and distribution, and $25 million in customer accounting, service, and sales due to cost containment efforts in 2009 as a result of economic conditions. The increase in power generation operations and maintenance expenses was also due to higher generation levels to meet increased customer demand in 2010. In 2009, other operations and maintenance expenses decreased $88 million, or 5.5%, compared to 2008. The decrease was due to a $46 million decrease in power generation, a $28 million decrease in transmission and distribution, and a $32 million decrease in customer accounting, service, and sales, most of which were related to cost containment activities in an effort to offset the effects of the recessionary economy. In 2008, other operations and maintenance expenses increased $21 million, or 1.2%, compared to 2007. The increase was primarily the result of a $15 million increase in the accrual for property damage approved under the 2007 Retail Rate Plan, a $15 million increase in scheduled outages and maintenance for fossil generating plants, and a $22 million increase related to meter reading, records and collections, and uncollectible account expenses. These increases were partially offset by decreases of $25 million related to the timing of transmission and distribution operations and maintenance and $7 million related to medical, pension, and other employee benefits. Depreciation and Amortization Depreciation and amortization decreased $97 million, or 14.8%, in 2010 compared to the prior year. This decrease was primarily due to a $133 million increase in amortization of the regulatory liability related to other cost of removal obligations, as authorized by the Georgia PSC, partially offset by increased depreciation related to additional plant in service related to transmission, distribution, and environmental projects. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Rate Plans” herein, Note 1 to the financial statements under “Depreciation and Amortization,” and Note 3 to the financial statements under “Retail Regulatory Matters – Rate Plans” for additional information. Depreciation and amortization increased $18 million, or 2.9%, in 2009 compared to the prior year primarily due to additional plant in service related to transmission, distribution, and environmental projects, partially offset by the amortization of $41 million of the regulatory liability related to other cost of removal obligations. Depreciation and amortization increased $126 million, or 24.6%, in 2008 compared to the prior year primarily due to an increase in plant in service related to completed transmission, distribution, and environmental projects, changes in depreciation rates effective January 1, 2008 approved under the 2007 Retail Rate Plan, and the expiration of amortization related to a regulatory liability for purchased power costs under the terms of the retail rate plan for the three years ended December 31, 2007. Taxes Other Than Income Taxes In 2010, taxes other than income taxes increased $27 million, or 8.5%, from the prior year primarily due to higher municipal franchise fees resulting from retail revenue increases during 2010. In 2009, the increase in taxes other than income taxes was immaterial. In 2008, taxes other than income taxes increased $24 million, or 8.6%, from the prior year primarily due to higher municipal franchise fees resulting from retail revenue increases during 2008. Allowance for Funds Used During Construction Equity Allowance for funds used during construction (AFUDC) equity increased $50 million, or 51.5%, in 2010 primarily due to the increase in construction related to three new combined cycle units at Plant McDonough, two new nuclear generating units at Plant Vogtle (Plant Vogtle Units 3 and 4), and ongoing environmental and transmission projects. In 2009, the increase in AFUDC equity as compared to 2008 was immaterial. AFUDC equity increased $27 million, or 39.8%, in 2008 primarily due to the increase in construction related to ongoing environmental and transmission projects, as well as the new units at Plant McDonough. See FUTURE EARNINGS POTENTIAL – “Construction” herein and Note 3 to the financial statements under “Construction” for additional information. II-189 SoCo FOIA Response 002546 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Interest Expense, Net of Amounts Capitalized In 2010, interest expense, net of amounts capitalized decreased $11 million, or 2.8%, primarily due to a $14 million increase in interest capitalized in 2010 compared to the prior year. In 2009, interest expense, net of amounts capitalized increased $41 million, or 11.7%, primarily due to an increase in long-term debt levels resulting from the issuance of additional senior notes and pollution control bonds to fund the Company’s ongoing construction program. The increase in interest expense in 2008 as compared to 2007 was immaterial. Other Income (Expense), Net Other income (expense), net decreased $20 million in 2010 primarily as a result of lower revenues of $9 million from non-operating activities and increased donations of $5 million. Other income (expense), net increased $7 million, or 80.8%, in 2009 primarily related to $2 million and $1 million increases in customer contracting and income resulting from purchases by large commercial and industrial customers of hedges against market-response rates, respectively, and a decrease of $2 million in donations. Other income (expense), net decreased $23 million, or 163.0%, in 2008 primarily due to a $13 million change in classification of revenues related to a residential pricing program to base retail revenues in 2008 as ordered by the Georgia PSC under the 2007 Retail Rate Plan, as well as decreased revenues of $7 million and $3 million related to non-operating rental income and customer contracting, respectively. Income Taxes Income taxes increased $43 million, or 10.5%, in 2010 primarily due to higher pre-tax earnings, partially offset by increases in nontaxable AFUDC equity and state tax credits. Income taxes decreased $78 million, or 15.9%, in 2009 primarily due to changes in pretax income. Income taxes increased $70 million, or 16.8%, in 2008 primarily due to increased pre-tax net income and the effect of deductions for the Company’s donation of 2,200 acres in the Tallulah Gorge area to the State of Georgia in 2007. This increase was partially offset by an increase in AFUDC equity, as well as additional state tax credits and an increase in the federal production activities deduction. Effects of Inflation The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company’s results of operations has not been substantial in recent years. FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Georgia PSC under cost-based regulatory principles. Prices for electricity relating to wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and revenues are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information about regulatory matters. The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the Company’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company’s service area. Changes in economic conditions impact sales for the Company, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. II-190 SoCo FOIA Response 002547 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. The Company’s environmental compliance cost recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. The action was filed concurrently with the issuance of a notice of violation of the NSR provisions to the Company. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against the Company, has been administratively closed since the spring of 2001, and the case has not been reopened. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot now be determined. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. II-191 SoCo FOIA Response 002548 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Statutes and Regulations General The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2010, the Company had invested approximately $3.7 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of $217 million, $440 million, and $689 million for 2010, 2009, and 2008, respectively. The Company expects that capital expenditures to comply with existing statutes and regulations will be $73 million, $79 million, and $58 million in 2011, 2012, and 2013, respectively. These environmental costs that are known and estimable at this time are included under the heading “Capital” in the table under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $69 million to $289 million in 2011, $191 million to $651 million in 2012, and $476 million to $1.4 billion in 2013. The Company’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of any new or revised environmental statutes and regulations that are enacted, including the proposed environmental legislation and regulations described below; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel mix. Compliance with any new federal or state legislation or regulations relating to global climate change, air quality, coal combustion byproducts, including coal ash, water quality, or other environmental and health concerns could also significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, the full II-192 SoCo FOIA Response 002549 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report impact of any such changes cannot be determined at this time. Additionally, many of the Company’s commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2010, the Company had spent approximately $3.4 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls are currently planned and others are under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements. The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone air quality standard. A 20county area within metropolitan Atlanta is the only location within the Company’s service area that is currently designated as nonattainment for the current standard. On November 30, 2010, the EPA extended the attainment date for this area by one year as a result of improving air quality. In March 2008, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the level of the standard. Under the EPA’s current schedule, a final revision to the eight-hour ozone standard is expected in July 2011, with state implementation plans for any resulting nonattainment areas due in mid-2014. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within the Company’s service territory and could result in additional required reductions in NOx emissions. During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within the Company’s service area. State implementation plans demonstrating attainment with annual standards have been submitted to the EPA. The EPA is expected to propose new annual and 24-hour fine particulate matter standards during the summer of 2011. Final revisions to the National Ambient Air Quality Standard for SO2, including the establishment of a new one-hour standard, became effective on August 23, 2010. Since the EPA intends to rely on computer modeling for implementation of the SO2 standard, the identification of potential nonattainment areas remains uncertain and could ultimately include areas within the Company’s service territory. Implementation of the revised SO2 standard could result in additional required reductions in SO2 emissions and increased compliance and operation costs. Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2), which established a new one-hour standard, became effective on April 12, 2010. Although none of the areas within the Company’s service territory are expected to be designated as nonattainment for the NO2 standard, based on current ambient air quality monitoring data, the new NO2 standard could result in significant additional compliance and operational costs for units that require new source permitting. Twenty-eight eastern states, including the States of Georgia and Alabama, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. The States of Georgia and Alabama have completed their plans to implement CAIR, and emissions reductions are being accomplished by the installation and operation of emissions controls at the Company’s coal-fired facilities and/or by the purchase of emissions allowances. On August 2, 2010, the EPA published a proposed rule, referred to as the Transport Rule, to replace CAIR. This proposed rule would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO2 and NOx that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Georgia and Alabama, to reduce annual emissions of SO2 and NOx from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Georgia and Alabama, to achieve additional reductions in NOx emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requested comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA stated that it also intends to develop a second phase of the Transport Rule in 2011 to address the more stringent ozone air quality standards after they are finalized. The EPA expects to finalize the Transport Rule in June 2011 and require compliance beginning in 2012. The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology II-193 SoCo FOIA Response 002550 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report (BART) to certain sources built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO2 and NOx, and no additional controls beyond CAIR are anticipated to be necessary at any of the Company’s facilities. The State of Georgia is currently completing its implementation plan for BART compliance and other measures required to achieve the first phase of reasonable progress. The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal- and oil-fired electric generating units which will establish emission limitations for numerous hazardous air pollutants, including mercury. As part of a proceeding in the U.S. District Court for the District of Columbia, the EPA has entered into a consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011. On April 29, 2010, the EPA issued a proposed Industrial Boiler (IB) MACT rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA issued the final rules on February 23, 2011 and, at the same time, issued a notice of intent to reconsider the final rules to allow for additional public review and comment. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time. The impacts of the eight-hour ozone, fine particulate matter, SO2 and NO2 standards, the proposed Transport Rule, the Clean Air Visibility Rule, and the proposed MACT rules for electric generating units and industrial boilers on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any pending and future legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company has already installed a number of SO2 and NOx emissions controls to ensure continued compliance with applicable air quality requirements. In addition to the federal air quality laws described above, the Company also is subject to the requirements of the State of Georgia’s Multi-Pollutant Rule, which was adopted in 2007. The Multi-Pollutant Rule is designed to reduce emissions of mercury, SO2, and NOx state-wide by requiring the installation of specified control technologies at certain coal-fired generating units by specific dates between December 31, 2008 and June 1, 2015. The State of Georgia also adopted a companion rule that requires a 95% reduction in SO2 emissions from the controlled units on the same or similar timetable. Through December 31, 2010, the Company had installed the required controls on 10 of its largest coal-fired generating units and is in the process of installing the required controls on six additional units. As a result of uncertainties related to the potential federal air quality regulations described above, the Company has suspended certain work related to both the installation of emissions control equipment at Plant Branch Units 1 and 2 and Plant Yates Units 6 and 7 and the conversion of Plant Mitchell from coal-fired to biomass-fired. The Company continues to analyze the potential costs and benefits of installing the required controls on its remaining coal-fired generating units in light of the potential federal regulations described above. The Company may determine that retiring and replacing certain of these existing units with new generating resources or purchased power is more economically efficient than installing the required environmental controls. The Company currently expects to file an update to its integrated resource plan in June 2011. Under the terms of the 2010 ARP, any costs associated with changes to the Company’s approved environmental operating or capital budgets (resulting from new or revised environmental regulations) through 2013 that are approved by the Georgia PSC in connection with an updated integrated resource plan will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Such costs that may be deferred as a regulatory asset include any impairment losses that may result from a decision to retire certain units that are no longer cost effective in light of new or modified environmental regulations. In addition, in connection with the 2010 ARP, the Georgia PSC also approved revised depreciation rates that will recover the remaining book value of certain of the Company’s existing coal-fired units by December 31, 2014. The ultimate outcome of these matters cannot be determined at this time. II-194 SoCo FOIA Response 002551 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Water Quality In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. In April 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is expected to propose revisions to the regulations in March 2011 and issue final regulations in mid-2012. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on the specific provisions of the EPA’s final rule and on the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time. However, if the final rules require the installation of cooling towers at certain existing facilities of the Company, the Company may be subject to significant additional compliance costs and capital expenditures that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. In December 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted, and the EPA has announced its intention to adopt such revisions by January 2014. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain of the Company’s facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, and, therefore, cannot be determined at this time. Environmental Remediation The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” for additional information. Coal Combustion Byproducts The Company currently operates 11 electric generating plants with on-site coal combustion byproduct storage facilities (some with both “wet” (ash ponds) and “dry” (landfill) storage facilities). In addition to on-site storage, the Company also sells a portion of its coal combustion byproducts to third parties for beneficial reuse (approximately one-fourth in recent years). Historically, individual states have regulated coal combustion byproducts and the states in Southern Company’s service territory, including the States of Georgia and Alabama, each have their own regulatory parameters. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments and compliance with applicable regulations. The EPA is currently evaluating whether additional regulation of coal combustion byproducts (including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June 21, 2010, the EPA published a proposed rule that requested comments on two potential regulatory options for the management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of, or significant change to, existing storage facilities and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. On November 19, 2010, Southern Company filed publicly available comments with the EPA regarding the rulemaking proposal. These comments included a preliminary cost analysis under various alternatives in the rulemaking proposal. The Company regards these estimates as pre-screening figures that should be distinguished from the more formalized cost estimates the Company provides for projects that are more definite as to the elements and timing of execution. Although its analysis was preliminary, Southern Company concluded that potential compliance costs under the proposed rules would be substantially higher than the estimates reflected in the EPA’s rulemaking proposal. The ultimate financial and operational impact of any new regulations relating to coal combustion byproducts cannot be determined at this time and will be dependent upon numerous factors. These factors include: whether coal combustion byproducts will be regulated II-195 SoCo FOIA Response 002552 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report as hazardous waste or non-hazardous waste; whether the EPA will require early closure of existing wet storage facilities; whether beneficial reuse will be limited or eliminated through a hazardous waste designation; whether the construction of lined landfills is required; whether hazardous waste landfill permitting will be required for on-site storage; whether additional waste water treatment will be required; the extent of any additional groundwater monitoring requirements; whether any equipment modifications will be required; the extent of any changes to site safety practices under a hazardous waste designation; and the time period over which compliance will be required. There can be no assurance as to the timing of adoption or the ultimate form of any such rules. While the ultimate outcome of this matter cannot be determined at this time, and will depend on the final form of any rules adopted and the outcome of any legal challenges, additional regulation of coal combustion byproducts could have a material impact on the generation, management, beneficial use, and disposal of such byproducts. Any material changes are likely to result in substantial additional compliance, operational, and capital costs that could affect future unit retirement and replacement decisions. Moreover, the Company could incur additional material asset retirement obligations with respect to closing existing storage facilities. The Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. Global Climate Issues Although the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas emissions, neither this legislation nor similar measures passed the U.S. Senate before the end of the 2010 session. Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are expected to continue to be considered in Congress. The financial and operational impacts of climate or energy legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal, natural gas, and biomass prices, and cost recovery through regulated rates. While climate legislation has yet to be adopted, the EPA is moving forward with regulation of greenhouse gases under the Clean Air Act. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. In December 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, which began on January 2, 2011, applies to sources and projects that would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed settlement agreement to issue standards of performance for greenhouse gas emissions from new and modified fossil fuel-fired electric generating units and greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012. All of the EPA’s final Clean Air Act rulemakings have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit; however, the court declined motions to stay the rules pending resolution of those challenges. As a result, the rules may impact the amount of time it takes to obtain PSD permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate outcome of these rules cannot be determined at this time and will depend on the content of the final rules and the outcome of any legal challenges. II-196 SoCo FOIA Response 002553 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The most recent round of negotiations took place in December 2010. The outcome and impact of the international negotiations cannot be determined at this time. Although the outcome of federal, state, and international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. See Item 1 – BUSINESS – “Rate Matters – Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. In 2009, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 48 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2010 is approximately 51 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The Company is actively constructing new generating facilities with lower greenhouse gas emissions. These include Plant Vogtle Units 3 and 4 and three combined cycle units at Plant McDonough. The Company has also proposed the conversion of Plant Mitchell from coal-fired to biomass generation and is currently evaluating the costs and viability of other renewable technologies for the State of Georgia. On February 2, 2010, the Georgia PSC approved the Company’s request to delay construction activities related to Plant Mitchell pending the EPA’s anticipated issuance of regulations associated with coal combustion byproducts and the IB MACT rule described previously. PSC Matters Rate Plans The economic recession significantly reduced the Company’s revenues upon which retail rates were set by the Georgia PSC for 2008 through 2010 under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce expenses, the Company’s projected retail return on common equity (ROE) for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, in June 2009, the Company filed a request with the Georgia PSC for an accounting order that would allow the Company to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. In August 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, the Company could amortize up to $108 million of the regulatory liability in 2009 and up to $216 million in 2010, limited to the amount needed to earn no more than a 9.75% and 10.15% retail ROE in 2009 and 2010, respectively. For the years ended December 31, 2009 and 2010, the Company amortized $41 million and $174 million of the regulatory liability, respectively. On December 21, 2010, the Georgia PSC approved the 2010 ARP, which became effective January 1, 2011. The terms of the 2010 ARP reflect a settlement agreement among the Company, the Georgia PSC’s Public Interest Advocacy Staff (PSC Staff), and eight other intervenors. Under the terms of the 2010 ARP, the Company will amortize approximately $92 million of its remaining regulatory liability related to other cost of removal obligations over the three years ending December 31, 2013. Also under the terms of the 2010 ARP, effective January 1, 2011, the Company increased its (1) traditional base tariff rates by approximately $347 million; (2) Demand-Side Management (DSM) tariff rates by approximately $31 million; (3) ECCR tariff rate by approximately $168 million; and (4) Municipal Franchise Fee (MFF) tariff rate by approximately $16 million, for a total increase in base revenues of approximately $562 million. II-197 SoCo FOIA Response 002554 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Under the 2010 ARP, the following additional base rate adjustments will be made to the Company’s tariffs in 2012 and 2013:  Effective January 1, 2012, the DSM tariffs will increase by $17 million;  Effective April 1, 2012, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Units 4 and 5 for the period from commercial operation through December 31, 2013;  Effective January 1, 2013, the DSM tariffs will increase by $18 million;  Effective January 1, 2013, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Unit 6 for the period from commercial operation through December 31, 2013; and  The MFF tariff will increase consistent with these adjustments. The Company currently estimates these adjustments will result in annualized base revenue increases of approximately $190 million in 2012 and $93 million in 2013. Under the 2010 ARP, the Company’s retail ROE is set at 11.15%, and earnings will be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25 % will be directly refunded to customers, with the remaining one-third retained by the Company. If at any time during the term of the 2010 ARP, the Company projects that retail earnings will be below 10.25% for any calendar year, it may petition the Georgia PSC for the implementation of an Interim Cost Recovery (ICR) tariff to adjust the Company’s earnings back to a 10.25% retail ROE. The Georgia PSC will have 90 days to rule on any such request. If approved, any ICR tariff would expire at the earlier of January 1, 2014 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR, the Company may file a full rate case. Except as provided above, the Company will not file for a general base rate increase while the 2010 ARP is in effect. The Company is required to file a general rate case by July 1, 2013, in response to which the Georgia PSC would be expected to determine whether the 2010 ARP should be continued, modified, or discontinued. Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved increases in the Company’s total annual billings of approximately $222 million effective June 1, 2008 and $373 million effective April 1, 2010. In addition, the Georgia PSC has authorized an interim fuel rider, which would allow the Company to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered balance exceeds budget by more than $75 million. The Company is currently required to file its next fuel case by March 1, 2011. The Company’s under recovered fuel balance totaled approximately $398 million of which approximately $214 million is included in deferred charges and other assets in the balance sheets at December 31, 2010. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. See Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information. Legislation Stimulus Funding On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S. Department of Energy (DOE), formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. The Company will receive, and will match, $51 million under the agreement. The ultimate outcome of this matter cannot be determined at this time. II-198 SoCo FOIA Response 002555 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Healthcare Reform On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, the Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in tax law must be recognized in the period enacted regardless of the effective date. However, the Company deferred the related impact as a regulatory asset, which is being amortized over 12 years, in accordance with the 2010 ARP, and therefore had no material impact on the Company’s financial statements. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and related employee benefit plan costs. Any future impact on the Company’s financial statements cannot be determined at this time. See Note 5 to the financial statements under “Current and Deferred Income Taxes” for additional information. Income Tax Matters Georgia State Income Tax Credits The Company’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. The Company filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) has not responded to these claims. In July 2007, the Company filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of the Company’s motion for summary judgment. The Georgia DOR has appealed to the Georgia Court of Appeals and a decision is expected later this year. Any decision may be subject to further appeal to the Georgia Supreme Court. An unrecognized tax benefit has been recorded related to these credits. If the Company prevails, no material impact on the Company’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers in accordance with the 2010 ARP. If the Company is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on the Company’s cash flow. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot now be determined. Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $133 million for the Company. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. Bonus Depreciation On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which could have a significant impact on the future cash flows of the Company. II-199 SoCo FOIA Response 002556 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report The application of the bonus depreciation provisions in these acts in 2010 provided approximately $168 million in increased cash flow. The Company estimates the potential increased cash flow for 2011 to be between approximately $275 million and $350 million. Internal Revenue Code Section 199 Domestic Production Deduction The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 2010, and none is projected to be available for 2011. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. Construction Nuclear In August 2009, the Nuclear Regulatory Commission (NRC) issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of the Company, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), related to Plant Vogtle Units 3 and 4. See Note 4 to the financial statements for additional information on these co-owners. In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units. If licensed by the NRC, Plant Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively. In April 2008, the Company, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement). The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that will be subject to certain price escalations and adjustments, including fixed escalation amounts and certain indexbased adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. The Company’s proportionate share is 45.7%. The Owners and the Consortium have agreed to certain liquidated damages upon the Consortium’s failure to comply with the schedule and performance guarantees. The Consortium’s liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events. In March 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve the inclusion of the related construction work in progress accounts in rate base. In April 2009 the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows the Company to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. With respect to Plant Vogtle Units 3 and 4, this legislation allows the Company to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. II-200 SoCo FOIA Response 002557 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report The Georgia PSC has ordered the Company to report against this total certified cost of approximately $6.1 billion. In addition, on December 21, 2010, the Georgia PSC approved the Company’s Nuclear Construction Cost Recovery (NCCR) tariff. The NCCR tariff became effective January 1, 2011 and is expected to collect approximately $223 million in revenues during 2011. On February 21, 2011, the Georgia PSC voted to approve the Company’s third semi-annual construction monitoring report including total costs of $1.048 billion for Plant Vogtle Units 3 and 4 incurred through June 30, 2010. In connection with its certification of Vogtle Units 3 and 4, the Georgia PSC ordered the Company and the PSC Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize the Company’s earnings if and when overruns are due to mandates from governing agencies. Such discussions have continued through the third semi-annual construction monitoring proceedings; however, the Georgia PSC has deferred a decision with respect to any related incentive or risk-sharing mechanism until a later date. The Company will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period. In 2009, the Southern Alliance for Clean Energy (SACE) and the Fulton County Taxpayers Foundation, Inc. (FCTF) filed separate petitions in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. On May 5, 2010, the court dismissed as premature the plaintiffs’ claim challenging the Georgia Nuclear Energy Financing Act. FCTF appealed the decision, and the Georgia Supreme Court ruled against FCTF, finding the suit premature. In addition, on May 5, 2010, the Superior Court of Fulton County issued an order remanding the Georgia PSC’s certification order for inclusion of further findings of fact and conclusions of law by the Georgia PSC. In compliance with the court’s order, the Georgia PSC issued its order on remand to include further findings of fact and conclusions of law on June 23, 2010. On July 5, 2010, SACE and FCTF filed separate motions with the Georgia PSC for reconsideration of the order on remand. On August 17, 2010, the Georgia PSC voted to reaffirm its order. The matter is no longer subject to judicial review and is now concluded. On December 2, 2010, Westinghouse submitted an AP1000 Design Certification Amendment (DCA) to the NRC. On February 10, 2011, the NRC announced that it was seeking public comment on a proposed rule to approve the DCA and amend the certified AP1000 reactor design for use in the U.S. The Advisory Committee on Reactor Safeguards also issued a letter on January 24, 2011 endorsing the issuance of the COL for Plant Vogtle Units 3 and 4. The Company currently expects to receive the COL for Plant Vogtle Units 3 and 4 from the NRC in late 2011 based on the NRC's February 16, 2011 release of its COL schedule framework. There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds. The ultimate outcome of these matters cannot be determined at this time. Other Construction On May 6, 2010, the Georgia PSC approved the Company’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. As a result, the units are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. To date, the Georgia PSC has approved the Company’s quarterly construction monitoring reports, including actual project expenditures incurred, through June 30, 2010. The Company will continue to file quarterly construction monitoring reports throughout the construction period. Other Matters The Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse II-201 SoCo FOIA Response 002558 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues. ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors. Electric Utility Regulation The Company is subject to retail regulation by the Georgia PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company. As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements. Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following: • Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters. • Changes in existing income tax regulations or changes in IRS or Georgia DOR interpretations of existing regulations. • Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party. • Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. • Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, the Georgia DOR, the FERC, or the EPA. II-202 SoCo FOIA Response 002559 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Unbilled Revenues Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations. Pension and Other Postretirement Benefits The Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. Key elements in determining the Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company’s investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company’s target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. A 25 basis point change in any significant assumption would result in a $9 million or less change in total benefit expense and a $112 million or less change in projected obligations. FINANCIAL CONDITION AND LIQUIDITY Overview The Company’s financial condition remained stable at December 31, 2010. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information. The Company’s investments in the qualified pension plan and the nuclear decommissioning trust funds remained stable in value as of December 31, 2010. In December 2010, the Company contributed $168 million to the qualified pension plan. The Company will fund approximately $3 million, $2 million, and $2 million to its nuclear decommissioning trust funds in 2011, 2012, and 2013, respectively. Net cash provided from operating activities totaled $1.8 billion in 2010, an increase of $429 million from 2009, primarily due to a $136 million increase in net income, fuel inventory reductions in 2010 compared to additions in 2009, and a net increase of $94 million in deferred and prepaid income taxes primarily due to the extension of bonus depreciation and the change in the tax accounting method for repair costs (See FUTURE EARNINGS POTENTIAL – “Income Tax Matters – Tax Method of Accounting For Repairs” and “Bonus Depreciation” herein), partially offset by the contributions to the qualified pension plan. Net cash provided from operating activities totaled $1.4 billion in 2009, a decrease of $310 million from 2008, primarily due to an $89 million decrease in net income, a reduction in deferred revenues of approximately $172 million, a reduction in accrued compensation of approximately $123 million, and an increase in fuel inventory additions of approximately $150 million, partially offset by a reduction in accounts receivable of approximately $210 million. Net cash provided from operating activities totaled $1.7 billion in 2008, an increase of II-203 SoCo FOIA Response 002560 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report $279 million from 2007, primarily due to higher retail operating revenues partially offset by higher inventory additions. Net cash used for investing activities totaled $2.2 billion, $2.4 billion, and $1.9 billion in 2010, 2009, and 2008, respectively, due to gross property additions primarily related to installation of equipment to comply with environmental standards; construction of generation, transmission, and distribution facilities; and purchase of nuclear fuel. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, capital contributions from Southern Company, and the issuance of debt. Net cash provided from financing activities totaled $391 million, $881 million, and $310 million for 2010, 2009, and 2008, respectively. These totals are primarily related to additional issuances of senior notes and capital contributions from Southern Company in all years. The statements of cash flows provide additional details. See “Financing Activities” herein. Significant balance sheet changes in 2010 include a $1.6 billion increase in total property, plant, and equipment related to the construction activities discussed above. Other significant balance sheet changes in 2010 include an increase in paid-in capital of $698 million reflecting equity contributions from Southern Company. Significant balance sheet changes in 2009 include a $1.9 billion increase in total property, plant, and equipment and a $776 million increase in long-term debt to provide funds for the Company’s continuous construction program. The Company’s ratio of common equity to total capitalization, including short-term debt, was 48.8% in 2010 and 47.8% in 2009. See Note 6 to the financial statements for additional information. Sources of Capital Except as described below with respect to potential DOE loan guarantees, the Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend on prevailing market conditions, regulatory approvals, and other factors. On June 18, 2010, the Company reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future borrowings by the Company related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to the Company and secured by a first priority lien on the Company’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the COL for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for the Company. See FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” herein and Note 3 to the financial statements under “Construction – Nuclear” for more information on Plant Vogtle Units 3 and 4. The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of shortterm debt securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended. The amounts of securities authorized by the Georgia PSC and the FERC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. The Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source for under recovered fuel costs and to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, at December 31, 2010 the Company had credit arrangements with banks totaling $1.7 billion. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. In addition, the Company has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. II-204 SoCo FOIA Response 002561 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report At December 31, 2010, bank credit arrangements were as follows: Total Unused Expires 2011 2012 (in millions) $1,715 $1,703 $595 $1,120 Of the credit arrangements that expire in 2011, $40 million allow for the execution of term loans for an additional two-year period, and $220 million allow for execution of term loans for a one-year period. These credit arrangements provide liquidity support to the Company’s variable rate pollution control revenue bonds and commercial paper borrowings. As of December 31, 2010, the Company had $385 million outstanding pollution control revenue bonds requiring liquidity support. Subsequent to December 31, 2010, the Company’s remarketing of $137 million of variable rate pollution control revenue bonds increased the total requiring liquidity support to $522 million. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from issuances for the benefit of any other operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support. As of December 31, 2010, the Company had $575 million of outstanding commercial paper. During 2010, the maximum amount of commercial paper outstanding was $575 million and the average amount outstanding was $167 million. During 2009, the maximum amount of commercial paper outstanding was $757 million and the average amount outstanding was $348 million. The weighted average annual interest rate on commercial paper in 2010 and 2009 was 0.3% and 0.4%, respectively. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash. Financing Activities In March 2010, the Company issued $350 million aggregate principal amount of Series 2010A Floating Rate Senior Notes due March 15, 2013. The net proceeds were used to repay at maturity $250 million aggregate principal amount of Series 2008A Floating Rate Senior Notes due March 17, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including the Company’s continuous construction program. In June 2010, the Company issued $600 million aggregate principal amount of Series 2010B 5.40% Senior Notes due June 1, 2040. The net proceeds from the sale of the Series 2010B Senior Notes were used for the redemption of all of the $200 million aggregate principal amount of the Company’s Series R 6.00% Senior Notes due October 15, 2033 and all of the $150 million aggregate principal amount of the Company’s Series O 5.90% Senior Notes due April 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including the Company’s continuous construction program. In September 2010, the Company issued $500 million aggregate principal amount Series 2010C 4.75% Senior Notes due September 1, 2040. The net proceeds were used to redeem all of the $250 million aggregate principal amount of the Company’s Series X 5.70% Senior Notes due January 15, 2045, $125 million aggregate principal amount of the Company’s Series W 6.00% Senior Notes due August 15, 2044, $100 million aggregate principal amount of the Company’s Series T 5.75% Senior Public Income Notes due January 15, 2044, and $35 million aggregate principal amount of the Company’s Series G 5.75% Senior Notes due December 1, 2044. Also in September 2010, the Company issued $500 million aggregate principal amount Series 2010D 1.30% Senior Notes due September 15, 2013. The net proceeds were used for the repurchase of all of the $114 million aggregate principal amount of outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2009, due January 1, 2049; $40 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2009, due January 1, 2049; $173 million aggregate principal amount of the outstanding Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009, due December 1, 2032; $89 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2009, due October 1, 2048; and $46 million aggregate principal amount of the outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1996, due October 1, 2032, and for other general corporate purposes, including the Company’s continuous II-205 SoCo FOIA Response 002562 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report construction program. The pollution control revenue bonds repurchased by the Company are being held by the Company and may be remarketed to investors in the future. In December 2010, the Development Authority of Floyd County issued $53 million aggregate principal amount Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2010 (the 2010 Bonds) for the benefit of the Company, and the 2010 Bonds were purchased by the Company. The proceeds from the issuance of the 2010 Bonds were used in December 2010 to purchase and cancel the $53 million aggregate principal amount Development Authority of Floyd County Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2008. In January 2011, the Company remarketed the 2010 Bonds to investors. Also subsequent to December 31, 2010, the Company issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay a portion of the Company’s outstanding short-term indebtedness and for general corporate purposes, including the Company’s continuous construction program. In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Credit Rating Risk The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. At December 31, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $27 million. At December 31, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.4 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market. On August 12, 2010, Moody’s Investors Service (Moody’s) downgraded the issuer and long-term debt ratings of the Company (senior unsecured to A3 from A2). Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of several Southern Company subsidiaries (including the Company) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of the Company to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of the Company to Baa2 from Baa1. Moody’s also downgraded the trust preferred securities rating of the Company to Baa1 from A3. Moody’s also announced that the ratings outlook for the Company is stable. On December 22, 2010, Fitch Ratings, Inc. announced that the ratings outlook of the Company had been revised from negative to stable. Market Price Risk Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market rate volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis. To mitigate future exposure to changes in interest rates, the Company enters into derivatives that have been designated as hedges. The weighted average interest rate on $1.0 billion of outstanding variable rate long-term debt at January 1, 2011 was 0.57%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $10 million at January 1, 2011. For further information, see Note 1 to the financial II-206 SoCo FOIA Response 002563 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report statements under “Financial Instruments” and Note 11 to the financial statements. To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The Company continues to manage a fuel hedging program implemented per the guidelines of the Georgia PSC. The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the years ended December 31 were as follows: 2009 2010 Changes Changes Fair Value (in millions) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes(a) Contracts outstanding at the end of the period, assets (liabilities), net $ $ $ (75) 85 (110) (100) $ (113) 150 (112) (75) (a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any. The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2010 was a decrease of $25 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 2010, the Company had a net hedge volume of 58.7 million mmBtu with a weighted average contract cost approximately $1.74 per mmBtu above market prices, and 64.6 million mmBtu at December 31, 2009 with a weighted average contract cost approximately $1.16 per mmBtu above market prices. All natural gas hedges gains and losses are recovered through the Company’s fuel cost recovery mechanism. At December 31, 2010 and 2009, substantially all of the Company’s energy-related derivative contracts were designated as regulatory hedges and are related to the Company’s fuel hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery mechanism. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented. The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 10 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2010 were as follows: Total Fair Value December 31, 2010 Fair Value Measurements Maturity Year 1 Years 2&3 Years 4&5 (in millions) Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period $ (100) $ (100) $ (77) $ (77) $ $ (23) (23) $ $ - The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s, a division of The McGraw Hill Companies, Inc., or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements. II-207 SoCo FOIA Response 002564 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of overthe-counter derivatives. The impact, if any, cannot be determined until regulations are finalized. Capital Requirements and Contractual Obligations The construction program of the Company is currently estimated to include a base level investment of $2.1 billion, $2.2 billion, and $2.0 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $73 million, $79 million, and $58 million for 2011, 2012, and 2013, respectively. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $69 million to $289 million in 2011, $191 million to $651 million in 2012, and $476 million to $1.4 billion in 2013. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 and Note 7 to the financial statements under “Construction – Nuclear” and “Construction Program,” respectively, for additional information. As a result of requirements by the NRC, the Company has established external trust funds for nuclear decommissioning costs. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC and the FERC. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 6, 7, and 11 to the financial statements for additional information. II-208 SoCo FOIA Response 002565 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Contractual Obligations 2011 20122013 20142015 After 2015 Uncertain Timing (d) Total (in millions) Long-term debt(a) – Principal Interest Preferred and preference stock dividends(b) Energy-related derivative obligations(c) Operating leases Capital leases Unrecognized tax benefits and interest(d) Purchase commitments(e) – Capital(f) Limestone (g) Coal Nuclear fuel Natural gas(h) Purchased power Long-term service agreements(i) Trusts – Nuclear decommissioning(j) Pension and other postretirement benefit plans(k) Total $ 411 378 17 77 36 4 203 $ 1,575 731 35 24 37 9 - $ 250 642 35 22 11 - $ 6,069 5,846 8 35 - $ 61 $ 8,305 7,597 87 101 103 59 264 1,858 17 1,869 252 445 316 18 3,878 36 1,538 333 984 509 102 30 786 263 769 464 111 10 1,182 585 2,665 1,726 467 - 5,736 93 5,375 1,433 4,863 3,015 698 3 22 $ 5,926 4 52 $ 9,847 4 $3,387 35 $ 18,628 $ 61 46 74 $ 37,849 (a) All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2011, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). (b) Preferred and preference stock does not mature; therefore, amounts provided are for the next five years only. (c) For additional information, see Notes 1 and 11 to the financial statements. (d) The timing related to the realization of $61 million in unrecognized tax benefits and corresponding interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. Of the total $264 million, $144 million is the estimated cash payment. See Note 3 under “Income Tax Matters” and Note 5 under “Unrecognized Tax Benefits” to the financial statements for additional information. (e) The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2010, 2009, and 2008 were $1.7 billion, $1.5 billion, and $1.6 billion, respectively. (f) The Company provides forecasted capital expenditures for a three-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for nuclear fuel. In addition, such amounts exclude the Company’s estimates of potential incremental investments to comply with anticipated new environmental regulations which could range from $69 million to $289 million in 2011, $191 million to $651 million in 2012, and $476 million to $1.4 billion in 2013. At December 31, 2010, significant purchase commitments were outstanding in connection with the construction program. (g) As part of the Company’s program to reduce SO2 emissions from its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. (h) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2010. (i) Long-term service agreements include price escalation based on inflation indices. (j) Projections of nuclear decommissioning trust fund contributions are based on the 2010 ARP. (k) The Company forecasts contributions to the qualified pension and other postretirement benefit plans over a three-year period. The Company does not expect to be required to make any contributions to the qualified pension plan during the next three years. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company’s corporate assets. II-209 SoCo FOIA Response 002566 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2010 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company’s 2010 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, customer growth, economic recovery, fuel cost recovery and other rate actions, environmental regulations and expenditures, the Company’s projections for qualified pension plan, other postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, impacts of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, start and completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: • • • • • • • • • • • • • • • • • • • • • • the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, mercury, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters and the pending EPA civil action against the Company; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population, business growth (and declines), and the effects of energy conservation measures; available sources and costs of fuels; effects of inflation; ability to control costs and avoid cost overruns during the development and construction of facilities; investment performance of the Company’s employee benefit plans and nuclear decommissioning trust funds; advances in technology; state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases related to fuel and other cost recovery mechanisms; regulatory approvals and actions related to the Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers; the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings; the ability of the Company to obtain additional generating capacity at competitive prices; catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC. The Company expressly disclaims any obligation to update any forward-looking statements II-210 SoCo FOIA Response 002567 STATEMENTS OF INCOME For the Years Ended December 31, 2010, 2009, and 2008 Georgia Power Company 2010 Annual Report 2010 2009 2008 (in millions) Operating Revenues: Retail revenues Wholesale revenues, non-affiliates Wholesale revenues, affiliates Other revenues Total operating revenues Operating Expenses: Fuel Purchased power, non-affiliates Purchased power, affiliates Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Interest income Interest expense, net of amounts capitalized Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Net Income Dividends on Preferred and Preference Stock Net Income After Dividends on Preferred and Preference Stock $7,608 380 53 308 8,349 $6,912 395 112 273 7,692 $7,286 569 286 271 8,412 3,102 368 578 1,734 558 344 6,684 1,665 2,717 269 710 1,494 655 317 6,162 1,530 2,812 443 962 1,582 637 316 6,752 1,660 147 5 (375) (22) (245) 1,420 453 967 17 $ 950 97 2 (386) (2) (289) 1,241 410 831 17 $ 814 95 7 (345) (9) (252) 1,408 488 920 17 $ 903 The accompanying notes are an integral part of these financial statements. II-211 SoCo FOIA Response 002568 STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2010, 2009, and 2008 Georgia Power Company 2010 Annual Report 2009 2010 2008 (in millions) Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating activities -Depreciation and amortization, total Deferred income taxes Deferred revenues Deferred expenses Allowance for equity funds used during construction Pension, postretirement, and other employee benefits Pension and postretirement funding Hedge settlements Insurance cash surrender value Other, net Changes in certain current assets and liabilities --Receivables -Fossil fuel stock -Materials and supplies -Prepaid income taxes -Other current assets -Accounts payable -Accrued taxes -Accrued compensation -Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Distribution of restricted cash from pollution control revenue bonds Nuclear decommissioning trust fund purchases Nuclear decommissioning trust fund sales Cost of removal, net of salvage Change in construction payables, net of joint owner portion Other investing activities Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds -Capital contributions from parent company Pollution control revenue bonds issuances Senior notes issuances Other long-term debt issuances Redemptions -Pollution control revenue bonds Capital leases Senior notes Payment of preferred and preference stock dividends Payment of common stock dividends Other financing activities Net cash provided from financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Supplemental Cash Flow Information: Cash paid during the period for -Interest (net of $54, $40 and $40 capitalized, respectively) Income taxes (net of refunds) $ 967 $ 831 $ 920 724 342 (101) (13) (147) 21 (195) 1 20 791 191 (49) (4) (97) 2 (22) (19) 20 24 758 171 123 2 (95) 19 (22) (23) 2 168 103 (7) (36) (2) (99) 31 62 8 1,847 127 (242) (6) 21 (1) (54) (19) (101) 25 1,418 (83) (92) (20) (15) (18) (56) 118 22 17 1,728 (2,190) (1,772) 1,768 (67) 36 (19) (2,244) (2,515) 27 (989) 984 (56) 106 25 (2,418) (1,848) 33 (419) 412 (63) 3 (38) (1,920) (33) (358) 252 688 1,950 (516) (3) (1,112) (18) (820) (30) 391 (6) 14 $ 8 $339 149 931 417 1,000 1 (327) (2) (333) (18) (739) (16) 881 (119) 133 $ 14 $341 228 273 386 1,000 301 (336) (1) (198) (17) (721) (19) 310 118 15 $ 133 $309 280 The accompanying notes are an integral part of these financial statements. II-212 SoCo FOIA Response 002569 BALANCE SHEETS At December 31, 2010 and 2009 Georgia Power Company 2010 Annual Report Assets 2009 2010 (in millions) Current Assets: Cash and cash equivalents Receivables -Customer accounts receivable Unbilled revenues Under recovered regulatory clause revenues Joint owner accounts receivable Other accounts and notes receivable Affiliated companies Accumulated provision for uncollectible accounts Fossil fuel stock, at average cost Materials and supplies, at average cost Vacation pay Prepaid income taxes Other regulatory assets, current Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Plant in service, net of depreciation Nuclear fuel, at amortized cost Construction work in progress Total property, plant, and equipment Other Property and Investments: Equity investments in unconsolidated subsidiaries Nuclear decommissioning trusts, at fair value Miscellaneous property and investments Total other property and investments Deferred Charges and Other Assets: Deferred charges related to income taxes Prepaid pension costs Deferred under recovered regulatory clause revenues Other regulatory assets, deferred Other deferred charges and assets Total deferred charges and other assets Total Assets $ 8 580 172 184 60 67 21 (11) 624 371 78 99 105 80 2,438 $ 14 487 172 292 147 63 12 (10) 726 363 75 133 77 61 2,612 26,397 9,966 16,431 386 3,287 20,104 25,120 9,493 15,627 340 2,521 18,488 70 818 42 930 66 580 39 685 723 91 214 1,207 207 2,442 $25,914 609 373 1,322 206 2,510 $24,295 The accompanying notes are an integral part of these financial statements. II-213 SoCo FOIA Response 002570 BALANCE SHEETS At December 31, 2010 and 2009 Georgia Power Company 2010 Annual Report Liabilities and Stockholder's Equity 2009 2010 (in millions) Current Liabilities: Securities due within one year Notes payable Accounts payable -Affiliated Other Customer deposits Accrued taxes -Unrecognized tax benefits Other accrued taxes Accrued interest Accrued vacation pay Accrued compensation Liabilities from risk management activities Other cost of removal obligations, current Other regulatory liabilities, current Nuclear decommissioning trust securities lending collateral Other current liabilities Total current liabilities Long-Term Debt (See accompanying statements) Deferred Credits and Other Liabilities: Accumulated deferred income taxes Deferred credits related to income taxes Accumulated deferred investment tax credits Employee benefit obligations Asset retirement obligations Other cost of removal obligations Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Preferred Stock (See accompanying statements) Preference Stock (See accompanying statements) Common Stockholder's Equity (See accompanying statements) Total Liabilities and Stockholder's Equity Commitments and Contingent Matters (See notes) $ 415 576 $ 254 324 243 574 198 239 602 200 187 328 94 58 109 77 31 1 144 134 3,169 7,931 165 291 89 58 43 50 216 100 14 69 2,714 7,782 3,718 129 229 684 705 131 211 5,807 16,907 45 221 8,741 $25,914 3,390 134 242 923 677 125 139 5,630 16,126 45 221 7,903 $24,295 The accompanying notes are an integral part of these financial statements. II-214 SoCo FOIA Response 002571 STATEMENTS OF CAPITALIZATION At December 31, 2010 and 2009 Georgia Power Company 2010 Annual Report 2009 2010 (in millions) Long-Term Debt: Long-term debt payable to affiliated trusts -5.88% due 2044 Long-term notes payable -Variable rate (0.80% at 1/1/10) due 2010 Variable rate (0.78% at 1/1/11) due 2011 Variable rate (0.62% at 1/1/11) due 2013 4.00% to 5.57% due 2011 5.125% due 2012 1.30% to 6.00% due 2013 5.25% due 2015 4.25% to 8.20% due 2017-2048 Total long-term notes payable Other long-term debt -Pollution control revenue bonds: 0.80% to 5.75% due 2016-2048 Variable rate (0.39% at 1/1/11) due 2011 Variable rate (0.33% to 0.46% at 1/1/11) due 2016-2041 Total other long-term debt Capitalized lease obligations Unamortized debt discount Total long-term debt (annual interest requirement -- $377.7 million) Less amount due within one year Long-term debt excluding amount due within one year Preferred and Preference Stock: Non-cumulative preferred stock $25 par value -- 6.125% Authorized - 50,000,000 shares Outstanding - 1,800,000 shares Non-cumulative preference stock $100 par value -- 6.50% Authorized - 15,000,000 shares Outstanding - 2,250,000 shares Total preferred and preference stock (annual dividend requirement -- $17.4 million) Common Stockholder's Equity: Common stock, without par value -Authorized: 20,000,000 shares Outstanding: 9,261,500 shares Paid-in capital Retained earnings Accumulated other comprehensive income (loss) Total common stockholder's equity Total Capitalization $ 206 $ 2009 (percent of total) 206 300 350 103 200 1,025 250 4,351 6,579 250 300 103 200 525 250 4,113 5,741 1,134 8 1,134 8 377 1,519 59 (17) 893 2,035 63 (9) 8,346 415 7,931 8,036 254 7,782 45 45 221 221 266 266 398 5,291 3,063 (11) 8,741 $16,938 2010 398 4,593 2,933 (21) 7,903 $15,951 46.8% 48.8% 1.6 1.7 51.6 100.0% 49.5 100.0% The accompanying notes are an integral part of these financial statements. II-215 SoCo FOIA Response 002572 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2010, 2009, and 2008 Georgia Power Company 2010 Annual Report Number of Common Shares Issued Common Stock Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total (in millions) Balance at December 31, 2007 Net income after dividends on preferred and preference stock Capital contributions from parent company Other comprehensive loss Cash dividends on common stock Balance at December 31, 2008 Net income after dividends on preferred and preference stock Capital contributions from parent company Other comprehensive income Cash dividends on common stock Balance at December 31, 2009 Net income after dividends on preferred and preference stock Capital contributions from parent company Other comprehensive income Cash dividends on common stock Balance at December 31, 2010 $(14) 9 $398 $3,375 $2,676 - - - 903 9 398 281 3,656 - - - 9 398 937 4,593 (739) 2,933 12 (21) 937 12 (739) 7,903 9 398 698 $ 5,291 950 (820) $ 3,063 10 $(11) 950 698 10 (820) $ 8,741 $ (721) 2,858 814 (19) (33) - The accompanying notes are an integral part of these financial statements. II-216 SoCo FOIA Response 002573 $6,435 903 281 (19) (721) 6,879 814 STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2010, 2009, and 2008 Georgia Power Company 2010 Annual Report 2009 2010 2008 (in millions) Net income after dividends on preferred and preference stock Other comprehensive income (loss): Qualifying hedges: Changes in fair value, net of tax of $-, $(1), and $(13), respectively Reclassification adjustment for amounts included in net income, net of tax of $6, $9, and $1, respectively Total other comprehensive income (loss) Comprehensive Income $950 10 10 $960 $814 (2) 14 12 $826 The accompanying notes are an integral part of these financial statements. II-217 SoCo FOIA Response 002574 $903 (21) 2 (19) $884 NOTES TO FINANCIAL STATEMENTS Georgia Power Company 2010 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Georgia Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power Company (Alabama Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants, including the Company’s Plants Hatch and Vogtle. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment, but is not the primary beneficiary. The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Georgia Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $552 million in 2010, $506 million in 2009, and $490 million in 2008. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $473 million in 2010, $398 million in 2009, and $410 million in 2008. The Company has entered into several power purchase agreements (PPA) with Southern Power for capacity and energy. Expenses associated with these PPAs were $199 million, $411 million, and $480 million in 2010, 2009, and 2008, respectively. Additionally, the Company had $26 million and $24 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2010 and 2009, respectively. See Note 7 under “Purchased Power Commitments” for additional information. The Company has an agreement with Gulf Power under which Gulf Power jointly owns a portion of Plant Scherer Unit 3. Under this agreement, the Company operates Plant Scherer Unit 3 and Gulf Power reimburses the Company for its 25% proportionate share of the related non-fuel expenses, which were $9 million in 2010, $4 million in 2009, and $8 million in 2008. See Note 4 for additional information. II-218 SoCo FOIA Response 002575 NOTES (continued) Georgia Power Company 2010 Annual Report The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any significant services to or from affiliates in 2010, 2009, or 2008. Also see Note 4 for information regarding the Company’s ownership in and a PPA with Southern Electric Generating Company (SEGCO) and Note 5 for information on certain deferred tax liabilities due to affiliates. The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information. II-219 SoCo FOIA Response 002576 NOTES (continued) Georgia Power Company 2010 Annual Report Regulatory Assets and Liabilities The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of governmental regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2010 2009 Note (in millions) Deferred income tax charges Deferred income tax charges – Medicare subsidy Loss on reacquired debt Vacation pay Retiree benefit plans Fuel-hedging (realized and unrealized) losses Building leases Generating plant outage costs Other regulatory assets Asset retirement obligations Other cost of removal obligations Deferred income tax credits Environmental compliance cost recovery Other regulatory liabilities Total assets (liabilities), net $ 676 51 176 78 883 108 45 31 40 69 (162) (129) (1) $1,865 $ 609 157 75 952 82 47 39 49 116 (341) (134) (96) (1) $1,554 (a) (e) (b) (c, h) (e, h) (f) (i) (j) (d) (a, h) (a) (a) (g) (b, f) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 60 years. Asset retirement and other cost of removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2010, other cost of removal obligations included $92 million that will be amortized over a three-year period beginning January 1, 2011 in accordance with a Georgia PSC order. See Note 3 under “Retail Regulatory Matters – Rate Plans” for additional information. (b) Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue which may range up to 50 years. (c) Recorded as earned by employees and recovered as paid, generally within one year. (d) Recorded and recovered or amortized as approved by the Georgia PSC over periods not exceeding five years. (e) Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 under “Pension Plans” and “Other Postretirement Benefits” and Note 5 under “Current and Deferred Income Taxes” for additional information. (f) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, costs are recovered through the Company’s fuel cost recovery mechanism. (g) Deferred revenue associated with the levelization of the environmental compliance cost recovery (ECCR) tariff revenues for the years 2008 through 2010 in accordance with a Georgia PSC order. (h) Not earning a return as offset in rate base by a corresponding asset or liability. (i) See Note 6 under “Capital Leases.” Recovered over the remaining lives of the buildings through 2026. (j) See “Property, Plant, and Equipment.” Recovered over the respective operating cycles, which range from 18 months to 10 years. In the event that a portion of the Company’s operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off or reclassify to accumulated other comprehensive income (OCI) related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are reflected in rates. II-220 SoCo FOIA Response 002577 NOTES (continued) Georgia Power Company 2010 Annual Report Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs and the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under “Nuclear Fuel Disposal Costs” for additional information. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost, less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction. The Company’s property, plant, and equipment consisted of the following at December 31: 2010 2009 (in millions) Generation Transmission Distribution General Plant acquisition adjustment Total plant in service $ 12,852 4,187 7,855 1,475 28 $ 26,397 $ 12,185 3,891 7,603 1,413 28 $ 25,120 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling outage costs over the unit’s operating cycle. The refueling cycles are 18 and 24 months for Plants Vogtle and Hatch, respectively. Also, in accordance with a Georgia PSC order, the Company defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle. II-221 SoCo FOIA Response 002578 NOTES (continued) Georgia Power Company 2010 Annual Report The amount of non-cash property additions recognized for the years ended December 31, 2010, 2009 and 2008 was $310 million, $243 million, and $137 million, respectively. These amounts were comprised of construction related accounts payable outstanding at each year end together with retention amounts accrued during the respective year. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0% in 2010 and 2009 and 2.9% in 2008. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC. Effective January 1, 2011, the Company’s depreciation rates were revised by the Georgia PSC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. In August 2009, the Georgia PSC approved an accounting order allowing the Company to amortize a portion of its regulatory liability related to other cost of removal obligations. See Note 3 under “Retail Regulatory Matters – Rate Plans” for additional information. Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 3 under “Retail Regulatory Matters - Rate Plans” for additional information related to the Company’s cost of removal regulatory liability. The asset retirement obligation liability primarily relates to the Company’s nuclear facilities, which include the Company’s ownership interests in Plants Hatch and Vogtle. In addition, the Company has retirement obligations related to various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with the Company’s rail lines. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income the allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. See “Nuclear Decommissioning” herein for further information on amounts included in rates. Details of the asset retirement obligations included in the balance sheets are as follows: 2010 2009 (in millions) Balance at beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions Balance at end of year $ 681 (12) 43 $ 712 $ 690 2 (7) 44 (48) $ 681 II-222 SoCo FOIA Response 002579 NOTES (continued) Georgia Power Company 2010 Annual Report Nuclear Decommissioning The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (the Funds) to comply with the NRC’s regulations. Use of the Funds is restricted to nuclear decommissioning activities and the Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Georgia PSC, as well as the Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds’ managers to exercise the standard of care in investing that a “prudent investor” would use in the same circumstances. The FERC regulations also require, except for investments tied to market indices or other mutual funds, that the Funds’ managers may not invest in any securities of the utility for which it manages funds or its affiliates. In addition, the NRC prohibits investments in securities of power reactor licensees. While the Company is allowed to prescribe an overall investment policy to the Funds’ managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the Company’s management. The Funds’ managers are authorized, within broad limits, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. The Funds participate in a securities lending program through the managers of the Funds. Under this program, the Funds’ investment securities are loaned to investment brokers for a fee. Securities so loaned are fully collateralized by cash, letters of credit, and securities issued or guaranteed by the U.S. government, its agencies, and the instrumentalities. As of December 31, 2010 and 2009, approximately $141 million and $14 million, respectively, of the fair market value of the Funds’ securities were on loan and pledged to creditors under the Funds’ managers’ securities lending program. The fair value of the collateral received was approximately $144 million and $14 million at December 31, 2010 and 2009, respectively, and can only be sold upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows. At December 31, 2010, investment securities in the Funds totaled $818 million, consisting of equity securities of $258 million, debt securities of $493 million, and $67 million of other securities. At December 31, 2009, investment securities in the Funds totaled $580 million, consisting of equity securities of $429 million, debt securities of $138 million, and $13 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases and the lending pool. Sales of the securities held in the Funds resulted in cash proceeds of $1.8 billion, $984 million, and $412 million in 2010, 2009, and 2008, respectively, all of which were reinvested. For 2010, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $74 million, of which $25 million of losses related to securities held in the Funds at December 31, 2010. For 2009, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $119 million, of which $118 million related to securities held in the Funds at December 31, 2009. For 2008, fair value reductions, including reinvested interest and dividends and excluding the Funds’ expenses, were $(144) million. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of and purpose for which the securities were acquired. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. II-223 SoCo FOIA Response 002580 NOTES (continued) Georgia Power Company 2010 Annual Report Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning are based on the most current study performed in 2009. The site study costs and accumulated provisions for decommissioning as of December 31, 2010 based on the Company’s ownership interests were as follows: Decommissioning periods: Beginning year Completion year Plant Hatch Plant Vogtle 2034 2063 2047 2067 Site study costs: Radiated structures Non-radiated structures Total site study costs $ 583 46 $ 629 $ 500 71 $ 571 Accumulated provision $ 360 $ 206 (in millions) The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. For ratemaking purposes, the Company’s decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2006. The NRC estimates are $575 million and $420 million for Plant Hatch and Plant Vogtle Units 1 and 2 , respectively. The Georgia PSC approved annual decommissioning costs for ratemaking of $3 million annually for Plant Vogtle Units 1 and 2 for 2008 through 2010. Under the Company’s alternate rate plan, effective January 1, 2011 and continuing through December 31, 2013 (2010 ARP), the annual decommissioning cost for ratemaking is $2 million for Plant Hatch. Based on estimates approved in the 2010 ARP, the Company projects the external trust funds for Plant Vogtle Units 1 and 2 would be adequate to meet the decommissioning obligations of the NRC with no further contributions. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4%. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Allowance for Funds Used During Construction (AFUDC) In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2010, 2009, and 2008, the average AFUDC rates were 8.0%, 8.0%, and 8.2%, respectively, and AFUDC capitalized was $201 million, $137 million, and $135 million, respectively. AFUDC, net of income taxes, was 19.0%, 14.9%, and 13.3% of net income after dividends on preferred and preference stock for 2010, 2009, and 2008, respectively. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. II-224 SoCo FOIA Response 002581 NOTES (continued) Georgia Power Company 2010 Annual Report Storm Damage Reserve The Company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property as mandated by the Georgia PSC. Under the retail rate plan effective January 1, 2008 (2007 Retail Rate Plan), the Company accrued $21 million annually that was recoverable through base rates. Starting January 1, 2011, the Company will accrue $18 million annually under the 2010 ARP. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel hedging program. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2010. The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. II-225 SoCo FOIA Response 002582 NOTES (continued) Georgia Power Company 2010 Annual Report Variable Interest Entities The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. However, the Company is not considered the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as other investments, and the related loans from the trusts are reflected as long-term debt in the balance sheets. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information. 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2010, the Company contributed approximately $168 million to the qualified pension plan. No contributions to the qualified pension plan are expected for the year ending December 31, 2011. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the FERC. For the year ending December 31, 2011, other postretirement trust contributions are expected to total approximately $22 million. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2007 for the 2008 plan year using a discount rate of 6.30% and an annual salary increase of 3.75%. 2010 Discount rate: Pension plans Other postretirement benefit plans Annual salary increase Long-term return on plan assets: Pension plans Other postretirement benefit plans 2009 2008 5.52% 5.40 3.84 5.93% 5.83 4.18 6.75% 6.75 3.75 8.75 7.24 8.50 7.35 8.50 7.38 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate of 8.25% for 2011, decreasing gradually to 5.00% through the year 2019 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2010 as follows: 1 Percent 1 Percent Increase Decrease (in millions) Benefit obligation Service and interest costs $ 63 3 $ 54 3 II-226 SoCo FOIA Response 002583 NOTES (continued) Georgia Power Company 2010 Annual Report Pension Plans The total accumulated benefit obligation for the pension plans was $2.5 billion in 2010 and $2.4 billion in 2009. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2009 2010 (in millions) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial loss (gain) Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability $ 2,517 54 145 (127) 85 2,674 $ 2,238 48 147 (122) 206 2,517 2,237 335 176 (127) 2,621 $ (53) 2,038 314 7 (122) 2,237 $ (280) At December 31, 2010, the projected benefit obligations for the qualified and non-qualified pension plans were $2.5 billion and $144 million, respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s pension plans consist of the following: 2009 2010 (in millions) Prepaid pension costs Other regulatory assets, deferred Current liabilities, other Employee benefit obligations $ 91 689 (9) (135) $ 734 (8) (272) Presented below are the amounts included in regulatory assets at December 31, 2010 and 2009 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2011. 2009 2010 Estimated Amortization in 2011 (in millions) Prior service cost Net (gain) loss Other regulatory assets, deferred $ $ 61 628 689 $ $ 73 661 734 $ 12 6 II-227 SoCo FOIA Response 002584 NOTES (continued) Georgia Power Company 2010 Annual Report The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2010 and 2009 are presented in the following table: Regulatory Assets (in millions) $ 642 108 - Balance at December 31, 2008 Net loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net (gain) Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 (14) (2) (16) 92 $ 734 (30) (13) (2) (15) (45) $ 689 Components of net periodic pension cost (income) were as follows: 2009 2010 2008 (in millions) Service cost Interest cost Expected return on plan assets Recognized net loss Net amortization Net periodic pension cost (income) $ 48 147 (216) 2 14 $ (5) $ 54 145 (220) 2 13 $ (6) $ 49 134 (211) 3 14 $ (11) Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the marketrelated value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2010, estimated benefit payments were as follows: Benefit Payments (in millions) 2011 2012 2013 2014 2015 2016 to 2020 $ 139 144 149 154 160 889 II-228 SoCo FOIA Response 002585 NOTES (continued) Georgia Power Company 2010 Annual Report Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2009 2010 (in millions) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial (gain)/loss Plan amendments Retiree drug subsidy Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability $ 782 9 44 (44) (7) 2 786 $ 772 10 50 (43) 8 (18) 3 782 369 37 29 (42) 393 $ (393) 312 66 31 (40) 369 $ (413) Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s other postretirement benefit plans consist of the following: 2009 2010 (in millions) Regulatory assets Employee benefit obligations $ 179 (393) $ 202 (413) Presented below are the amounts included in regulatory assets at December 31, 2010 and 2009 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2011. 2009 2010 Estimated Amortization in 2011 (in millions) Prior service cost Net (gain) loss Transition obligation Regulatory assets $ $ 10 152 17 179 $ $ 11 167 24 202 $ 1 3 7 II-229 SoCo FOIA Response 002586 NOTES (continued) Georgia Power Company 2010 Annual Report The changes in the balance of regulatory assets, related to the other postretirement benefit plans for the plan years ended December 31, 2010 and 2009 are presented in the following table: Regulatory Assets (in millions) $ 261 (28) (18) Balance at December 31, 2008 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 (8) (2) (3) (13) (59) $ 202 (13) (6) (1) (3) (10) (23) $ 179 Components of the other postretirement benefit plans’ net periodic cost were as follows: 2010 2009 2008 (in millions) Service cost Interest cost Expected return on plan assets Net amortization Net postretirement cost $ 9 44 (30) 10 $ 33 $ 10 50 (30) 13 $ 43 $ 10 50 (30) 16 $ 46 The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2010, 2009, and 2008 by approximately $11 million, $14 million, and $14 million, respectively, and is expected to have a similar impact on future expenses. Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows: Benefit Payments Subsidy Receipts Total (in millions) 2011 2012 2013 2014 2015 2016 to 2020 $ 50 52 54 57 59 307 $ (3) (4) (4) (5) (5) (29) $ 47 48 50 52 54 278 II-230 SoCo FOIA Response 002587 NOTES (continued) Georgia Power Company 2010 Annual Report Benefit Plan Assets Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The composition of the Company’s pension plan and other postretirement benefit plan assets as of December 31, 2010 and 2009, along with the targeted mix of assets for each plan, is presented below: Pension plan assets: Domestic equity International equity Fixed income Special situations Real estate investments Private equity Total Target 2010 2009 29% 28 15 3 15 10 100% 29% 27 22 13 9 100% 33% 29 15 13 10 100% Other postretirement benefit plan assets: Domestic equity 41% International equity 22 Fixed income 31 Special situations 1 Real estate investments 3 Private equity 2 Total 100% 41% 24 30 3 2 100% 34% 29 32 3 2 100% The investment strategy for plan assets related to the Company’s qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is longterm in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. An actively-managed mix of growth stocks and value stocks with both developed and emerging market exposure. • Fixed income. A mix of domestic and international bonds. • Trust-owned life insurance. Investments of the Company’s taxable trusts aimed at minimizing the impact of taxes on the portfolio. II-231 SoCo FOIA Response 002588 NOTES (continued) Georgia Power Company 2010 Annual Report • Special situations. Though currently unfunded, established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private-market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2010 and 2009. The fair values presented are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund. The fair values of pension plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: $ U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total $ 486 490 1 71 1,048 $ 196 170 117 95 226 77 183 $ 1,064 $ $ 1 258 245 504 $ 682 660 117 95 227 77 184 329 245 $ 2,616 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. II-232 SoCo FOIA Response 002589 NOTES (continued) Georgia Power Company 2010 Annual Report As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: $ 444 574 U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $ 1 69 1,088 $ (2) 1,086 $ 184 57 $ 165 45 111 4 136 702 $ 702 $ - $ 628 631 $ 217 221 438 165 45 111 4 137 286 221 $ 2,228 $ 438 (2) $ 2,226 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 are as follows: 2010 Real Estate Investments Private Equity 2009 Real Estate Investments Private Equity (in millions) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $ 217 $ 221 $ 336 $ 196 15 7 22 19 $ 258 18 7 25 (1) $ 245 (98) (26) (124) 5 $ 217 14 4 18 7 $ 221 II-233 SoCo FOIA Response 002590 NOTES (continued) Georgia Power Company 2010 Annual Report The fair values of other postretirement benefit plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: $ U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Special situations Real estate investments Private equity Total $ 98 16 2 116 $ $ 33 39 $ 4 3 7 28 11 132 257 $ 8 8 16 $ 131 55 4 3 7 28 11 132 10 8 389 $ *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in millions) Assets: Domestic equity* International equity* Fixed income: $ U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Special situations Real estate investments Private equity Total $ 82 20 2 104 $ $ 29 31 5 2 4 17 26 126 240 $ $ 8 8 16 $ $ 111 51 5 2 4 17 26 126 10 8 360 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. II-234 SoCo FOIA Response 002591 NOTES (continued) Georgia Power Company 2010 Annual Report Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 are as follows: 2010 Real Estate Investments Private Equity 2009 Real Estate Investments Private Equity (in millions) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year $ 8 $ 8 Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $ 8 $ 12 $ 7 $ 8 (3) (1) (4) $ 8 1 1 $ 8 Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2010, 2009, and 2008 were $23 million, $25 million, and $25 million, respectively. 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. Environmental Matters New Source Review Actions In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. The action was filed concurrently with the issuance of a notice of violation of the NSR provisions to the Company. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against the Company, has been administratively closed since the spring of 2001, and the case has not been reopened. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against II-235 SoCo FOIA Response 002592 NOTES (continued) Georgia Power Company 2010 Annual Report Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot now be determined. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the II-236 SoCo FOIA Response 002593 NOTES (continued) Georgia Power Company 2010 Annual Report case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Remediation The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. The Company accrued $1 million annually for environmental remediation expenses during 2008 through 2010 that was recoverable through its ECCR tariff. Beginning in 2011, the Company is accruing approximately $3 million annually under the 2010 ARP. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As of December 31, 2010, the balance of the environmental remediation liability was $13 million, with approximately $3 million included in other regulatory assets, current and approximately $3 million included as other regulatory assets, deferred. The Company has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated. The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the financial statements. In September 2008, the EPA advised the Company that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices regarding this site from the EPA. The Company, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, in April 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including the Company, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, as a result of the regulatory treatment previously described, it is not expected to have a material impact on the Company’s financial statements. Income Tax Matters Georgia State Income Tax Credits The Company’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. The Company filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) has not responded to these claims. In July 2007, the Company filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of the Company’s motion for summary judgment. The Georgia DOR has appealed to the Georgia Court of Appeals and a decision is expected later this year. Any decision may be subject to further appeal to the Georgia Supreme Court. An unrecognized tax benefit has been recorded related to these credits. If the Company prevails, no material impact on the Company’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers in accordance with the 2010 ARP. If the Company is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on the Company’s cash flow. See Note 5 under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. II-237 SoCo FOIA Response 002594 NOTES (continued) Georgia Power Company 2010 Annual Report Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $133 million for the Company. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. The ultimate outcome of this matter cannot be determined at this time. See Note 5 under “Unrecognized Tax Benefits” for additional information. Nuclear Fuel Disposal Costs The Company has contracts with the U.S., acting through the U.S. Department of Energy (DOE), that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and the Company is pursuing legal remedies against the government for breach of contract. In July 2007, the U.S. Court of Federal Claims awarded the Company approximately $30 million, based on its ownership interests, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Hatch and Vogtle from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April 2008. On May 5, 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay. In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of December 31, 2010 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on the Company’s net income is expected as any damage amounts collected from the government are expected to be returned to customers. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plant Hatch, an on-site dry spent fuel storage facility is operational and can be expanded to accommodate spent fuel through the expected life of the plant. Retail Regulatory Matters Rate Plans The economic recession significantly reduced the Company’s revenues upon which retail rates were set by the Georgia PSC for 2008 through 2010 under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce expenses, the Company’s projected retail return on common equity (ROE) for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, in June 2009, the Company filed a request with the Georgia PSC for an accounting order that would allow the Company to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. In August 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, the Company could amortize up to $108 million of the regulatory liability in 2009 and up to $216 million in 2010, limited to the amount needed to earn no more than a 9.75% and 10.15% retail ROE in 2009 and 2010, respectively. For the years ended December 31, 2009 and 2010, the Company amortized $41 million and $174 million of the regulatory liability, respectively. On December 21, 2010, the Georgia PSC approved the 2010 ARP, which became effective January 1, 2011. The terms of the 2010 ARP reflect a settlement agreement among the Company, the Georgia PSC’s Public Interest Advocacy Staff (PSC Staff), and eight other intervenors. Under the terms of the 2010 ARP, the Company will amortize approximately $92 million of its remaining regulatory liability related to other cost of removal obligations over the three years ending December 31, 2013. II-238 SoCo FOIA Response 002595 NOTES (continued) Georgia Power Company 2010 Annual Report Also under the terms of the 2010 ARP, effective January 1, 2011, the Company increased its (1) traditional base tariff rates by approximately $347 million; (2) Demand-Side Management (DSM) tariff rates by approximately $31 million; (3) ECCR tariff rate by approximately $168 million; and (4) Municipal Franchise Fee (MFF) tariff rate by approximately $16 million, for a total increase in base revenues of approximately $562 million. Under the 2010 ARP, the following additional base rate adjustments will be made to the Company’s tariffs in 2012 and 2013:  Effective January 1, 2012, the DSM tariffs will increase by $17 million;  Effective April 1, 2012, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Units 4 and 5 for the period from commercial operation through December 31, 2013;  Effective January 1, 2013, the DSM tariffs will increase by $18 million;  Effective January 1, 2013, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Unit 6 for the period from commercial operation through December 31, 2013; and  The MFF tariff will increase consistent with these adjustments. The Company currently estimates these adjustments will result in annualized base revenue increases of approximately $190 million in 2012 and $93 million in 2013. Under the 2010 ARP, the Company’s retail ROE is set at 11.15%, and earnings will be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25 % will be directly refunded to customers, with the remaining one-third retained by the Company. If at any time during the term of the 2010 ARP, the Company projects that retail earnings will be below 10.25% for any calendar year, it may petition the Georgia PSC for the implementation of an Interim Cost Recovery (ICR) tariff to adjust the Company’s earnings back to a 10.25% retail ROE. The Georgia PSC will have 90 days to rule on any such request. If approved, any ICR tariff would expire at the earlier of January 1, 2014 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR, the Company may file a full rate case. Except as provided above, the Company will not file for a general base rate increase while the 2010 ARP is in effect. The Company is required to file a general rate case by July 1, 2013, in response to which the Georgia PSC would be expected to determine whether the 2010 ARP should be continued, modified, or discontinued. The Company currently expects to file an update to its integrated resource plan in June 2011. Under the terms of the 2010 ARP, any costs associated with changes to the Company’s approved environmental operating or capital budgets (resulting from new or revised environmental regulations) through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Such costs that may be deferred as a regulatory asset include any impairment losses that may result from a decision to retire certain units that are no longer cost effective in light of new or modified environmental regulations. In addition, in connection with the 2010 ARP, the Georgia PSC also approved revised depreciation rates that will recover the remaining book value of certain of the Company’s existing coal-fired units by December 31, 2014. The ultimate outcome of these matters cannot be determined at this time. Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved increases in the Company’s total annual billings of approximately $222 million effective June 1, 2008 and $373 million effective April 1, 2010. In addition, the Georgia PSC has authorized an interim fuel rider, which would allow the Company to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered fuel balance exceeds budget by more than $75 million. The Company is currently required to file its next fuel case by March 1, 2011. The Company’s under recovered fuel balance totaled approximately $398 million, of which approximately $214 million is included in deferred charges and other assets in the balance sheets at December 31, 2010. Fuel cost recovery revenues as recorded in the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. II-239 SoCo FOIA Response 002596 NOTES (continued) Georgia Power Company 2010 Annual Report Construction Nuclear In August 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of the Company, Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). See Note 4 for additional information on these co-owners. In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units. If licensed by the NRC, Plant Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively. In April 2008, the Company, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement). The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that will be subject to certain price escalations and adjustments, including fixed escalation amounts and certain indexbased adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. The Company’s proportionate share is 45.7%. The Owners and the Consortium have agreed to certain liquidated damages upon the Consortium’s failure to comply with the schedule and performance guarantees. The Consortium’s liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events. In March 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve the inclusion of the related construction work in progress accounts in rate base. In April 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows the Company to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. With respect to Plant Vogtle Units 3 and 4, this legislation allows the Company to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. The Georgia PSC has ordered the Company to report against this total certified cost of approximately $6.1 billion. In addition, on December 21, 2010, the Georgia PSC approved the Company’s Nuclear Construction Cost Recovery (NCCR) tariff. The NCCR tariff became effective January 1, 2011 and is expected to collect approximately $223 million in revenues during 2011. On February 21, 2011, the Georgia PSC voted to approve the Company’s third semi-annual construction monitoring report including total costs of $1.048 billion for Plant Vogtle Units 3 and 4 incurred through June 30, 2010. In connection with its certification of Vogtle Units 3 and 4, the Georgia PSC ordered the Company and the PSC Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize the Company’s earnings if and when overruns are due to mandates from governing agencies. Such discussions have continued through the third semi-annual construction monitoring proceedings; however, the Georgia PSC has deferred a decision with respect to any related incentive or risk-sharing mechanism until a later date. The Company will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period. II-240 SoCo FOIA Response 002597 NOTES (continued) Georgia Power Company 2010 Annual Report In 2009, the Southern Alliance for Clean Energy (SACE) and the Fulton County Taxpayers Foundation, Inc. (FCTF) filed separate petitions in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. On May 5, 2010, the court dismissed as premature the plaintiffs’ claim challenging the Georgia Nuclear Energy Financing Act. FCTF appealed the decision, and the Georgia Supreme Court ruled against FCTF, finding the suit premature. In addition, on May 5, 2010, the Superior Court of Fulton County issued an order remanding the Georgia PSC’s certification order for inclusion of further findings of fact and conclusions of law by the Georgia PSC. In compliance with the court’s order, the Georgia PSC issued its order on remand to include further findings of fact and conclusions of law on June 23, 2010. On July 5, 2010, SACE and FCTF filed separate motions with the Georgia PSC for reconsideration of the order on remand. On August 17, 2010, the Georgia PSC voted to reaffirm its order. The matter is no longer subject to judicial review and is now concluded. On December 2, 2010, Westinghouse submitted an AP1000 Design Certification Amendment (DCA) to the NRC. On February 10, 2011, the NRC announced that it was seeking public comment on a proposed rule to approve the DCA and amend the certified AP1000 reactor design for use in the U.S. The Advisory Committee on Reactor Safeguards also issued a letter on January 24, 2011 endorsing the issuance of the COL for Plant Vogtle Units 3 and 4. The Company currently expects to receive the COL for Plant Vogtle Units 3 and 4 from the NRC in late 2011 based on the NRC's February 16, 2011 release of its COL schedule framework. There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds. The ultimate outcome of these matters cannot be determined at this time. Other Construction On May 6, 2010, the Georgia PSC approved the Company’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. As a result, the units are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. To date, the Georgia PSC has approved the Company’s quarterly construction monitoring reports including actual project expenditures incurred through June 30, 2010. The Company will continue to file quarterly construction monitoring reports throughout the construction period. 4. JOINT OWNERSHIP AGREEMENTS The Company and Alabama Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Alabama Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, debt service, and return on investment, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two years’ notice. The Company accounts for SEGCO using the equity method. The Company’s share of expenses included in purchased power from affiliates in the statements of income is as follows: 2010 2009 2008 (in millions) Energy Capacity Total $ 53 47 $ 100 $ 44 43 $ 87 $ 86 41 $ 127 The Company owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with OPC, MEAG Power, Dalton, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company and Florida Power Corporation (Progress Energy Florida) jointly own a combustion turbine unit (Intercession City) operated by Progress Energy Florida. II-241 SoCo FOIA Response 002598 NOTES (continued) Georgia Power Company 2010 Annual Report At December 31, 2010, the Company’s percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation with the above entities were as follows: Facility (Type) Company Ownership Investment Accumulated Depreciation (in millions) Plant Vogtle (nuclear) Units 1 and 2 Plant Hatch (nuclear) Plant Wansley (coal) Plant Scherer (coal) Units 1 and 2 Unit 3 Rocky Mountain (pumped storage) Intercession City (combustion-turbine) 45.7% 50.1 53.5 8.4 75.0 25.4 33.3 $ 3,292 962 700 $ 1,935 534 208 148 857 175 12 74 362 109 3 At December 31, 2010, the portion of total construction work in progress related to Plants Wansley, Scherer, and Vogtle Units 3 and 4 was $11 million, $110 million, and $1.3 billion, respectively. Construction at Plants Wansley and Scherer relates primarily to environmental projects. See Note 3 under “Construction – Nuclear” for information on Plant Vogtle Units 3 and 4. The Company’s proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing. 5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2010 2009 2008 (in millions) Federal – Current Deferred State – Current Deferred Total $ 147 312 459 $ 211 175 386 $ 284 155 439 (36) 30 (6) $ 453 7 17 24 $ 410 33 16 49 $ 488 II-242 SoCo FOIA Response 002599 NOTES (continued) Georgia Power Company 2010 Annual Report The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2009 2010 (in millions) Deferred tax liabilities – Accelerated depreciation Property basis differences Employee benefit obligations Fuel clause under recovery Premium on reacquired debt Emissions allowances Regulatory assets associated with employee benefit obligations Asset retirement obligations Other Total Deferred tax assets – Federal effect of state deferred taxes Employee benefit obligations Other property basis differences Other deferred costs Cost of removal obligations State tax credit carry forward Other comprehensive income Unbilled fuel revenue Asset retirement obligations Environmental capital cost recovery Other Total Total deferred tax liabilities, net Portion included in current assets/(liabilities), net Accumulated deferred income taxes $ 3,184 746 251 162 71 18 336 275 52 5,095 $ 2,923 585 184 270 64 22 362 263 70 4,743 159 433 111 72 52 192 6 57 275 1 37 1,395 3,700 18 $ 3,718 177 482 117 65 109 99 12 42 263 37 38 1,441 3,302 88 $ 3,390 At December 31, 2010, tax-related regulatory assets were $727 million and tax-related regulatory liabilities were $129 million. These assets are attributable to tax benefits flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest. In 2010, the Company deferred $51 million as a regulatory asset related to the impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (together, the Acts). The Acts eliminated the deductibility of health care costs that are covered by federal Medicare subsidy payments. Beginning in 2011, the Company is amortizing the regulatory asset to income tax expense over 12 years, under the 2010 ARP. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $13 million in 2010, $14 million in 2009, and $13 million in 2008. At December 31, 2010, all investment tax credits available to reduce federal income taxes payable had been utilized. On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance II-243 SoCo FOIA Response 002600 NOTES (continued) Georgia Power Company 2010 Annual Report Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013). The application of the bonus depreciation provisions in these acts in 2010 significantly increased deferred tax liabilities related to accelerated depreciation. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Federal statutory rate State income tax, net of federal deduction Non-deductible book depreciation AFUDC equity Donations Other Effective income tax rate 2009 35.0% 1.2 1.1 (2.7) (0.8) (0.8) 33.0% 2010 35.0% (0.3) 1.0 (3.6) (0.2) 31.9% 2008 35.0% 2.2 0.9 (2.4) (1.1) 34.6% The decreases in the Company’s 2010 and 2009 effective tax rates are primarily the result of increases in non-taxable AFUDC equity and state tax credits. See “Unrecognized Tax Benefits” herein and Note 3 under “Income Tax Matters” for additional information on unrecognized tax benefits and related litigation related to state tax credits. The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code. The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 2010. Unrecognized Tax Benefits For 2010, the total amount of unrecognized tax benefits increased by $56 million, resulting in a balance of $237 million as of December 31, 2010. Changes during the year in unrecognized tax benefits were as follows: 2009 2010 2008 (in millions) Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions increase from prior periods Tax positions decrease from prior periods Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year $ $ 181 52 27 (23) 237 $ $ 137 44 6 (5) (1) 181 $ 89 47 5 (4) $ 137 The tax positions from current periods relates primarily to the Georgia state tax credits litigation, tax accounting method change for repairs and other miscellaneous uncertain tax positions. The tax positions increase from prior periods relates primarily to the tax accounting method change for repairs and other miscellaneous positions. The tax positions decrease from prior periods relates primarily to the Georgia state tax credit litigation and miscellaneous tax positions. See Note 3 under “Income Tax Matters” for additional information. II-244 SoCo FOIA Response 002601 NOTES (continued) Georgia Power Company 2010 Annual Report The impact on the Company’s effective tax rate, if recognized, is as follows: 2009 2010 2008 (in millions) Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits $ 181 $ 181 $ 202 35 $ 237 $ 134 3 $ 137 The tax positions impacting the effective tax rate primarily relate to the state tax credit litigation, however, as discussed in Note 3 under “Income Tax Matters,” if the Company is successful in its claim against the DOR, a significant portion of the tax benefit is expected to be deferred and returned to retail customers and therefore no material impact to net income is expected. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note 3 under “Income Tax Matters” for additional information. Accrued interest for unrecognized tax benefits was as follows: 2009 2010 2008 (in millions) Interest accrued at beginning of year Interest accrued during the year Balance at end of year $ 14 6 $ 20 $ 20 7 $ 27 $ 7 7 $ 14 The Company classifies interest on tax uncertainties as interest expense. The net amount of interest accrued for all years presented was primarily associated with the state tax credit litigation. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the state tax credit litigation would substantially reduce the balances. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has audited and closed all tax returns prior to 2007. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006. 6. FINANCING Long-Term Debt Payable to Affiliated Trusts The Company has formed certain wholly-owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as long-term debt. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2010, preferred securities of $200 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities. Securities Due Within One Year A summary of the scheduled maturities and redemptions of securities due within one year at December 31 was as follows: 2009 2010 (in millions) Capital lease Bank term loan Pollution control revenue bonds Senior notes Other long-term debt Total $ 4 300 8 100 3 $ 415 $ 4 250 $ 254 II-245 SoCo FOIA Response 002602 NOTES (continued) Georgia Power Company 2010 Annual Report Maturities through 2015 applicable to total long-term debt are as follows: $415 million in 2011; $205 million in 2012; $1.4 billion in 2013; $5 million in 2014; and $256 million in 2015. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company has incurred obligations in connection with the sale by public authorities of tax-exempt pollution control revenue bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2010 and 2009 was $1.5 billion and $2.0 billion, respectively. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. Senior Notes The Company issued $2.0 billion aggregate principal amount of unsecured senior notes in 2010. The proceeds of the issuance were used to repay a portion of the Company’s short-term indebtedness, fund note redemptions totaling $1.1 billion, redeem pollution control revenue bonds totaling $516 million, and fund the Company’s continuous construction program. At December 31, 2010 and 2009, the Company had $6.3 billion and $5.4 billion of senior notes outstanding, respectively. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $59 million and $63 million at December 31, 2010 and 2009, respectively. Subsequent to December 31, 2010, the Company issued $300 million of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds from the sale of the Series 2011A Senior Notes were used by the Company to repay a portion of its outstanding short-term indebtedness and for general corporate purposes, including the Company’s continuous construction program. Bank Term Loans At December 31, 2010 and 2009, the Company had a $300 million bank loan outstanding, which matures in March 2011. Capital Leases Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2010 and 2009, the Company had a capitalized lease obligation for its corporate headquarters building of $58 million and $62 million, respectively, with an interest rate of 8.0%. For ratemaking purposes, the Georgia PSC has treated the lease as an operating lease and has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expense as ordered by the Georgia PSC. See Note 1 under “Regulatory Assets and Liabilities.” The annual expense incurred for all capital leases in 2010, 2009, and 2008 was $6 million, $9 million, and $10 million, respectively. Outstanding Classes of Capital Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company has shares of its Class A preferred stock, preference stock, and common stock outstanding. The Company’s Class A preferred stock ranks senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the Class A preferred stock and preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the stock. In addition, the Company may redeem the outstanding series of the preference stock at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends through the first par redemption date. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. II-246 SoCo FOIA Response 002603 NOTES (continued) Georgia Power Company 2010 Annual Report Bank Credit Arrangements At December 31, 2010, the Company had credit arrangements with banks totaling $1.7 billion, of which $12 million was used to support outstanding letters of credit. Of these facilities, $595 million expire during 2011, with the remaining $1.1 billion expiring in 2012. Of the facilities that expire in 2011, $40 million provides the option of converting borrowings into a two-year term loan and $220 million provides the option of converting borrowings into a one-year term loan. The Company expects to renew its facilities, as needed, prior to expiration. The agreements contain stated borrowing rates. All the agreements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. The credit arrangements contain covenants that limit the ratio of indebtedness to capitalization (each as defined in the arrangements) to 65%. For purposes of these definitions, indebtedness excludes the long-term debt payable to affiliated trusts and, in certain cases, other hybrid securities. In addition, the credit arrangements contain cross default provisions that would trigger an event of default if the Company defaulted on other indebtedness above a specified threshold. At December 31, 2010, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowings. The $1.7 billion of unused credit arrangements provides liquidity support to the Company’s variable rate pollution control revenue bonds and its commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2010 was $385 million. Subsequent to December 31, 2010, the Company’s remarketing of $137 million of variable rate pollution control revenue bonds increased the total requiring liquidity support to $522 million. In addition, the Company borrows under a commercial paper program. The amount of commercial paper outstanding at December 31, 2010 and 2009 was $575 million and $324 million, respectively. Commercial paper and short-term bank loans are included in notes payable on the balance sheets. During 2010, the maximum amount of commercial paper outstanding was $575 million and the average amount outstanding was $167 million. During 2009, the maximum amount of commercial paper outstanding was $757 million and the average amount outstanding was $348 million. The weighted average annual interest rate on commercial paper in 2010 and 2009 was 0.3% and 0.4%, respectively. 7. COMMITMENTS Construction Program The construction program of the Company is currently estimated to include a base level investment of $2.1 billion, $2.2 billion, and $2.0 billion for 2011, 2012, and 2013, respectively. These amounts include $252 million, $148 million, and $185 million in 2011, 2012, and 2013, respectively, for construction expenditures related to contractual purchase commitments for nuclear fuel included herein under “Fuel Commitments.” Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $73 million, $79 million, and $58 million for 2011, 2012, and 2013, respectively. The capital budget amounts for 2011-2013 include amounts for the construction of Plant Vogtle Units 3 and 4 as discussed in Note 3 under “Construction – Nuclear.” Of the estimated total $4.4 billion in capital costs, approximately $943 million is expected to be incurred from 2014 through 2017. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2010, significant purchase commitments were outstanding in connection with the ongoing construction program. See Note 3 under “Construction” for additional information. Long-Term Service Agreements The Company has a long-term service agreement (LTSA) with General Electric (GE) for maintenance support for the combustion turbines at the Plant McIntosh combined cycle facility. In summary, the LTSA stipulates that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the contract. In general, this LTSA is in effect through two major inspection cycles per unit. Scheduled payments to GE, which are subject to price escalation, are made quarterly based on actual operating hours of the respective units. Total payments to GE are currently estimated at $155 million over the remaining term of the II-247 SoCo FOIA Response 002604 NOTES (continued) Georgia Power Company 2010 Annual Report agreement, which is currently projected to be approximately eight years. However, the LTSA contains various cancellation provisions at the option of the Company. The Company also has a LTSA with GE through 2014 for neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently estimated at $6 million. The contract contains cancellation provisions at the option of the Company. Payments made to GE prior to the performance of any work are recorded as a prepayment in the balance sheets. Work performed by GE is capitalized or charged to expense, as appropriate, net of any joint owner billings, based on the nature of the work. The Company has entered into a LTSA with Mitsubishi Power Systems Americas, Inc. (MPS) for the purpose of providing certain parts and maintenance services for the three combined cycle units under construction at Plant McDonough, which are scheduled to go into service in January 2012, May 2012, and January 2013, respectively. The LTSA stipulates that MPS will perform all planned maintenance on each covered unit which includes the cost of all materials and services. MPS is also obligated to cover costs of unplanned maintenance on the gas turbines subject to limits specified in the LTSA. This LTSA will begin in 2012 and is in effect through two major inspection cycles per covered unit. Periodic payments to MPS are to be made quarterly and will also be made based on the scheduled inspections for the respective covered units. Payments to MPS, which are subject to price escalation, are currently estimated to be $537 million for the term of this agreement which is expected to be between 12 and 13 years. However, the LTSA contains various termination provisions at the option of the Company. Limestone Commitments As part of the Company’s program to reduce sulfur dioxide emissions from its coal plants, the Company has entered into various longterm commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. The Company has a minimum contractual obligation of 3.5 million tons, equating to approximately $93 million through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $17 million in 2011, $18 million in 2012, $18 million in 2013, $19 million in 2014, and $11 million in 2015. Fuel Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emissions allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2010. Total estimated minimum long-term commitments at December 31, 2010 were as follows: Natural Gas Commitments Coal Nuclear Fuel (in millions) 2011 2012 2013 2014 2015 2016 and thereafter Total $ 445 490 494 429 340 2,665 $4,863 $ 1,869 808 730 441 345 1,182 $ 5,375 $ 252 148 185 165 98 585 $ 1,433 Additional commitments for fuel will be required to supply the Company’s future needs. Total charges for nuclear fuel included in fuel expense amounted to $106 million, $82 million, and $77 million for the years 2010, 2009, and 2008, respectively. SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well II-248 SoCo FOIA Response 002605 NOTES (continued) Georgia Power Company 2010 Annual Report agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Purchased Power Commitments The Company has commitments regarding a portion of a 5% interest in Plant Vogtle owned by MEAG Power that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG Power’s bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit’s variable operating costs. Portions of the capacity payments relate to costs in excess of Plant Vogtle’s allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity and energy is included in purchased power, non-affiliates in the statements of income. Capacity payments totaled $55 million, $54 million, and $48 million in 2010, 2009, and 2008, respectively. The Company also has entered into other various longterm PPAs. Estimated total long-term obligations under these commitments at December 31, 2010 were as follows: Vogtle Capacity Payments Affiliated PPAs Non-Affiliated PPAs (in millions) 2011 2012 2013 2014 2015 2016 and thereafter Total $ 55 49 23 18 11 87 $ 243 $ 119 107 107 108 108 380 929 $ $ 142 115 108 109 110 1,259 $ 1,843 Certain PPAs reflected in the table are accounted for as operating leases. Operating Leases The Company has entered into various operating leases with various terms and expiration dates. Rental expenses related to these operating leases totaled $35 million for 2010, $43 million for 2009, and $52 million for 2008. At December 31, 2010, estimated minimum lease payments for noncancelable operating leases were as follows: Minimum Lease Payments Rail Cars Other Total (in millions) 2011 2012 2013 2014 2015 2016 and thereafter Total $ 30 17 12 10 8 7 $ 84 $ 6 4 4 3 1 1 $ 19 $ 36 21 16 13 9 8 $ 103 In addition to the above rental commitments, the Company has obligations upon expiration of certain rail car leases with respect to the residual value of the leased property. These leases expire in 2011 and the Company’s maximum obligation is $40 million. At the termination of the leases, at the Company’s option, the Company may either exercise its purchase option or the property can be sold to a third party. A portion of the rail car lease obligations is shared with the joint owners of Plants Scherer and Wansley. A majority of the rental expenses related to the rail car leases are fully recoverable through the fuel cost recovery clause as ordered by the Georgia PSC and the remaining portion is recovered through base rates. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company’s payments under the residual value obligations. II-249 SoCo FOIA Response 002606 NOTES (continued) Georgia Power Company 2010 Annual Report Guarantees Alabama Power has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO’s generating units, pursuant to which $25 million principal amount of pollution control revenue bonds are outstanding. Alabama Power has also guaranteed $50 million in senior notes issued by SEGCO. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company’s then proportionate ownership of stock of SEGCO if Alabama Power is called upon to make such payment under its guaranty. As discussed earlier in this Note under “Operating Leases,” the Company has entered into certain residual value guarantees related to rail car leases. 8. STOCK COMPENSATION Stock Option Plan Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2010, there were 1,837 current and former employees of the Company participating in the stock option plan, and there were 10 million shares of Southern Company common stock remaining available for awards under this plan and the Performance Share Plan discussed below. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting. The estimated fair values of stock options granted in 2010, 2009, and 2008 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Dividend yield Weighted average grant-date fair value 2010 17.4% 5.0 2.4% 5.6% $2.23 2009 15.6% 5.0 1.9% 5.4% $1.80 2008 13.1% 5.0 2.8% 4.5% $2.37 The Company’s activity in the stock option plan for 2010 is summarized below: Shares Subject to Option Weighted Average Exercise Price Outstanding at December 31, 2009 Granted Exercised Cancelled Outstanding at December 31, 2010 10,322,924 1,715,600 (1,656,754) 163 10,381,933 $31.90 31.19 27.80 30.34 $32.44 Exercisable at December 31, 2010 6,848,412 $32.77 II-250 SoCo FOIA Response 002607 NOTES (continued) Georgia Power Company 2010 Annual Report The number of stock options vested, and expected to vest in the future, as of December 31, 2010 was not significantly different from the number of stock options outstanding at December 31, 2010 as stated above. At December 31, 2010, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $60 million and $37 million, respectively. As of December 31, 2010, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial. The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. The amounts were not material for any year presented. The total intrinsic value of options exercised during the years ended December 31, 2010, 2009, and 2008 was $12 million, $2 million, and $11 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises was not material for any year presented. Performance Share Plan In 2010, Southern Company implemented the performance share program under its omnibus incentive compensation plan, which provides performance share award units to a large segment of the Company’s employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company’s total shareholder return (TSR) over the three-year performance period which measures Southern Company’s relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company’s actual TSR and may range from 0% to 200% of the original target performance share amount. The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company’s stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. Expected volatility used in the model of 20.7% was based on historical volatility of Southern Company’s stock over a period equal to the performance period. The risk-free rate of 1.4% was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units. The annualized dividend rate at the time of the grant was $1.75. During 2010, 189,361 performance share units were granted to the Company’s employees with a weighted-average grant date fair value of $30.13. During 2010, 3,849 performance share units were forfeited by the Company’s employees resulting in 185,512 unvested units outstanding at December 31, 2010. For the year ended December 31, 2010, the Company’s total compensation cost for performance share units and the related tax benefit recognized in income were not material. As of December 31, 2010, the amount of total unrecognized compensation cost related to performance share award units that will be recognized over the next two years was not material. 9. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company’s Plants Hatch and Vogtle. The Act provides funds up to $12.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of $17.5 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company, based on its ownership and buyback interests, is $237 million, per incident, but not more than an aggregate of $35 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013. II-251 SoCo FOIA Response 002608 NOTES (continued) Georgia Power Company 2010 Annual Report The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ operating nuclear generating facilities. Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period. A builders’ risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $70 million. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. 10. FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.    Level 1 consists of observable market data in an active market for identical assets or liabilities. Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. II-252 SoCo FOIA Response 002609 NOTES (continued) Georgia Power Company 2010 Annual Report As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) As of December 31, 2010: Total (in millions) Assets: Energy-related derivatives Nuclear decommissioning trusts:(a) Domestic equity U.S. Treasury and government agency securities Municipal bonds Corporate bonds Mortgage and asset backed securities Other Total 257 $ 257 Liabilities: Energy-related derivatives $ $ - - $ 1 $ - $ 1 1 213 53 138 89 67 $ 562 $ - $ 258 213 53 138 89 67 819 $ 101 $ - $ 101 (a) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under “Nuclear Decommissioning” for additional information. Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, implied volatility, and London Interbank Offered Rate (LIBOR) interest rates. See Note 11 for additional information on how these derivatives are used. For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics. A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts’ judgment are also obtained when available. As of December 31, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: As of December 31, 2010: Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period None None Daily Daily 1 to 3 days Not applicable (in millions) Nuclear decommissioning trusts: Corporate bonds – commingled funds Other – commingled funds $ $ 65 67 II-253 SoCo FOIA Response 002610 NOTES (continued) Georgia Power Company 2010 Annual Report The commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The corporate bonds – commingled funds represent the investment of cash collateral received under the Funds’ managers’ securities lending program that can only be sold upon the return of the loaned securities. See Note 1 under “Nuclear Decommissioning” for additional information. As of December 31, 2010 and 2009, other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt: 2010 2009 $ 8,285 $ 7,973 $ 8,548 $ 8,059 The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). 11. DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Georgia PSC, through the use of financial derivative contracts, and recently has started using significantly more financial options within the guidelines of the Georgia PSC which is expected to continue to mitigate price volatility. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. Energy-related derivative contracts are accounted for in one of two methods:   Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clauses. Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. II-254 SoCo FOIA Response 002611 NOTES (continued) Georgia Power Company 2010 Annual Report At December 31, 2010, the net volume of energy-related derivative contracts for natural gas positions totaled 59 million mmBtu (million British thermal units), all of which expire by 2015, which is the longest hedge date. In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 4 million mmBtu for the Company. Interest Rate Derivatives The Company also enters into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to income. At December 31, 2010, there were no interest rate derivatives outstanding. The estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2011 are $4 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2037. Derivative Financial Statement Presentation and Amounts At December 31, 2010 and 2009, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Derivative Category Asset Derivatives Balance Sheet Location 2010 Liability Derivatives Balance Sheet Location 2010 2009 (in millions) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Total derivatives designated as hedging instruments for regulatory purposes Derivatives designated as hedging instruments in cash flow hedges Interest rate derivatives: Other current assets Other deferred charges and assets Other current assets Total 2009 (in millions) $1 $- - - $1 $- $$1 $$- Liabilities from risk management activities Other deferred credits and liabilities Liabilities from risk management activities $77 $47 24 28 $101 $75 $$101 $2 $77 All derivative instruments are measured at fair value. See Note 10 for additional information. II-255 SoCo FOIA Response 002612 NOTES (continued) Georgia Power Company 2010 Annual Report At December 31, 2010 and 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: Unrealized Losses Balance Sheet Location 2010 Derivative Category 2009 Unrealized Gains Balance Sheet Location 2010 (in millions) Energy-related derivatives: Other regulatory assets, current Other regulatory assets, deferred Total energy-related derivative gains (losses) $(77) $(47) (24) (28) $(101) $(75) 2009 (in millions) Other regulatory liabilities, current Other deferred credits and liabilities $1 $- - - $1 $- For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Hedging Relationships Derivative Category Gain (Loss) Recognized in OCI on Derivative (Effective Portion) 2009 2008 2010 Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount 2009 2008 Statements of Income Location 2010 (in millions) Interest rate derivatives $- $(3) (in millions) $(34) Interest expense, net of amounts capitalized $(16) $(22) $(3) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. The Company has certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2010, the fair value of derivative liabilities with contingent features was $26 million. At December 31, 2010, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-riskrelated contingent features, at a rating below BBB- and/or Baa3, is $40 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. II-256 SoCo FOIA Response 002613 NOTES (continued) Georgia Power Company 2010 Annual Report 12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2010 and 2009 is as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock March 2010 June 2010 September 2010 December 2010 $ 1,984 2,000 2,628 1,737 $ 399 411 714 141 $ 238 238 420 54 March 2009 June 2009 September 2009 December 2009 $ 1,766 1,874 2,327 1,725 $ 272 369 683 206 $ 122 190 388 114 (in millions) The Company’s business is influenced by seasonal weather conditions. II-257 SoCo FOIA Response 002614 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 Georgia Power Company 2010 Annual Report Operating Revenues (in millions) Net Income after Dividends on Preferred and Preference Stock (in millions) Cash Dividends on Common Stock (in millions) Return on Average Common Equity (percent) Total Assets (in millions) Gross Property Additions (in millions) Capitalization (in millions) : Common stock equity Preferred and preference stock Long-term debt Total (excluding amounts due within one year) Capitalization Ratios (percent): Common stock equity Preferred and preference stock Long-term debt Total (excluding amounts due within one year) Customers (year-end): Residential Commercial Industrial Other Total Employees (year-end) 2010 $8,349 2009 $7,692 2008 $8,412 2007 $7,572 2006 $7,246 $950 $814 $903 $836 $787 $820 11.42 $25,914 $2,401 $739 11.01 $24,295 $2,646 $721 13.56 $22,316 $1,953 $690 13.50 $20,823 $1,862 $630 13.80 $19,309 $1,277 $8,741 266 7,931 $16,938 $7,903 266 7,782 $15,951 $6,879 266 7,006 $14,151 $6,435 266 5,938 $12,639 $5,956 45 5,212 $11,213 51.6 1.6 46.8 100.0 49.5 1.7 48.8 100.0 48.6 1.9 49.5 100.0 50.9 2.1 47.0 100.0 53.1 0.4 46.5 100.0 2,049,770 296,140 8,136 7,309 2,361,355 8,330 2,043,661 295,375 8,202 6,580 2,353,818 8,599 2,039,503 295,925 8,248 5,566 2,349,242 9,337 2,024,520 295,478 8,240 4,807 2,333,045 9,270 1,998,643 294,654 8,008 4,371 2,305,676 9,278 N/A = Not Applicable. II-258 SoCo FOIA Response 002615 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 (continued) Georgia Power Company 2010 Annual Report Operating Revenues (in millions) : Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total revenues from sales of electricity Other revenues Total Kilowatt-Hour Sales (in millions) : Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total Average Revenue Per Kilowatt-Hour (cents): Residential Commercial Industrial Total retail Wholesale Total sales Residential Average Annual Kilowatt-Hour Use Per Customer Residential Average Annual Revenue Per Customer Plant Nameplate Capacity Ratings (year-end) (megawatts) Maximum Peak-Hour Demand (megawatts) : Winter Summer Annual Load Factor (percent) Plant Availability (percent): Fossil-steam Nuclear Source of Energy Supply (percent): Coal Nuclear Hydro Oil and gas Purchased power From non-affiliates From affiliates Total 2010 2009 2008 2007 2006 $ 3,072 3,011 1,441 84 7,608 380 53 8,041 308 $8,349 $2,686 2,826 1,318 82 6,912 395 112 7,419 273 $7,692 $2,648 2,917 1,640 81 7,286 569 286 8,141 271 $8,412 $2,443 2,576 1,404 75 6,498 538 278 7,314 258 $7,572 $2,326 2,424 1,382 74 6,206 552 253 7,011 235 $7,246 29,433 33,855 23,209 663 87,160 4,662 1,000 92,822 26,272 32,593 21,810 671 81,346 5,208 2,504 89,058 26,412 33,058 24,164 671 84,305 9,755 3,695 97,755 26,840 33,057 25,490 697 86,084 10,578 5,192 101,854 26,206 32,112 25,577 660 84,555 10,687 5,463 100,705 10.44 8.89 6.21 8.73 7.65 8.66 10.22 8.67 6.04 8.50 6.57 8.33 10.03 8.82 6.79 8.64 6.36 8.33 9.10 7.79 5.51 7.55 5.17 7.18 8.88 7.55 5.40 7.34 4.98 6.96 14,367 12,848 12,969 13,315 13,216 $1,499 $1,314 $1,300 $1,212 $1,173 15,992 15,995 15,995 15,995 15,995 15,614 17,152 60.9 15,173 16,080 60.7 14,221 17,270 58.4 13,817 17,974 57.5 13,528 17,159 61.8 88.6 94.0 92.5 88.4 91.0 89.8 90.8 92.4 91.4 90.7 51.8 16.4 1.4 8.0 52.3 16.2 1.8 7.7 58.7 14.8 0.6 5.1 61.5 14.6 0.5 5.5 59.0 14.4 0.9 5.0 5.2 17.2 100.0 4.4 17.6 100.0 5.1 15.7 100.0 3.8 14.1 100.0 3.8 16.9 100.0 II-259 SoCo FOIA Response 002616 GULF POWER COMPANY FINANCIAL SECTION SoCo FOIA Response 002617 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Gulf Power Company 2010 Annual Report The management of Gulf Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010. Mark A. Crosswhite President and Chief Executive Officer Richard S. Teel Vice President and Chief Financial Officer February 25, 2011 II-261 SoCo FOIA Response 002618 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Gulf Power Company We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2010 and 2009, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed of the Company in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements (pages II-287 to II-327) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. Atlanta, Georgia February 25, 2011 II-262 SoCo FOIA Response 002619 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Gulf Power Company 2010 Annual Report OVERVIEW Business Activities Gulf Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. Key Performance Indicators In striving to maximize shareholder value while providing cost-effective energy to over 430,000 customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The 2010 Peak Season EFOR of 3.86% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The performance for 2010 was better than the target for these reliability measures. Net income after dividends on preference stock is the primary measure of the Company’s financial performance. The performance for net income after dividends on preference stock in 2010 was above target. The Company’s 2010 results compared with its targets for some of these key indicators are reflected in the following chart: Key Performance Indicator Customer Satisfaction Peak Season EFOR Net income after dividends on preference stock 2010 Target Performance 2010 Actual Performance Top quartile in customer surveys 5.06% or less Top quartile 3.86% $116.8 million $121.5 million See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2010 reflects the continued emphasis the Company places on these indicators as well as the commitment of employees to meet and exceed targets. Earnings The Company’s 2010 net income after dividends on preference stock was $121.5 million, an increase of $10.3 million from the previous year. In 2009, net income after dividends on preference stock was $111.2 million, an increase of $12.9 million from the previous year. In 2008, net income after dividends on preference stock was $98.3 million, an increase of $14.2 million from the previous year. The increase in net income after dividends on preference stock in 2010 was primarily due to increased retail revenues due to significantly colder weather in the first quarter 2010 and warmer weather in the third quarter 2010. The increases in revenues were partially offset by an increase in operations and maintenance expenses. The increase in net income after dividends on preference stock in 2009 was due primarily to increased allowance for funds used during construction (AFUDC) equity, which is non-taxable, and decreased interest expense, net of amounts capitalized, partially offset by unfavorable weather and a decline in sales. The increase II-263 SoCo FOIA Response 002620 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report in net income after dividends on preference stock in 2008 was due primarily to higher wholesale revenues from non-affiliates, increased AFUDC equity, and a gain on the sale of assets. RESULTS OF OPERATIONS A condensed statement of income follows: Amount 2010 Increase (Decrease) from Prior Year 2009 2008 2010 (in millions) Operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Total other income and (expense) Income taxes Net income Dividends on preference stock Net income after dividends on preference stock $ 1,590.2 742.3 97.2 280.6 121.5 101.8 1,343.4 246.8 (47.6) 71.5 127.7 6.2 $ 288.0 168.9 5.2 20.3 28.1 7.3 229.8 58.2 (29.4) 18.5 10.3 - $ (84.9) (62.2) (17.4) (17.2) 8.6 7.3 (80.9) (4.0) 15.8 (1.1) 12.9 - $ 127.4 62.2 37.9 7.1 (0.8) 4.2 110.6 16.8 6.7 7.0 16.5 2.3 $ 121.5 $ 10.3 $ 12.9 $ 14.2 Operating Revenues Operating revenues for 2010 were $1,590.2 million, reflecting an increase of $288.0 million from 2009. The following table summarizes the significant changes in operating revenues for the past three years: 2010 Amount 2009 2008 (in millions) Retail – prior year Estimated change in – Rates and pricing Sales growth (decline) Weather Fuel and other cost recovery Retail – current year Wholesale revenues – Non-affiliates Affiliates Total wholesale revenues Other operating revenues Total operating revenues Percent change $ 1,106.6 72.7 (2.3) 18.7 113.0 1,308.7 $ 1,120.8 33.0 (5.7) (4.5) (37.0) 1,106.6 94.1 109.2 32.1 110.0 126.2 219.2 69.4 62.3 $ 1,302.2 $ 1,590.2 (6.1)% 22.1% $ 1,006.3 6.3 (4.6) 3.9 108.9 1,120.8 97.1 107.0 204.1 62.3 $ 1,387.2 10.1% Retail revenues increased $202.1 million, or 18.3%, in 2010, decreased $14.2 million, or 1.3%, in 2009, and increased $114.4 million, or 11.4%, in 2008. II-264 SoCo FOIA Response 002621 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Revenues associated with changes in rates and pricing include cost recovery provisions for energy conservation costs and environmental compliance costs. Annually, the Company petitions the Florida Public Service Commission (PSC) for recovery of projected costs, including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions include related expenses and a return on average net investment. See Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Cost Recovery” for additional information. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes relating to sales growth (or decline) and weather. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, and purchased power capacity costs. Annually, the Company petitions the Florida PSC for recovery of projected fuel and purchased power costs, including any true-up amount from prior periods, and approved rates are implemented each January. Cost recovery provisions also include revenues related to the recovery of storm damage restoration costs. The recovery provisions generally equal the related expenses and have no material effect on net income. See Note 1 to the financial statements under “Revenues” and “Property Damage Reserve” and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information. Total wholesale revenues were $219.2 million in 2010, an increase of $93.0 million, or 73.7%, compared to 2009 primarily to serve weather-related increases in affiliate demand as a result of colder weather in the first and fourth quarters 2010 and warmer weather in the second and third quarters 2010. Total wholesale revenues were $126.2 million in 2009, a decrease of $77.8 million, or 38.2%, compared to 2008 primarily due to decreased energy sales to affiliates at a lower cost per kilowatt-hour (KWH). Total wholesale revenues were $204.1 million in 2008, an increase of $7.4 million, or 3.7%, compared to 2007 primarily due to higher capacity revenues associated with new and existing territorial wholesale contracts with non-affiliated companies. Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Revenues from unit power sales increased $7.3 million, or 12.6% in 2010 primarily due to increased capacity revenues as a result of new contracts. Revenues from other power sales increased $7.8 million, or 21.3% in 2010 primarily due to increased KWH sales to serve weather-related increases in non-territorial demand. Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to other utilities in Florida and Georgia. Wholesale revenues from contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy is generally sold at variable cost. The capacity and energy components under these unit power sales contracts were as follows: 2010 2009 2008 (in thousands) Unit power sales – Capacity Energy Total Other power sales – Capacity and other Energy Total Total non-affiliated $ 33,482 31,379 64,861 $ 24,466 33,122 57,588 $ 22,028 33,767 55,795 11,158 33,153 44,311 $ 109,172 11,060 25,457 36,517 $ 94,105 10,890 30,380 41,270 $ 97,065 Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). These transactions do not have a significant impact on earnings since the fuel revenue related to energy sales and the cost of energy purchases are both included in the determination of recoverable fuel costs and are generally offset by revenues collected in the Company’s fuel cost recovery clause. Other operating revenues decreased $7.2 million, or 10.4%, in 2010 primarily due a $10.3 million decrease in revenues from other energy services, partially offset by higher franchise fees of $3.1 million. Other operating revenues increased $7.1 million, or 11.3%, in 2009 primarily due to other energy services and franchise fees, offset by transmission and distribution network services and timber II-265 SoCo FOIA Response 002622 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report sales. Other operating revenues increased $5.6 million, or 9.9%, in 2008 primarily due to transmission and distribution network services and other energy services. Revenues from other energy services did not have a material effect on net income since they were generally offset by associated expenses. Franchise fees have no impact on net income. Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2010 and the percent change by year were as follows: Total KWHs 2010 Total KWH Percent Change 2009 2008 2010 Weather-Adjusted Percent Change 2009 2008 2010 (in millions) Residential Commercial Industrial Other Total retail Wholesale Non-affiliates Affiliates Total wholesale Total energy sales 5,651 3,996 1,686 26 11,359 7.6% 2.6 (2.4) 1.9 4.2 (1.8)% (1.6) (21.9) 8.1 (5.5) (2.3)% (0.3) 7.9 (5.1) 0.2 1,675 2,437 4,112 15,471 (7.6) 180.0 53.2 13.9% (0.2) (53.5) (27.2) (10.8)% (18.4) (35.1) (27.8) (8.4)% (0.2)% 0.3 (2.4) 1.9 (0.3)% 0.1% (1.1) (21.9) 8.1 (4.6)% (4.1)% (0.4) 7.9 (5.1) (0.7)% Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Residential KWH sales increased 7.6% in 2010 compared to 2009 primarily due to significantly colder weather in the first quarter 2010 and warmer weather in the third quarter 2010. Weather-adjusted KWH sales to residential customers remained relatively flat as compared to 2009. Residential KWH sales decreased 1.8% in 2009 compared to 2008 primarily due to the recessionary economy. Weather-adjusted KWH sales to residential customers remained relatively flat as compared to 2008. Residential KWH sales decreased 2.3% in 2008 compared to 2007 primarily due to decreased customer usage as a result of a slowing economy, partially offset by more favorable weather. Commercial KWH sales increased 2.6% in 2010 compared to 2009 primarily due to significantly colder weather in the first quarter 2010 and warmer weather in the third quarter 2010. Weather-adjusted KWH sales to commercial customers remained relatively flat as compared to 2009. Commercial KWH sales decreased 1.6% in 2009 compared to 2008 primarily due to the recessionary economy and a decrease in the number of customers. Weather-adjusted KWH sales to commercial customers decreased primarily due to recessionary-driven decreases in per customer usage and in the number of customers as compared to 2008. The change in commercial KWH sales in 2008 compared to 2007 was immaterial. Industrial KWH sales decreased 2.4% in 2010 compared to 2009 primarily resulting from increased customer co-generation due to the lower cost of natural gas in 2010. Industrial KWH sales decreased 21.9% in 2009 compared to 2008 primarily due to increased customer co-generation due to the lower cost of natural gas in 2009, decreased demand, and a business closure due to the recessionary economy. Industrial KWH sales increased 7.9% in 2008 compared to 2007 primarily due to decreased customer co-generation due to the higher cost of natural gas. Wholesale KWH sales to non-affiliates decreased 7.6% in 2010, decreased 0.2% in 2009, and decreased 18.4% in 2008 each compared to the prior year. The decrease in 2010 was primarily a result of lower KWHs scheduled by unit power customers. The decrease in 2009 was primarily a result of the recessionary economy. The decrease in 2008 was primarily the result of fluctuations in the fuel cost to produce energy sold to non-affiliated utilities under both long-term and short-term contracts. The degree to which prices for oil and natural gas, which are the primary fuel sources for these customers, differ from the Company’s fuel costs will influence these changes in sales. The fluctuations in sales have a minimal effect on earnings since the fuel revenue related to energy sales and the cost of energy purchases are both included in the determination of recoverable fuel costs and are generally offset by revenues collected in the Company’s fuel cost recovery clause. II-266 SoCo FOIA Response 002623 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Wholesale KWH sales to affiliates increased 180% in 2010, decreased 53.5% in 2009, and decreased 35.1% in 2008, compared to prior years. The increase in 2010 was primarily to serve weather-related increases in affiliate demand due to colder weather in the first and fourth quarters 2010 and warmer weather in the second and third quarters 2010. The decrease in 2009 was primarily a result of the recessionary economy. The decrease in 2008 was primarily due to the availability of lower cost generation resources at affiliated companies. Fuel and Purchased Power Expenses Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows: Total generation (millions of KWHs) Total purchased power (millions of KWHs) Sources of generation (percent) – Coal Gas Cost of fuel, generated (cents per net KWH) – Coal Gas Average cost of fuel, generated (cents per net KWH)* Average cost of purchased power (cents per net KWH) 2010 13,440 2,858 78% 22 5.10 4.68 5.01 5.82 2009 12,895 1,481 2008 14,762 1,187 69% 31 4.27 4.66 4.39 6.71 84% 16 3.58 8.02 4.31 9.21 *Fuel includes fuel purchased by the Company for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power. Total fuel and purchased power expenses were $839.5 million in 2010, an increase of $174.1 million, or 26.2%, above the prior year costs. The net increase in fuel and purchased power expenses was primarily due to a $116.3 million increase related to total KWHs generated and purchased and a $57.8 million increase in the cost of energy resulting primarily from an increase in the average cost of coal-fired generation and affiliated company power purchases. Total fuel and purchased power expenses were $665.4 million in 2009, a decrease of $79.6 million, or 10.7%, below the prior year costs. The net decrease in fuel and purchased power expenses was primarily due to a $53.3 million decrease related to total KWHs generated and purchased and a $26.3 million decrease in the cost of energy primarily resulting from a decrease in the average cost of natural gas. Total fuel and purchased power expenses were $745.0 million in 2008, an increase of $100.1 million, or 15.5%, above the prior year costs. The net increase in fuel and purchased power expenses was due to a $130.5 million increase in the average cost of fuel and purchased power as well as a $34.9 million increase related to KWHs purchased, offset by a $65.3 million decrease related to KWHs generated. Fuel expense was $742.3 million in 2010, an increase of $168.9 million, or 29.5%, above the prior year costs. This increase was primarily the result of a 19.4% increase in the average cost of coal and a 4.2% increase in KWHs generated as a result of higher demand. Fuel expense was $573.4 million in 2009, a decrease of $62.2 million, or 9.8%, below the prior year costs. This decrease was primarily the result of a 41.9% decrease in the average cost of natural gas and a 12.6% decrease in KWHs generated as a result of lower demand, partially offset by an increase of 19.3% in the average cost of coal per KWH generated. Fuel expense was $635.6 million in 2008, an increase of $62.2 million, or 10.9%, above the prior year costs. This increase was the result of a 25.3% increase in the average cost of fuel, offset by an 11.4% decrease in KWHs generated. Purchased power expense was $97.2 million in 2010, an increase of $5.2 million, or 5.7%, above the prior year costs. This increase was the result of a 92.9% increase in the volume of KWHs purchased, offset by a 13.3% decrease in the average cost per KWH purchased. Purchased power expense was $92.0 million in 2009, a decrease of $17.4 million, or 15.9%, below the prior year costs. This decrease was primarily the result of a 27.1% decrease in the average cost per KWH purchased, offset by a 24.8% increase in the volume of KWHs purchased. Purchased power expense was $109.4 million in 2008, an increase of $37.9 million, or 53.0%, above the prior year costs. This increase was the result of a 48.8% increase in total KWHs purchased and a 2.8% increase in the average cost per net KWH. II-267 SoCo FOIA Response 002624 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report From an overall global market perspective, coal prices increased substantially in 2010 from the levels experienced in 2009, but remained lower than the unprecedented high levels of 2008. The slowly recovering U.S. economy and global demand from coal importing countries drove the higher prices in 2010, with concerns over regulatory actions, such as permitting issues, and their negative impact on production also contributing upward pressure. Domestic natural gas prices continued to be depressed by robust supplies, including production from shale gas, as well as lower demand. These lower natural gas prices contributed to increased use of natural gas-fueled generating units in 2009 and 2010. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information. Other Operations and Maintenance Expenses In 2010, other operations and maintenance expenses increased $20.3 million, or 7.8%, compared to the prior year primarily due to a $20.2 million increase in scheduled and unscheduled maintenance at generation facilities. In 2009, other operations and maintenance expenses decreased $17.2 million, or 6.2%, compared to the prior year primarily due to a $14.4 million decrease in administrative and general expense, most of which was related to decreased storm recovery costs, and a $6.7 million decrease in power generation, most of which was related to scheduled and unscheduled maintenance and cost containment activities in an effort to offset the effects of the recessionary economy. This decrease was partially offset by a $4.8 million increase in other energy services. In 2008, other operations and maintenance expenses increased $7.1 million, or 2.6%, compared to the prior year primarily due to an $8.2 million increase in scheduled and unscheduled maintenance at generation facilities. Depreciation and Amortization Depreciation and amortization increased $28.1 million, or 30.1%, in 2010 compared to the prior year primarily due to the addition of an environmental control project at Plant Crist being placed into service in December 2009 and other net additions to generation and distribution facilities. Approximately $19.0 million of the increase was related to the environmental control project at Plant Crist and was recovered through the environmental clause; therefore, it had no material impact on net income. Depreciation and amortization increased $8.6 million, or 10.1%, in 2009 compared to the prior year primarily due to additions of environmental control projects at Plant Crist and Plant Scherer and other net additions to generation and distribution facilities. Depreciation and amortization decreased $0.8 million, or 0.9%, in 2008 compared to the prior year primarily as a result of a $3.8 million gain on the sale of a building. The decrease was partially offset by an increase of $3.0 million in depreciation due to net additions to generation and distribution facilities. Taxes Other Than Income Taxes Taxes other than income taxes increased $7.3 million, or 7.7%, in 2010 compared to the prior year primarily due to a $5.5 million increase in gross receipt and franchise fees and a $1.0 million increase in payroll taxes. Taxes other than income taxes increased $7.3 million, or 8.3%, in 2009 compared to the prior year primarily due to a $5.6 million increase in gross receipts and franchise taxes and a $1.6 million increase in property taxes. Taxes other than income taxes increased $4.2 million, or 5.1%, in 2008 compared to the prior year primarily due to a $1.9 million decrease in 2007 related to the resolution of a dispute regarding property taxes in Monroe County, Georgia and a $1.9 million increase in franchise and gross receipt taxes. Gross receipts and franchise taxes have no impact on net income. Allowance for Funds Used During Construction Equity AFUDC equity decreased $16.6 million, or 69.7%, in 2010 compared to the prior year primarily due to an environmental control project at Plant Crist being placed into service in December 2009. AFUDC equity increased $13.8 million, or 138.8%, in 2009 compared to the prior year primarily due to construction of environmental control projects at Plant Crist and Plant Scherer. AFUDC equity increased $7.6 million, or 319.9%, in 2008 compared to the prior year primarily due to construction of environmental control projects at Plant Crist and Plant Scherer. See Note 1 to the financial statements under “Allowance for Funds Used During Construction (AFUDC)” for additional information. II-268 SoCo FOIA Response 002625 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Interest Expense, Net of Amounts Capitalized Interest expense, net of amounts capitalized increased $13.5 million, or 35.3%, in 2010 compared to the prior year as the result of a reduction in capitalized interest for an environmental control project at Plant Crist being placed into service in December 2009. The increased interest was also primarily due to an increase in long-term debt levels resulting from the issuance of additional senior notes in 2010 to fund general corporate purposes, including the Company’s continuous construction program. Interest expense, net of amounts capitalized decreased $4.7 million, or 11.0%, in 2009 compared to the prior year as the result of an increase in capitalization of AFUDC debt related to the construction of environmental control projects at Plant Crist and Plant Scherer. Interest expense, net of amounts capitalized decreased $1.6 million, or 3.5%, in 2008 compared to the prior year as the result of an increase in capitalization of AFUDC debt related to the construction of environmental control projects and the redemption of $41.2 million of long-term debt payable to an affiliated trust in 2007. These decreases were offset by the issuance of a $110 million term loan agreement in 2008. Income Taxes Income taxes increased $18.5 million, or 34.9%, in 2010, compared to the prior year primarily as a result of higher earnings before income taxes and a reduction in the tax benefits associated with a decrease in AFUDC equity, which is non-taxable. Income taxes decreased $1.1 million, or 2.0%, in 2009 compared to the prior year primarily due to the tax benefit associated with an increase in AFUDC equity, which is non-taxable, partially offset by higher earnings before taxes. Income taxes increased $7.0 million, or 14.9%, in 2008, compared to the prior year primarily due to higher earnings before income taxes and a decrease in the federal production activities deduction, partially offset by the tax benefit associated with an increase in AFUDC equity, which is non-taxable. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. Effects of Inflation The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company’s results of operations has not been substantial in recent years. FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Florida PSC under cost-based regulatory principles. Prices for electricity relating to wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about regulatory matters. The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the Company’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company’s service area. Changes in economic conditions impact sales for the Company, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information. II-269 SoCo FOIA Response 002626 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power Company (Alabama Power) and Georgia Power Company (Georgia Power), alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to the Company with respect to the Company’s Plant Crist. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coalfired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. II-270 SoCo FOIA Response 002627 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Statutes and Regulations General The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2010, the Company had invested approximately $1.2 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of $136 million, $343 million, and $296 million for 2010, 2009, and 2008, respectively. The Company expects that capital expenditures to comply with existing statutes and regulations will be $176 million, $228 million, and $214 million for 2011, 2012, and 2013, respectively. These environmental costs that are known and estimable at this time are included under the heading “Capital” in the table under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations of up to $17 million in 2011, up to $56 million in 2012, and up to $107 million in 2013. The Company’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of any new or revised environmental statutes and regulations that are enacted, including the proposed environmental legislation and regulations described below; the cost, availability, and existing inventory of emissions allowances, and the Company’s fuel mix. The Florida Legislature has adopted legislation that allows a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. The legislation is discussed in Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Cost Recovery.” Substantially all of the costs II-271 SoCo FOIA Response 002628 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report for the Clean Air Act and other new environmental legislation discussed below are expected to be recovered through the environmental cost recovery clause. Compliance with any new federal or state legislation or regulations relating to global climate change, air quality, coal combustion byproducts, including coal ash, water quality, or other environmental and health concerns could also significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the Company’s commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2010, the Company had spent approximately $953 million in reducing sulfur dioxide (SO 2 ) and nitrogen oxide (NO x ) emissions and in monitoring emissions pursuant to the Clean Air Act. As a result, emissions control projects have been completed recently or are underway. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements. The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone air quality standard. No area within the Company’s service area is currently designated as nonattainment under the current standard. In March 2008, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the level of the standard. Under the EPA’s current schedule, a final revision to the eight-hour ozone standard is expected in July 2011, with state implementation plans for any resulting nonattainment areas due in mid-2014. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within the Company’s service territory, and could result in additional required reductions in NO x emissions. During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within the State of Georgia, which includes the Company’s co-owned facility. State implementation plans demonstrating attainment with the annual standard for all areas have been submitted to the EPA. The EPA is expected to propose new annual and 24-hour fine particulate matter standards during the summer of 2011. Final revisions to the National Ambient Air Quality Standard for SO 2 , including the establishment of a new one-hour standard, became effective on August 23, 2010. Since the EPA intends to rely on computer modeling for implementation of the SO 2 standard, the identification of potential nonattainment areas remains uncertain and could ultimately include areas within the Company’s service territory. Implementation of the revised SO 2 standard could result in additional required reductions in SO 2 emissions and increased compliance and operation costs. Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO 2 ), which established a new one-hour standard, became effective on April 12, 2010. Although none of the areas within the Company’s service territory are expected to be designated as nonattainment for the NO 2 standard, based on current ambient air quality monitoring data, the new NO 2 standard could result in significant additional compliance and operational costs for units that require new source permitting. Twenty-eight eastern states, including the states of Florida, Georgia, and Mississippi, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO x and/or SO 2 to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. The states of Florida, Georgia, and Mississippi have completed plans to implement CAIR, and emissions reductions are being accomplished by the installation and operation of emissions controls at the Company’s coal-fired facilities and/or by the purchase of emissions allowances. On August 2, 2010, the EPA published a proposed rule, referred to as the Transport Rule, to replace CAIR. This proposed rule would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO 2 and NO x that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Florida and Georgia, to reduce annual emissions of SO 2 and NO x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Florida, Georgia, and Mississippi, to achieve additional reductions in NO x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading II-272 SoCo FOIA Response 002629 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report of emissions allowances; however, the EPA also requested comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA stated that it also intends to develop a second phase of the Transport Rule in 2011 to address the more stringent ozone air quality standards after they are finalized. The EPA expects to finalize the Transport Rule in June 2011 and require compliance beginning in 2012. The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO 2 and NO x , and no additional controls beyond CAIR are anticipated to be necessary at the Company’s facilities. States have completed or are currently completing implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress. The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal- and oil-fired electric generating units which will establish emission limitations for numerous hazardous air pollutants, including mercury. As part of a proceeding in the U.S. District Court for the District of Columbia, the EPA has entered into a consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011. The impacts of the eight-hour ozone, fine particulate matter, SO 2 and NO 2 standards, the proposed Transport Rule, the Clean Air Visibility Rule, and the proposed MACT rule for electric generating units on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any pending and future legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO 2 and NO x emissions controls within the next several years to ensure continued compliance with applicable air quality requirements. In addition, certain units in the State of Georgia, including Plant Scherer Unit 3, which is coowned by the Company, are required to install specific emissions controls according to a schedule set forth in the state’s MultiPollutant Rule, which is designed to reduce emissions of SO 2 , NO x , and mercury. Water Quality In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. In April 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is expected to propose revisions to the regulations in March 2011 and issue final regulations in mid-2012. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on the specific provisions of the EPA’s final rule and on the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time. However, if the final rules require the installation of cooling towers at certain existing facilities of the Company, the Company may be subject to significant additional compliance costs and capital expenditures that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. In December 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted, and the EPA has announced its intention to adopt such revisions by January 2014. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Company facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, and, therefore, cannot be determined at this time. In addition, the State of Florida is finalizing nutrient water quality standards to limit the amount of nitrogen and phosphorous allowed in state waters. The impact of these standards will depend on the specific requirements of the final rule and cannot be determined at this time. II-273 SoCo FOIA Response 002630 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Environmental Remediation The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Included in this amount are costs associated with remediation of the Company’s substation sites. These projects have been approved by the Florida PSC for recovery through the environmental cost recovery clause; therefore, there is no impact to the Company’s net income as a result of these liabilities. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” for additional information. Coal Combustion Byproducts The Company currently operates three electric generating plants with on-site coal combustion byproduct storage facilities (some with both “wet” (ash ponds) and “dry” (landfill) storage facilities). In addition to on-site storage, the Company utilizes a portion of its coal combustion byproducts for beneficial reuse (approximately 20% in recent years). Historically, individual states have regulated coal combustion byproducts and the states in Southern Company’s service territory, including the States of Florida, Georgia and Mississippi, each have their own regulatory parameters. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments and compliance with applicable regulations. The EPA is currently evaluating whether additional regulation of coal combustion byproducts (including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June 21, 2010, the EPA published a proposed rule that requested comments on two potential regulatory options for the management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of, or significant change to, existing storage facilities and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. On November 19, 2010, Southern Company filed publicly available comments with the EPA regarding the rulemaking proposal. These comments included a preliminary cost analysis under various alternatives in the rulemaking proposal. The Company regards these estimates as pre-screening figures that should be distinguished from the more formalized cost estimates the Company provides for projects that are more definite as to the elements and timing of execution. Although its analysis was preliminary, Southern Company concluded that potential compliance costs under the proposed rules would be substantially higher than the estimates reflected in the EPA’s rulemaking proposal. The ultimate financial and operational impact of any new regulations relating to coal combustion byproducts cannot be determined at this time and will be dependent upon numerous factors. These factors include: whether coal combustion byproducts will be regulated as hazardous waste or non-hazardous waste; whether the EPA will require early closure of existing wet storage facilities; whether beneficial reuse will be limited or eliminated through a hazardous waste designation; whether the construction of lined landfills is required; whether hazardous waste landfill permitting will be required for on-site storage; whether additional waste water treatment will be required; the extent of any additional groundwater monitoring requirements; whether any equipment modifications will be required; the extent of any changes to site safety practices under a hazardous waste designation; and the time period over which compliance will be required. There can be no assurance as to the timing of adoption or the ultimate form of any such rules. While the ultimate outcome of this matter cannot be determined at this time, and will depend on the final form of any rules adopted and the outcome of any legal challenges, additional regulation of coal combustion byproducts could have a material impact on the generation, management, beneficial use, and disposal of such byproducts. Any material changes are likely to result in substantial additional compliance, operational, and capital costs that could affect future unit retirement and replacement decisions. Moreover, the Company could incur additional material asset retirement obligations with respect to closing existing storage facilities. The Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. II-274 SoCo FOIA Response 002631 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Global Climate Issues Although the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas emissions, neither this legislation nor similar measures passed the U.S. Senate before the end of the 2010 session. Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are expected to continue to be considered in Congress. The financial and operational impacts of climate or energy legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates. While climate legislation has yet to be adopted, the EPA is moving forward with regulation of greenhouse gases under the Clean Air Act. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. In December 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, which began on January 2, 2011, applies to sources and projects that would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed settlement agreement to issue standards of performance for greenhouse gas emissions from new and modified fossil fuel-fired electric generating units and greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012. All of the EPA’s final Clean Air Act rulemakings have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit; however, the court declined motions to stay the rules pending resolution of those challenges. As a result, the rules may impact the amount of time it takes to obtain PSD permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate outcome of these rules cannot be determined at this time and will depend on the content of the final rules and the outcome of any legal challenges. International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The most recent round of negotiations took place in December 2010. The outcome and impact of the international negotiations cannot be determined at this time. Although the outcome of federal, state, and international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions and could result in the retirement of a significant number of coal-fired generating units. See Item 1 – BUSINESS – “Rate Matters – Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. In 2009, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 11 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2010 is II-275 SoCo FOIA Response 002632 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report approximately 13 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The Company continues to evaluate its future energy and emissions profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions. PSC Matters General The Company’s rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company’s rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company’s base rates. In November 2010, the Florida PSC approved the Company’s annual cost recovery clause requests for its fuel, purchased power capacity, energy conservation, and environmental compliance cost recovery factors for 2011. The net effect of the approved changes to the Company’s cost recovery factors for 2011 is a 2.8% rate decrease for residential customers using 1,000 KWHs per month. The billing factors for 2011 are intended to allow the Company to recover projected 2011 costs as well as refund or collect the 2010 over or under recovered amounts in 2011. Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. See Notes 1 and 3 to the financial statements under “Revenues” and “Retail Regulatory Matters – Fuel Cost Recovery,” respectively, for additional information. Fuel Cost Recovery The Company petitions for fuel cost recovery rates to be approved by the Florida PSC on an annual basis. The fuel cost recovery rates include the costs of fuel and purchased energy. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. If, at any time during the year, the projected fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested. The change in the fuel cost under-recovered balance during 2010 was primarily due to higher than expected fuel costs and purchased power energy expenses. At December 31, 2010 and 2009, the under recovered fuel balance was approximately $17.4 million and $2.4 million, respectively, which is included in under recovered regulatory clause revenues, current in the balance sheets. Purchased Power Capacity Recovery The Florida PSC allows the Company to recover its costs for capacity purchased from other power producers under power purchase agreements (PPAs) through a separate cost recovery component or factor in the Company’s retail energy rates. Like the other specific cost recovery factors included in the Company’s retail energy rates, the rates for purchased capacity are set annually. When the Company enters into a new PPA, it is reviewed and approved by the Florida PSC for cost recovery purposes. As of December 31, 2010 and 2009, the Company had an over recovered purchased power capacity balance of approximately $4.4 million and $1.5 million, respectively, which is included in other regulatory liabilities, current in the balance sheets. Environmental Cost Recovery In August 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company’s plan for complying with certain federal and state regulations addressing air quality. The Company’s environmental compliance plan as filed in March 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The stipulation covers all elements of the current plan that are scheduled to be implemented in the 2007 through 2011 timeframe. On April 1, 2010, the Company filed an update to the plan, which was approved by the Florida PSC on November 15, 2010. The Florida PSC acknowledged that the costs associated with the Company’s CAIR and Clean Air Visibility Rule compliance plans are eligible for recovery through the environmental cost recovery clause. Annually, the II-276 SoCo FOIA Response 002633 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2010 and 2009, the over recovered environmental balance was approximately $10.4 million and $11.7 million, respectively, which is included in other regulatory liabilities, current in the balance sheets. See FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein, Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Cost Recovery,” and Note 7 to the financial statements under “Construction Program” for additional information. On July 22, 2010, Mississippi Power Company (Mississippi Power) filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and the Company, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million. The project is scheduled for completion in the fourth quarter 2014. The Company’s portion of the cost, if approved by the Florida PSC, is expected to be recovered through the environmental compliance recovery clause. Hearings on the certificate request were held with the Mississippi PSC on January 25, 2011 with a final order expected by February 28, 2011. The ultimate outcome of this matter cannot now be determined. Legislation Stimulus Funding On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S. Department of Energy, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. The Company will receive, and will match, $15.5 million under the agreement. The ultimate outcome of this matter cannot be determined at this time. Healthcare Reform On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, the Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the Company’s financial statements. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and related employee benefit plan costs. Any future impact on the Company’s financial statements cannot be determined at this time. See Note 5 to the financial statements under “Current and Deferred Income Taxes” for additional information. Income Tax Matters Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $8 million for the Company. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. II-277 SoCo FOIA Response 002634 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Bonus Depreciation On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which could have a significant impact on the future cash flows of the Company. The application of the bonus depreciation provisions in these acts in 2010 provided approximately $36 million in increased cash flow. The Company estimates the potential increased cash flow for 2011 to be between approximately $40 million and $50 million. Internal Revenue Code Section 199 Domestic Production Deduction The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 2010 and none is projected to be available for 2011. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. Other Matters The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues. ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors. Electric Utility Regulation The Company is subject to retail regulation by the Florida PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, II-278 SoCo FOIA Response 002635 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report the accounting estimates inherent in specific costs such as depreciation and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company. As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements. Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following: • Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters. • Changes in existing income tax regulations or changes in IRS or state revenue department interpretations of existing regulations. • Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party. • Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. • Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA. Unbilled Revenues Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations. Pension and Other Postretirement Benefits The Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. II-279 SoCo FOIA Response 002636 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Key elements in determining the Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company’s investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company’s target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. A 25 basis point change in any significant assumption would result in a $1.1 million or less change in total benefit expense and a $13 million or less change in projected obligations. FINANCIAL CONDITION AND LIQUIDITY Overview The Company’s financial condition remained stable at December 31, 2010. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information. The Company’s investments in the qualified pension plan remained stable in value as of December 31, 2010. In December 2010, the Company contributed $28 million to the qualified pension plan. Net cash provided from operating activities totaled $267.8 million, $194.2 million, and $147.9 million for 2010, 2009, and 2008, respectively. The $73.5 million increase in net cash provided from operating activities in 2010 was primarily due to a $99.2 million increase from deferred income taxes related to bonus depreciation and a $90.9 million decrease in fuel inventory, partially offset by a $109.4 million increase in accounts receivable related to fuel cost and a $25.7 million decrease related to the qualified pension plan. The $46.3 million increase in net cash provided from operating activities in 2009 was primarily due to a $134.5 million reduction in accounts receivable related to fuel cost, partially offset by a $40.5 million decrease in deferred income taxes and a $38.4 million increase in fuel inventory. The $69.1 million decrease in net cash provided from operating activities in 2008 was due primarily to a $61.0 million increase in cash used for the under recovered regulatory clause related to fuel. Net cash used for investing activities totaled $308.4 million, $468.4 million, and $348.7 million for 2010, 2009, and 2008, respectively. The changes in cash used for investing activities were primarily due to gross property additions to utility plant of $285.4 million, $450.4 million, and $390.7 million for 2010, 2009, and 2008, respectively. Funds for the Company’s property additions were provided by operating activities, capital contributions, and other financing activities. Net cash provided from financing activities totaled $48.4 million, $279.4 million, and $198.8 million for 2010, 2009, and 2008, respectively. The $231.0 million decrease in net cash provided from financing activities in 2010 was due primarily to $194.4 million higher issuances of pollution control revenue bonds and common stock in 2009 and a net $54.3 million decrease in senior notes outstanding. The $80.6 million increase in net cash provided from financing activities in 2009 was due primarily to $258.4 million in higher debt issuances and cash raised from a common stock sale, partially offset by a $157.0 million decrease in notes payable. The $178.6 million increase in net cash provided from financing activities in 2008 was due primarily to the issuance of $110 million in long-term debt and $50 million in short-term debt, and a $49.1 million change in commercial paper cash flows in 2008. The increase was partially offset by the issuance of $85 million in senior notes in 2007. Significant balance sheet changes in 2010 include increases in customer accounts receivable of $10.1 million; under recovered regulatory clause revenues of $15.4 million; other regulatory assets, deferred of $28.9 million, primarily due to an increase in PPA deferred capacity expense, and accumulated deferred income taxes of $85.5 million. Total property, plant, and equipment increased by $194.9 million primarily due to environmental control projects. Securities due within one year decreased by $30.0 million primarily due to senior notes maturing in the first quarter 2010. Employee benefit obligations decreased by $32.6 million primarily due to funding of the Company’s qualified pension plan. The Company’s ratio of common equity to total capitalization, including short-term debt, was 43.1% in 2010, 43.4% in 2009, and 42.9% in 2008. See Note 6 to the financial statements for additional information. II-280 SoCo FOIA Response 002637 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Sources of Capital The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, and short-term indebtedness. However, the amount, type, and timing of any future financings, if needed, will depend on prevailing market conditions, regulatory approval, and other factors. Security issuances are subject to regulatory approval by the Florida PSC pursuant to its rules and regulations. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Florida PSC, as well as the amounts, if any, registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. The Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term-debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At December 31, 2010, the Company had approximately $16.4 million of cash and cash equivalents, along with $240 million of unused committed lines of credit with banks to meet its short-term cash needs. These bank credit arrangements will expire in 2011 and $210 million contain provisions allowing one-year term loans executable at expiration. In February 2011, the Company renewed a $30 million credit facility. The Company plans to renew the other lines of credit during 2011 prior to their expiration. These credit arrangements provide liquidity support to the Company’s variable rate pollution control revenue bonds and commercial paper borrowings. As of December 31, 2010, the Company had $69 million outstanding of pollution control revenue bonds requiring liquidity support. In addition, the Company has substantial cash flow from operating activities and access to the capital markets to meet liquidity needs. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other traditional operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support. At December 31, 2010, the Company had $1.2 million in notes payable outstanding related to other energy services contracts. At December 31, 2010, the Company had approximately $92.0 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During 2010, the Company had an average of $44 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $108 million. At December 31, 2009, the Company had $88.9 million of commercial paper borrowings outstanding with a weighted average interest rate of 1.0% per annum. During 2009, the Company had an average of $51.7 million of commercial paper outstanding at a weighted average interest rate of 1.0% per annum and the maximum amount outstanding was $152.1 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash. Financing Activities In January 2010, the Company issued to Southern Company 500,000 shares of common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of the Company’s short-term debt and for other general corporate purposes. In April 2010, the Company issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 15, 2020. The net proceeds were used to repay at maturity $140 million aggregate principal amount of Series 2009A Floating Rate Senior Notes due June 28, 2010, to repay a portion of its outstanding short-term debt, and for general corporate purposes, including the Company’s continuous construction program. The Company settled $100 million of interest rate hedges related to the Series 2010A Senior Note issuance at a gain of approximately $1.5 million. The gain will be amortized to interest expense over 10 years. II-281 SoCo FOIA Response 002638 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report In June 2010, the Company incurred obligations in connection with the issuance of $21 million aggregate principal amount of the Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Plant Scherer Project), First Series 2010. The proceeds were used to fund pollution control and environmental improvement facilities at Plant Scherer. In September 2010, the Company issued $125 million aggregate principal amount of its Series 2010B 5.10% Senior Notes due October 1, 2040. The net proceeds were used to repay a portion of its outstanding short-term indebtedness, for general corporate purposes, including the Company’s continuous construction program, and for the redemption of all of the $40 million aggregate principal amount of the Company’s Series I 5.75% Senior Notes due September 15, 2033 and $35 million aggregate principal amount of the Company’s Series J 5.875% Senior Notes due April 1, 2044. On January 20, 2011, the Company issued to Southern Company 500,000 shares of the Company’s common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of the Company’s short-term indebtedness and for other general corporate purposes, including the Company’s continuous construction program. In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm-recovery, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Credit Rating Risk The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At December 31, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $125 million. At December 31, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $548 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market. On August 12, 2010, Moody’s Investors Service (Moody’s) downgraded the issuer and long-term debt ratings of the Company (senior unsecured to A3 from A2); Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of several Southern Company subsidiaries (including the Company) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of the Company to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of the Company (to Baa2 from Baa1). Moody’s announced that the ratings outlook for the Company is stable. Market Price Risk Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including but not limited to market valuation, value at risk, stress testing, and sensitivity analysis. To mitigate future exposure to changes in interest rates, the Company may enter into derivatives which are designated as hedges. The weighted average interest rate on $179 million of outstanding variable rate long-term debt at December 31, 2010 was 0.62%. If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $1.8 million at January 1, 2011. For further information, see Note 1 to the financial statements under “Financial Instruments” and Note 10 to the financial statements. To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for II-282 SoCo FOIA Response 002639 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report natural gas purchases. The Company continues to manage a financial hedging program for fuel purchased to operate its electric generating fleet implemented per the guidelines of the Florida PSC. The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the years ended December 31 were as follows: 2009 2010 Changes Changes Fair Value (in thousands) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes(a) Contracts outstanding at the end of the period, assets (liabilities), net $ (13,687) 17,613 (15,154) $ (11,228) $ (31,161) 41,683 (24,209) $ (13,687) (a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any. The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2010 was an increase of $2.5 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 2010, the Company had a net hedge volume of 19.6 million mmBtu with a weighted average contract cost approximately $0.67 per mmBtu above market prices and 10.7 million mmBtu at December 31, 2009 with a weighted average contract cost approximately $1.29 per mmBtu above market prices. Natural gas settlements are recovered through the Company’s fuel cost recovery clause. At December 31, 2010 and 2009, substantially all of the Company’s energy-related derivative contracts were designated as regulatory hedges and are related to the Company’s fuel hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clause. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented. The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 9 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2010 were as follows: December 31, 2010 Fair Value Measurements Total Maturity Fair Value Year 1 Years 2&3 Years 4&5 (in thousands) Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period $ (11,228) $ (11,228) $ (7,609) $ (7,609) $ (3,619) $ (3,619) $ $ - The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s Investors Service and Standard & Poor’s, a division of The McGraw Hill Companies, Inc., or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under “Financial Instruments” and Note 10 to the financial statements. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized. II-283 SoCo FOIA Response 002640 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Capital Requirements and Contractual Obligations The construction program of the Company is currently estimated to include a base level investment of $381.5 million, $395.5 million, and $384.1 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $175.9 million, $227.8 million, and $214.0 million for 2011, 2012, and 2013, respectively. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations of up to $17.1 million for 2011, up to $55.6 million for 2012, and up to $107.3 million for 2013. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the FERC and the Florida PSC. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 6, 7, and 10 to the financial statements for additional information. II-284 SoCo FOIA Response 002641 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Contractual Obligations 20122013 2011 20142015 After 2015 Uncertain Timing(d) Total (in thousands) Long-term debt(a) – Principal Interest Energy-related derivative obligations(b) Preference stock dividends(c) Operating leases Unrecognized tax benefits and interest(d) Purchase commitments(e) – Capital(f) Limestone(g) Coal Natural gas(h) Purchased power(i) Long-term service agreements(j) Pension and other postretirement benefit plans(k) Total $ 110,000 51,902 9,415 6,203 20,629 - 381,451 6,371 312,244 104,977 40,911 6,470 $ 1,050,573 $ 60,000 102,242 4,193 12,405 32,822 - 779,667 13,225 119,773 161,412 86,776 13,429 $ 1,385,944 $ 75,000 93,347 12,405 15,070 - 13,894 165,395 159,655 14,108 $ 548,874 $ 985,926 552,551 1,045 - 29,934 209,308 685,750 16,499 $ 2,481,013 $ 4,080 $ 1,230,926 800,042 13,608 31,013 69,566 4,080 $ 4,080 1,161,118 63,424 432,017 641,092 973,092 50,506 $ 5,470,484 (a) All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2011, as reflected in the statements of capitalization. (b) For additional information, see Notes 1 and 10 to the financial statements. (c) Preference stock does not mature; therefore, amounts are provided for the next five years only. (d) The timing related to the realization of $4.1 million in unrecognized tax benefits and corresponding interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Note 5 to the financial statements for additional information. (e) The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2010, 2009, and 2008 were $280 million, $260 million, and $277 million, respectively. (f) The Company provides forecasted capital expenditures for a three-year period. Amounts represent current estimates of total expenditures, excluding the Company’s estimates of potential incremental investments to comply with anticipated new environmental regulations of up to $17.1 million for 2011, up to $55.6 million for 2012, and up to $107.3 million for 2013. At December 31, 2010, significant purchase commitments were outstanding in connection with the construction program. (g) As part of the Company’s program to reduce SO 2 emissions from its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. (h) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2010. (i) The capacity and transmission related costs associated with PPAs are recovered through the purchased power capacity clause. See Notes 3 and 7 to the financial statements for additional information. (j) Long-term service agreements include price escalation based on inflation indices. (k) The Company forecasts contributions to the qualified pension and other postretirement benefit plans over a three-year period. The Company does not expect to be required to make any contributions to the qualified pension plan during the next three years. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company’s corporate assets. II-285 SoCo FOIA Response 002642 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2010 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company’s 2010 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, fuel cost recovery and other rate actions, environmental regulations and expenditures, future earnings, access to sources of capital, economic recovery, projections for the qualified pension plan and postretirement benefit trust contributions, financing activities, start and completion of construction projects, impacts of adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forwardlooking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: • • • • • • • • • • • • • • • • • • • • • the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation, regulatory investigations, proceedings or inquiries, including FERC matters and the EPA civil actions against the Company; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population, and business growth (and declines), and the effects of energy conservation measures; available sources and costs of fuels; effects of inflation; ability to control costs and avoid cost overruns during the development and construction of facilities; investment performance of the Company’s employee benefit plans; advances in technology; state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers; the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings; the ability of the Company to obtain additional generating capacity at competitive prices; catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC. The Company expressly disclaims any obligation to update any forward-looking statements. II-286 SoCo FOIA Response 002643 STATEMENTS OF INCOME For the Years Ended December 31, 2010, 2009, and 2008 Gulf Power Company 2010 Annual Report 2010 2009 2008 (in thousands) Operating Revenues: Retail revenues Wholesale revenues, non-affiliates Wholesale revenues, affiliates Other revenues Total operating revenues Operating Expenses: Fuel Purchased power, non-affiliates Purchased power, affiliates Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Interest income Interest expense, net of amounts capitalized Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Net Income Dividends on Preference Stock Net Income After Dividends on Preference Stock $1,308,726 109,172 110,051 62,260 1,590,209 $1,106,568 94,105 32,095 69,461 1,302,229 $1,120,766 97,065 106,989 62,383 1,387,203 742,322 41,278 55,948 280,585 121,498 101,778 1,343,409 246,800 573,407 23,706 68,276 260,274 93,398 94,506 1,113,567 188,662 635,634 29,590 79,750 277,478 84,815 87,247 1,194,514 192,689 7,213 123 (51,897) (3,011) (47,572) 199,228 71,514 127,714 6,203 $121,511 23,809 423 (38,358) (4,075) (18,201) 170,461 53,025 117,436 6,203 $111,233 9,969 3,155 (43,098) (4,064) (34,038) 158,651 54,103 104,548 6,203 $ 98,345 The accompanying notes are an integral part of these financial statements. II-287 SoCo FOIA Response 002644 STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2010, 2009, and 2008 Gulf Power Company 2010 Annual Report 2010 2009 2008 (in thousands) Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating activities -Depreciation and amortization, total Deferred income taxes Allowance for equity funds used during construction Pension, postretirement, and other employee benefits Stock based compensation expense Hedge settlements Other, net Changes in certain current assets and liabilities --Receivables -Prepayments -Fossil fuel stock -Materials and supplies -Prepaid income taxes -Property damage cost recovery -Other current assets -Accounts payable -Accrued taxes -Accrued compensation -Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Investment in restricted cash from pollution control revenue bonds Distribution of restricted cash from pollution control revenue bonds Cost of removal net of salvage Construction payables Payments pursuant to long-term service agreements Other investing activities Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds -Common stock issued to parent Capital contributions from parent company Pollution control revenue bonds Senior notes Other long-term debt issuances Redemptions -Pollution control revenue bonds Senior notes Payment of preference stock dividends Payment of common stock dividends Other financing activities Net cash provided from financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Supplemental Cash Flow Information: Cash paid during the period for -Interest (net of $2,875, $9,489 and $3,973 capitalized, respectively) Income taxes (net of refunds) Noncash decrease in notes payable related to energy services Noncash transactions - accrued property additions at year-end $127,714 $ 117,436 $ 104,548 127,897 82,681 (7,213) (23,964) 1,101 1,530 (4,126) 99,564 (16,545) (23,809) 1,769 933 (5,173) 93,607 23,949 (9,969) 1,585 765 (5,220) (4,934) (36,687) (10,796) 15,766 (6,251) (29,630) 55 15,683 1,427 5,122 7,471 267,780 83,245 (192) (75,145) (1,642) (6,355) 10,746 (12) 7,890 (2,404) (6,330) 10,255 194,231 (49,886) (310) (36,765) 8,927 (416) 26,143 3 (4,561) (6,511) 570 6,417 147,942 (285,793) 6,347 (1,145) (21,581) (6,011) (262) (308,445) (421,309) (49,188) 42,841 (9,751) (23,603) (7,421) (5) (468,436) (377,790) (8,713) 37,244 (5,468) 6,044 (348,683) (49,599) 107,438 135,000 22,032 130,400 140,000 - 75,324 37,000 110,000 4,451 50,000 2,242 21,000 300,000 (215,515) (6,203) (104,300) (3,253) 48,422 7,757 8,677 $ 16,434 $42,521 17,224 14,475 (1,214) (6,203) (89,300) (1,677) 279,439 5,234 3,443 $ 8,677 $40,336 73,889 (8,309) 42,050 (37,000) (1,300) (6,057) (81,700) (4,869) 198,836 (1,905) 5,348 $ 3,443 $39,956 40,176 61,006 The accompanying notes are an integral part of these financial statements. II-288 SoCo FOIA Response 002645 BALANCE SHEETS At December 31, 2010 and 2009 Gulf Power Company 2010 Annual Report Assets 2009 2010 (in thousands) Current Assets: Cash and cash equivalents Restricted cash and cash equivalents Receivables -Customer accounts receivable Unbilled revenues Under recovered regulatory clause revenues Other accounts and notes receivable Affiliated companies Accumulated provision for uncollectible accounts Fossil fuel stock, at average cost Materials and supplies, at average cost Other regulatory assets, current Prepaid expenses Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Plant in service, net of depreciation Construction work in progress Total property, plant, and equipment Other Property and Investments Deferred Charges and Other Assets: Deferred charges related to income taxes Prepaid pension costs Other regulatory assets, deferred Other deferred charges and assets Total deferred charges and other assets Total Assets $ 16,434 74,377 64,697 19,690 9,867 7,859 (2,014) 167,155 44,729 20,278 58,412 3,585 485,069 $ 8,677 6,347 64,257 60,414 4,285 4,107 7,503 (1,913) 183,619 38,478 19,172 44,760 3,634 443,340 3,634,255 1,069,006 2,565,249 209,808 2,775,057 16,352 3,430,503 1,009,807 2,420,696 159,499 2,580,195 15,923 46,357 7,291 219,877 34,936 308,461 $3,584,939 39,018 190,971 24,160 254,149 $3,293,607 The accompanying notes are an integral part of these financial statements. II-289 SoCo FOIA Response 002646 BALANCE SHEETS At December 31, 2010 and 2009 Gulf Power Company 2010 Annual Report Liabilities and Stockholder's Equity 2009 2010 (in thousands) Current Liabilities: Securities due within one year Notes payable Accounts payable -Affiliated Other Customer deposits Accrued taxes -Accrued income taxes Other accrued taxes Accrued interest Accrued compensation Other regulatory liabilities, current Liabilities from risk management activities Other current liabilities Total current liabilities Long-Term Debt (See accompanying statements) Deferred Credits and Other Liabilities: Accumulated deferred income taxes Accumulated deferred investment tax credits Employee benefit obligations Other cost of removal obligations Other regulatory liabilities, deferred Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Preference Stock (See accompanying statements) Common Stockholder's Equity (See accompanying statements) Total Liabilities and Stockholder's Equity Commitments and Contingent Matters (See notes) $110,000 93,183 $140,000 90,331 46,342 68,840 35,600 47,421 80,184 32,361 3,835 7,944 13,393 14,459 27,060 9,415 19,766 449,837 1,114,398 1,955 7,297 10,222 9,337 22,416 9,442 20,092 471,058 978,914 382,876 8,109 76,654 204,408 42,915 132,708 847,670 2,411,905 97,998 1,075,036 $3,584,939 297,405 9,652 109,271 191,248 41,399 92,370 741,345 2,191,317 97,998 1,004,292 $3,293,607 The accompanying notes are an integral part of these financial statements. II-290 SoCo FOIA Response 002647 STATEMENTS OF CAPITALIZATION At December 31, 2010 and 2009 Gulf Power Company 2010 Annual Report 2009 2010 (in thousands) Long Term Debt: Long-term notes payable -4.35% due 2013 4.90% due 2014 4.75% to 5.90% due 2016-2044 Variable rates (0.35% at 1/1/10) due 2010 Variable rates (0.71% at 1/1/11) due 2011 Total long-term notes payable Other long-term debt -Pollution control revenue bonds -1.50% to 6.00% due 2022-2049 Variable rates (0.39% to 0.47% at 1/1/11) due 2022-2039 Total other long-term debt Unamortized debt discount Total long-term debt (annual interest requirement -- $51.9 million) Less amount due within one year Long-term debt excluding amount due within one year Preferred and Preference Stock: Authorized - 20,000,000 shares--preferred stock - 10,000,000 shares--preference stock Outstanding - $100 par or stated value -- 6% preference stock -- 6.45% preference stock - 1,000,000 shares (non-cumulative) Total preference stock (annual dividend requirement -- $6.2 million) Common Stockholder's Equity: Common stock, without par value -Authorized - 20,000,000 shares Outstanding - 2010: 3,642,717 shares Outstanding - 2009: 3,142,717 shares Paid-in capital Retained earnings Accumulated other comprehensive income (loss) Total common stockholder's equity Total Capitalization $ 60,000 75,000 676,971 110,000 921,971 239,625 69,330 308,955 (6,528) $ 2009 (percent of total) 60,000 75,000 452,486 140,000 110,000 837,486 218,625 69,330 287,955 (6,527) 1,224,398 110,000 1,114,398 1,118,914 140,000 978,914 53,886 44,112 53,886 44,112 97,998 97,998 303,060 538,375 236,328 (2,727) 1,075,036 $2,287,432 2010 253,060 534,577 219,117 (2,462) 1,004,292 $2,081,204 48.7% 47.0% 4.3 4.7 47.0 100.0% 48.3 100.0% The accompanying notes are an integral part of these financial statements. II-291 SoCo FOIA Response 002648 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2010, 2009, and 2008 Gulf Power Company 2010 Annual Report Number of Common Shares Issued Common Stock Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total (in thousands) Balance at December 31, 2007 Net income after dividends on preference stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Change in benefit plan measurement date Balance at December 31, 2008 Net income after dividends on preference stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Change in benefit plan measurement date Balance at December 31, 2009 Net income after dividends on preference stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2010 1,793 $118,060 $435,008 $181,986 - - - 98,345 1,793 118,060 76,539 511,547 - - - 1,350 3,143 135,000 253,060 23,030 534,577 (89,300) (233) 219,117 2,470 (2,462) 135,000 23,030 2,470 (89,300) (233) 1,004,292 500 3,643 50,000 $303,060 3,798 $538,375 121,511 (104,300) $236,328 (265) $(2,727) 121,511 50,000 3,798 (265) (104,300) $1,075,036 (81,700) (1,214) 197,417 111,233 $(3,799) $731,255 - 98,345 (1,133) (4,932) 76,539 (1,133) (81,700) (1,214) 822,092 - 111,233 The accompanying notes are an integral part of these financial statements. II-292 SoCo FOIA Response 002649 STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2010, 2009, and 2008 Gulf Power Company 2010 Annual Report 2009 2010 2008 (in thousands) Net income after dividends on preference stock Other comprehensive income (loss): Qualifying hedges: Changes in fair value, net of tax of $(542), $1,132, and $(1,077), respectively Reclassification adjustment for amounts included in net income, net of tax of $376, $419, and $366, respectively Total other comprehensive income (loss) Comprehensive Income $121,511 $111,233 $98,345 (863) 1,803 (1,716) 598 (265) $121,246 667 2,470 $113,703 583 (1,133) $97,212 The accompanying notes are an integral part of these financial statements. II-293 SoCo FOIA Response 002650 NOTES TO FINANCIAL STATEMENTS Gulf Power Company 2010 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Gulf Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies − the Company, Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), and Mississippi Power Company (Mississippi Power) − are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. Certain prior years’ data presented in the financial statement have been reclassified to conform to the current year presentation. The equity method is used for entities in which the Company has significant influence but does not control. The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Florida Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years’ data presented in the financial statement have been reclassified to conform to the current year presentation. Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $99 million, $87 million, and $86 million during 2010, 2009, and 2008, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company has agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $8.9 million, $3.9 million, and $8.1 million and Mississippi Power $25.0 million, $20.9 million, and $22.8 million in 2010, 2009, and 2008, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under “Operating Leases” for additional information. The Company entered into a power purchase agreement (PPA), with Southern Power for a total of approximately 292 megawatts (MWs) annually from June 2009 through May 2014. Expenses associated with the PPA were $14.7 million, $13.2 million, and none in 2010, 2009, and 2008, respectfully. These costs have been approved for recovery by the Florida PSC through the Company’s purchase power capacity cost recovery clause. Additionally, the Company had $4.2 million of deferred capacity expenses included in prepaid expenses and other regulatory liabilities, current in the balance sheets at December 31, 2010 and 2009, respectfully. See Note 7 under “Fuel and Purchased Power Commitments” for additional information. The Company has an agreement with Alabama Power under which Alabama Power will make transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA. Revenue requirement obligations to Alabama Power for these upgrades are estimated to be $135 million for the entire project. These costs are estimated to begin in 2012 and will continue through 2023. These costs have been approved for recovery by the Florida PSC through the Company’s purchase power capacity cost recovery clause and by FERC in the transmission facilities cost allocation tariff. II-294 SoCo FOIA Response 002651 NOTES (continued) Gulf Power Company 2010 Annual Report The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any significant services to or from affiliates in 2010, 2009, or 2008. The traditional operating companies, including the Company, and Southern Power jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel and Purchased Power Commitments” for additional information. In 2010, the Company purchased an assembly fluted compressor from Georgia Power and an unbucketed turbine rotor from Southern Power for $3.9 million and $6.3 million, respectively. The Company also sold a universal distance piece to Southern Power, a compressor rotor and blades to Georgia Power and a turbine rotor and blades to Mississippi Power for $0.6 million, $3.9 million, and $6.2 million, respectively. There were no significant affiliate transactions for 2009. In 2008, the Company sold a turbine rotor assembly and a distance piece component to Southern Power for $9.4 million and $0.7 million, respectively. These affiliate transactions were made in accordance with FERC and state PSC rules and guidelines. II-295 SoCo FOIA Response 002652 NOTES (continued) Gulf Power Company 2010 Annual Report Regulatory Assets and Liabilities The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2010 2009 Note (in thousands) Deferred income tax charges Deferred income tax charges – Medicare subsidy Asset retirement obligations Other cost of removal obligations Deferred income tax credits Loss on reacquired debt Vacation pay Under recovered regulatory clause revenues Over recovered regulatory clause revenues Property damage reserve Fuel-hedging (realized and unrealized) losses Fuel-hedging (realized and unrealized) gains PPA charges Generation site selection/evaluation costs Other assets Environmental remediation PPA credits Other liabilities Retiree benefit plans, net Total assets (liabilities), net $ 42,352 4,332 (4,310) (204,408) (9,362) 15,874 8,288 17,437 (17,703) (27,593) 15,024 (2,376) 52,404 12,814 833 61,749 (7,536) (930) 74,930 $ 31,819 $ 39,018 (4,371) (191,248) (11,412) 14,599 8,120 2,384 (14,510) (24,046) 15,367 (190) 8,141 8,373 131 65,223 (7,536) (715) 91,055 $ (1,617) (a) (b) (a,j) (a) (a) (c) (d,j) (e) (e) (f) (g,j) (g,j) (j,k) (l) (e,j) (h,j) (j,k) (f) (i,j) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Recovered and amortized over periods not exceeding 14 years. See Note 5 under “Current and Deferred Income Taxes” for additional information. Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years. Recorded as earned by employees and recovered as paid, generally within one year. Recorded and recovered or amortized as approved by the Florida PSC, generally within one year. Recorded and recovered or amortized as approved by the Florida PSC. Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the fuel cost recovery clause. Recovered through the environmental cost recovery clause when the remediation is performed. Recovered and amortized over the average remaining service period which may range up to 15 years. Includes $166 thousand related to other postretirement benefits. See Note 2 and Note 5 for additional information. Not earning a return as offset in rate base by a corresponding asset or liability. Recovered over the life of the PPA for periods up to 14 years. Deferred pursuant to Florida Statute while the Company continues to evaluate certain potential new generation projects. In the event that a portion of the Company’s operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off or reclassify to accumulated other comprehensive income (OCI) related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. II-296 SoCo FOIA Response 002653 NOTES (continued) Gulf Power Company 2010 Annual Report Revenues Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under “Retail Regulatory Matters” for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emissions allowances as they are used. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information. Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction. The Company’s property, plant, and equipment consisted of the following at December 31: 2009 2010 (in thousands) Generation Transmission Distribution General Plant acquisition adjustment Total plant in service $ 2,157,619 337,055 982,022 154,762 2,797 $ 3,634,255 $ 2,034,826 317,298 938,393 136,934 3,052 $ 3,430,503 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed. II-297 SoCo FOIA Response 002654 NOTES (continued) Gulf Power Company 2010 Annual Report Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.5% in 2010, 3.1% in 2009, and 3.4% in 2008. Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The liability recognized to retire long-lived assets primarily relates to the Company’s combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Florida PSC, and are reflected in the balance sheets. Details of the asset retirement obligations included in the balance sheets are as follows: 2010 2009 (in thousands) Balance at beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions Balance at end of year $ 12,608 (1,794) 656 $ 11,470 $ 12,042 224 (300) 642 $ 12,608 Allowance for Funds Used During Construction (AFUDC) In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 7.65% for each of the years 2010, 2009, and 2008. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 7.39%, 26.64%, and 12.62% for 2010, 2009, and 2008, respectively. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For II-298 SoCo FOIA Response 002655 NOTES (continued) Gulf Power Company 2010 Annual Report assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. Property Damage Reserve The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The costs of such damage are charged to the reserve. The Florida PSC-approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $25.1 million and $36.0 million. The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company’s discretion. The Company accrued total expenses of $3.5 million in 2010, $3.5 million in 2009, and $3.5 million in 2008. As of December 31, 2010 and 2009, the balance in the Company’s property damage reserve totaled approximately $27.6 million and $24.0 million, respectively, which is included in deferred liabilities in the balance sheets. When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. Such a surcharge was authorized in 2005 after Hurricane Ivan in 2004 and was extended by a 2006 Florida PSC order approving a stipulation to address costs incurred as a result of Hurricanes Dennis and Katrina in 2005. According to the 2006 Florida PSC order, in the case of future storms, if the Company incurs cumulative costs for stormrecovery activities in excess of $10 million during any calendar year, the Company will be permitted to file a streamlined formal request for an interim surcharge. Any interim surcharge would provide for the recovery, subject to refund, of up to 80% of the claimed costs for storm-recovery activities. The Company would then petition the Florida PSC for full recovery through a final or non-interim surcharge or other cost recovery mechanism. Injuries and Damages Reserve The Company is subject to claims and lawsuits arising in the ordinary course of business. As permitted by the Florida PSC, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. The injuries and damages reserve was $2.0 million and $2.9 million at December 31, 2010 and 2009, respectively. For 2010, $1.6 million and $0.4 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. For 2009, $1.6 million and $1.3 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. Liabilities in excess of the reserve balance of $0.8 million and $0.1 million at December 31, 2010 and 2009, respectively, are included in deferred credits and other liabilities in the balance sheets. Corresponding regulatory assets of $0.8 million and $0.1 million at December 31, 2010 and 2009, respectively, are included in current assets in the balance sheets. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Florida PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost. II-299 SoCo FOIA Response 002656 NOTES (continued) Gulf Power Company 2010 Annual Report Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 9 for additional information. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exemption, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC-approved hedging program. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 10 for additional information. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2010. The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2010, the Company contributed approximately $28 million to the qualified pension plan. No contributions to the qualified pension plan are expected for the year ending December 31, 2011. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other post retirement trusts to the extent required by the FERC. For the year ending December 31, 2011, no other postretirement trust contributions are expected. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2007 for the 2008 plan year using a discount rate of 6.30% and an annual salary increase of 3.75%. Discount rate: Pension plans Other postretirement benefit plans Annual salary increase Long-term return on plan assets: Pension plans Other postretirement benefit plans 2010 2009 2008 5.53% 5.41 3.84 5.93% 5.84 4.18 6.75% 6.75 3.75 8.75 8.18 8.50 8.36 8.50 8.38 II-300 SoCo FOIA Response 002657 NOTES (continued) Gulf Power Company 2010 Annual Report The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate of 8.25% for 2011, decreasing gradually to 5.00% through the year 2019 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2010 as follows: 1 Percent Increase 1 Percent Decrease (in thousands) Benefit obligation Service and interest costs $ 3,802 205 $ 3,246 175 Pension Plans The total accumulated benefit obligation for the pension plans was $290 million in 2010 and $275 million in 2009. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2009 2010 (in thousands) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Plan amendments Actuarial loss (gain) Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability $ 298,886 $ 260,765 6,478 7,853 17,139 17,305 (12,884) (13,401) 460 27,388 5,183 298,886 316,286 254,059 38,736 28,434 (13,401) 307,828 $ (8,458) $ 229,407 36,840 696 (12,884) 254,059 (44,827) At December 31, 2010, the projected benefit obligations for the qualified and non-qualified pension plans were $300 million and $16 million, respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s pension plans consist of the following: 2009 2010 (in thousands) Prepaid pension costs Other regulatory assets Current liabilities, other Employee benefit obligations $ 7,291 75,096 (778) (14,971) $ 85,194 (910) (43,917) II-301 SoCo FOIA Response 002658 NOTES (continued) Gulf Power Company 2010 Annual Report Presented below are the amounts included in regulatory assets at December 31, 2010 and 2009 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2011. Estimated Amortization in 2011 2009 2010 (in thousands) Prior service cost Net (gain) loss Other regulatory assets, deferred $ 8,506 76,688 $ 85,194 $ 7,664 67,432 $ 75,096 $ 1,262 512 The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2010 and 2009 are presented in the following table: Regulatory Assets (in thousands) $ 71,990 14,906 - Balance at December 31, 2008 Net loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net (gain) Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 (1,478) (224) (1,702) 13,204 85,194 (8,857) 459 (1,302) (398) (1,700) (10,098) $ 75,096 Components of net periodic pension cost were as follows: 2009 2010 2008 (in thousands) Service cost Interest cost Expected return on plan assets Recognized net (gain) loss Net amortization Net periodic pension cost $ 7,853 17,305 (24,695) 398 1,302 $ 2,163 $ 6,478 17,139 (24,357) 224 1,478 $ 962 $ 6,750 15,475 (23,757) 334 1,478 $ 280 Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. II-302 SoCo FOIA Response 002659 NOTES (continued) Gulf Power Company 2010 Annual Report Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2010, estimated benefit payments were as follows: Benefit Payments (in thousands) 2011 2012 2013 2014 2015 2016 to 2020 $ 14,524 15,129 15,709 16,419 17,158 99,482 Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2009 2010 (in thousands) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial (gain) loss Plan amendments Retiree drug subsidy Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability $ 72,640 1,304 4,121 (4,068) (4,704) 324 69,617 $ 72,391 1,328 4,705 (4,115) 497 (2,416) 250 72,640 14,973 2,010 2,458 (3,744) 15,697 $ (53,920) 13,180 2,735 2,923 (3,865) 14,973 $ (57,667) Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s other postretirement benefit plans consist of the following: 2009 2010 (in thousands) Regulatory assets Regulatory liabilities Current liabilities, other Employee benefit obligations $ (166) (211) (53,709) $ 5,861 (57,667) II-303 SoCo FOIA Response 002660 NOTES (continued) Gulf Power Company 2010 Annual Report Presented below are the amounts included in regulatory assets at December 31, 2010 and 2009 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2011. Estimated Amortization in 2011 2009 2010 (in thousands) Prior service cost Net (gain) loss Transition obligation Regulatory assets (liabilities) $ $ 695 (1,311) 450 $ (166) 881 4,273 707 5,861 $ $ 186 (47) 257 The changes in the balance of regulatory assets and regulatory liabilities related to the other postretirement benefit plans for the plan years ended December 31, 2010 and 2009 are presented in the following table: Regulatory Assets Regulatory Liabilities (in thousands) Balance at December 31, 2008 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 $ $ 9,922 (1,097) (2,416) (323) (293) 68 (548) (4,061) $ 5,861 (5,455) - $ (257) (186) 37 (406) (5,861) $ - $ (166) (166) (166) Components of the other postretirement benefit plans’ net periodic cost were as follows: 2010 2009 2008 (in thousands) Service cost Interest cost Expected return on plan assets Net amortization Net postretirement cost $ 1,304 4,121 (1,481) 406 $ 4,350 $ 1,328 4,705 (1,436) 548 $ 5,145 $ 1,413 4,536 (1,452) 702 $ 5,199 The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2010, 2009, and 2008 by approximately $1.0 million, $1.3 million, and $1.4 million, respectively, and is expected to have a similar impact on future expenses. II-304 SoCo FOIA Response 002661 NOTES (continued) Gulf Power Company 2010 Annual Report Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows: Benefit Subsidy Payments Receipts Total (in thousands) 2011 2012 2013 2014 2015 2016 to 2020 $ 4,461 4,706 4,931 5,177 5,372 27,974 $ (372) (423) (477) (531) (589) (3,023) $ 4,089 4,283 4,454 4,646 4,783 24,951 Benefit Plan Assets Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The composition of the Company’s pension plan and other postretirement benefit plan assets as of December 31, 2010 and 2009, along with the targeted mix of assets for each plan, is presented below: Target 2010 Pension plan assets: Domestic equity International equity Fixed income Special situations Real estate investments Private equity Total 2009 29% 28 15 3 15 10 100% 29% 27 22 13 9 100% 33% 29 15 13 10 100% Other postretirement benefit plan assets: Domestic equity International equity Domestic fixed income Special situations Real estate investments Private equity Total 28% 27 18 3 14 10 100% 28% 26 25 12 9 100% 32% 28 18 12 10 100% The investment strategy for plan assets related to the Company’s qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is longterm in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk II-305 SoCo FOIA Response 002662 NOTES (continued) Gulf Power Company 2010 Annual Report management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. An actively-managed mix of growth stocks and value stocks with both developed and emerging market exposure. • Fixed income. A mix of domestic and international bonds. • Special situations. Though currently unfunded, established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private-market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2010 and 2009. The fair values presented are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund. II-306 SoCo FOIA Response 002663 NOTES (continued) Gulf Power Company 2010 Annual Report The fair values of pension plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $ 57,023 57,515 $ 23,012 19,940 $ 31 - $ 80,066 77,455 92 8,295 $ 122,925 13,703 11,122 26,760 9,063 21,537 $ 125,137 92 30,355 28,727 $ 59,205 13,703 11,122 26,852 9,063 21,629 38,650 28,727 $ 307,267 (31) $ 122,894 $ 125,137 $ 59,205 (31) $ 307,236 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. II-307 SoCo FOIA Response 002664 NOTES (continued) Gulf Power Company 2010 Annual Report As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $ 50,434 65,197 $ 20,856 6,497 $ - $ 71,290 71,694 126 7,862 $ 123,619 18,783 5,107 12,589 455 15,396 $ 79,683 24,699 25,053 $ 49,752 18,783 5,107 12,589 455 15,522 32,561 25,053 $ 253,054 (202) $ 123,417 (51) $ 79,632 $ 49,752 (253) $ 252,801 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 are as follows: 2010 2009 Real Estate Investments Private Equity Real Estate Investments Private Equity $ 24,699 $ 25,053 $ 37,790 $ 22,063 2,596 810 3,406 2,250 $ 30,355 2,954 810 3,764 (90) $ 28,727 (10,741) (2,938) (13,679) 588 $ 24,699 1,724 452 2,176 814 $ 25,053 (in thousands) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance II-308 SoCo FOIA Response 002665 NOTES (continued) Gulf Power Company 2010 Annual Report The fair values of other postretirement benefit plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total $ $ 2,727 2,751 3 396 5,877 $ $ 1,100 955 655 533 1,280 953 1,030 6,506 $ $ 1 1,452 1,375 2,828 $ 3,828 3,706 655 533 1,280 953 1,033 1,848 1,375 $ 15,211 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. II-309 SoCo FOIA Response 002666 NOTES (continued) Gulf Power Company 2010 Annual Report As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $ 2,706 3,499 $ 8 420 6,633 $ (11) 6,622 $ 1,119 348 $ 1,008 274 675 553 827 4,804 $ (3) 4,801 $ - $ 3,825 3,847 $ 1,326 1,346 2,672 1,008 274 675 553 835 1,746 1,346 $ 14,109 $ 2,672 (14) $ 14,095 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 are as follows: 2010 Real Estate Private Investments Equity 2009 Real Estate Private Investments Equity (in thousands) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $ 1,326 $ 1,346 $ 2,073 $ 1,211 30 40 70 56 $ 1,452 34 34 (5) $ 1,375 (624) (154) (778) 31 $ 1,326 68 25 93 42 $ 1,346 Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2010, 2009, and 2008 were $3.6 million, $3.7 million, and $3.5 million, respectively. II-310 SoCo FOIA Response 002667 NOTES (continued) Gulf Power Company 2010 Annual Report 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. Environmental Matters New Source Review Actions In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to the Company with respect to the Company’s Plant Crist. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility coowned by the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, II-311 SoCo FOIA Response 002668 NOTES (continued) Gulf Power Company 2010 Annual Report requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Remediation The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually. The Company’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $61.7 million as of December 31, 2010. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company’s substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through the Company’s environmental cost recovery clause; therefore, there is no impact to net income as a result of these liabilities. The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, the Company does not believe that additional liabilities, if any, at these sites would be material to the Company’s financial statements. II-312 SoCo FOIA Response 002669 NOTES (continued) Gulf Power Company 2010 Annual Report Income Tax Matters Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $8 million for the Company. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. Retail Regulatory Matters General The Company’s rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company’s rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company’s base rates. In November 2010, the Florida PSC approved the Company’s annual cost recovery clause requests for its fuel, purchased power capacity, energy conservation, and environmental compliance cost recovery factors for 2011. The net effect of the approved changes to the Company’s cost recovery factors for 2011 is a 2.8% rate decrease for residential customers using 1,000 kilowatt-hours per month. The billing factors for 2011 are intended to allow the Company to recover projected 2011 costs as well as refund or collect the 2010 over or under recovered amounts in 2011. Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factors has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. Fuel Cost Recovery The Company petitions for fuel cost recovery rates to be approved by the Florida PSC on an annual basis. The fuel cost recovery rates include the costs of fuel and purchased energy. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. If, at any time during the year, the projected fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested. The change in the fuel cost under-recovered balance during 2010 was primarily due to higher than expected fuel costs and purchased power energy expenses. At December 31, 2010 and 2009, the under recovered fuel balance was approximately $17.4 million and $2.4 million, respectively, which is included in under recovered regulatory clause revenues, current in the balance sheets. Purchased Power Capacity Recovery The Florida PSC allows the Company to recover its costs for capacity purchased from other power producers under PPAs through a separate cost recovery component or factor in the Company’s retail energy rates. Like the other specific cost recovery factors included in the Company’s retail energy rates, the rates for purchased capacity are set annually. When the Company enters into a new PPA, it is reviewed and approved by the Florida PSC for cost recovery purposes. As of December 31, 2010 and 2009, the Company had an over recovered purchased power capacity balance of approximately $4.4 million and $1.5 million, respectively, which is included in other regulatory liabilities, current in the balance sheets. II-313 SoCo FOIA Response 002670 NOTES (continued) Gulf Power Company 2010 Annual Report Environmental Cost Recovery The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operations and maintenance expenses, emission allowance expense, depreciation, and a return on invested capital. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. In August 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company’s plan for complying with certain federal and state regulations addressing air quality. The Company’s environmental compliance plan as filed in March 2007 contemplates implementation of specific projects identified in the plan from 2007 through 2018. The stipulation covers all elements of the current plan that are scheduled to be implemented in the 2007 through 2011 timeframe. On April 1, 2010, the Company filed an update to the plan, which was approved by the Florida PSC on November 15, 2010. The Florida PSC acknowledged that the costs associated with the Company’s Clean Air Interstate Rule and Clean Air Visibility Rule compliance plans are eligible for recovery through the environmental cost recovery clause. Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2010 and 2009, the over recovered environmental balance was approximately $10.4 million and $11.7 million, respectively, which is included in other regulatory liabilities, current in the balance sheets. 4. JOINT OWNERSHIP AGREEMENTS The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 MWs. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company’s agent with respect to the construction, operation, and maintenance of these units. The Company and Georgia Power jointly own the 818 MWs capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company’s agent with respect to the construction, operation, and maintenance of the unit. The Company’s proportionate share of expenses related to both plants is included in the corresponding operating expense accounts in the statements of income and the Company is responsible for providing its own financing. At December 31, 2010, the Company’s percentage ownership and investment in these jointly owned facilities were as follows: Plant Scherer Unit 3 (coal) Plant Daniel Units 1 & 2 (coal) (in thousands) Plant in service Accumulated depreciation Construction work in progress Ownership $ 285,923(a) 104,492 72,250 25% $ 267,527 155,672 137 50% (a) Includes net plant acquisition adjustment of $2.8 million. II-314 SoCo FOIA Response 002671 NOTES (continued) Gulf Power Company 2010 Annual Report 5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Georgia and Mississippi. The Company files separate State of Florida income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: 2010 2009 2008 (in thousands) Federal – Current Deferred State – Current Deferred Total $ (14,115) 77,452 63,337 $ 62,980 (14,453) 48,527 $ 26,592 21,481 48,073 2,948 5,229 8,177 $ 71,514 6,590 (2,092) 4,498 $ 53,025 3,563 2,467 6,030 $ 54,103 The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2010 2009 (in thousands) Deferred tax liabilities– Accelerated depreciation Fuel recovery clause Pension and other employee benefits Regulatory assets associated with employee benefit obligations Regulatory assets associated with asset retirement obligations Other Total Deferred tax assets– Federal effect of state deferred taxes Postretirement benefits Pension and other employee benefits Property reserve Other comprehensive loss Asset retirement obligations Other Total Net deferred tax liabilities Less current portion, net Accumulated deferred income taxes $ 413,490 7,062 23,990 29,054 4,646 15,793 494,035 $ 332,971 965 15,539 37,768 5,106 9,084 401,433 14,757 20,723 33,047 12,712 1,712 4,646 19,727 107,324 386,711 (3,835) $ 382,876 13,076 18,465 41,124 10,642 1,546 5,106 16,995 106,954 294,479 2,926 $ 297,405 II-315 SoCo FOIA Response 002672 NOTES (continued) Gulf Power Company 2010 Annual Report At December 31, 2010, the tax-related regulatory assets to be recovered from customers was $42.4 million. These assets are attributable to tax benefits flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized allowance for funds used during construction. At December 31, 2010, the tax-related regulatory liabilities to be credited to customers was $9.4 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits. In 2010, the Company deferred $4.5 million as a regulatory asset related to the impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (together, the Acts). The Acts eliminated the deductibility of health care costs that are covered by federal Medicare subsidy payments. The Company will amortize the regulatory asset to amortization expense over the remaining average service life of 14 years. Amortization amounted to $0.2 million in 2010. In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $1.5 million in 2010, $1.6 million in 2009, and $1.7 million in 2008. At December 31, 2010, all investment tax credits available to reduce federal income taxes payable had been utilized. On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013). The application of the bonus depreciation provisions in these acts in 2010 significantly increased deferred income tax liabilities related to accelerated depreciation. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate was as follows: Federal statutory rate State income tax, net of federal deduction Non-deductible book depreciation Difference in prior years’ deferred and current tax rate Production activities deduction AFUDC equity Other, net Effective income tax rate 2010 35.0% 2.7 0.3 (0.3) (1.3) (0.5) 35.9% 2009 35.0% 1.7 0.3 (0.4) (0.9) (4.9) 0.3 31.1% 2008 35.0% 2.5 (0.5) 0.1 (2.2) (0.8) 34.1% The increase in the 2010 effective tax rate is primarily the result of a decrease in AFUDC equity, which is not taxable. The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009 a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 2010. II-316 SoCo FOIA Response 002673 NOTES (continued) Gulf Power Company 2010 Annual Report Unrecognized Tax Benefits For 2010, the total amount of unrecognized tax benefits increased by $2.2 million, resulting in a balance of $3.9 million as of December 31, 2010. Changes during the year in unrecognized tax benefits were as follows: 2010 2009 2008 (in thousands) Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions from prior periods Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year $ 1,639 1,027 1,204 $ 3,870 $ 294 455 890 $ 1,639 $ 887 93 11 (697) $ 294 The tax positions increase from current periods relates primarily to the tax accounting method change for repairs tax position and other miscellaneous uncertain tax positions. The tax positions increase from prior periods relates primarily to the tax accounting method change for repairs; and other miscellaneous uncertain tax positions. See Note 3 under “Income Tax Matters” for additional information. The impact on the Company’s effective tax rate, if recognized, was as follows: 2010 2009 2008 (in thousands) Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits $ 1,826 2,044 $ 3,870 $ 1,639 $ 1,639 $ 294 $ 294 The tax positions impacting the effective tax rate relate primarily to the production activities deduction. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note 3 under “Income Tax Matters” for additional information. Accrued interest for unrecognized tax benefits was as follows: 2010 2009 2008 (in thousands) Interest accrued at beginning of year Interest reclassified due to settlements Interest accrued during the year Balance at end of year $ 90 120 $ 210 $ 17 73 $ 90 $ 58 (54) 13 $ 17 The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has audited and closed all tax returns prior to 2007. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006. II-317 SoCo FOIA Response 002674 NOTES (continued) Gulf Power Company 2010 Annual Report 6. FINANCING Securities Due Within One Year At December 31, 2010, the Company had a $110 million bank loan that will mature on April 8, 2011. Senior Notes At December 31, 2010 and 2009, the Company had a total of $812.0 million and $727.5 million of senior notes outstanding, respectively. These senior notes are effectively subordinate to all secured debt of the Company which totaled approximately $41 million at December 31, 2010. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. At December 31, 2010 and 2009, the Company had a total of $309 million and $288 million of outstanding pollution control revenue bonds, respectively, and is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. Outstanding Classes of Capital Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company’s preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. No shares of preferred stock or Class A preferred stock were outstanding at December 31, 2010. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the preference stock. In addition, one series of the preference stock may be redeemed earlier at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends. On January 25, 2010, the Company issued to Southern Company 500,000 shares of the Company’s common stock, without par value, and realized proceeds of $50 million. On January 20, 2011, the Company issued to Southern Company 500,000 shares of the Company’s common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of the Company’s short-term debt and for other general corporate purposes, including the Company’s continuous construction program. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Assets Subject to Lien The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control revenue bonds with an outstanding principal amount of $41 million. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its subsidiaries. Bank Credit Arrangements At December 31, 2010, the Company had $240 million of lines of credit with banks, all of which remained unused. These bank credit arrangements will expire in 2011 and $210 million contain provisions allowing one-year term loans executable at expiration. Of the $240 million, $69 million provides support for variable rate pollution control revenue bonds and $171 million was available for liquidity support for the Company’s commercial paper program and for other general corporate purposes. In February 2011, the Company renewed a $30 million credit facility. Commitment fees average less than ⅜ of 1% for the Company. II-318 SoCo FOIA Response 002675 NOTES (continued) Gulf Power Company 2010 Annual Report Certain credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65%, as defined in the arrangements. At December 31, 2010, the Company was in compliance with these covenants. In addition, certain credit arrangements contain cross default provisions to other indebtedness that would trigger an event of default if the Company defaulted on indebtedness over a specified threshold. The cross default provisions are restricted only to indebtedness of the Company. The Company is currently in compliance with all such covenants. The Company borrows primarily through a commercial paper program that has the liquidity support of the Company’s committed bank credit arrangements. The Company may also borrow through various other arrangements with banks. At December 31, 2010, the Company had $92.0 million of commercial paper outstanding. At December 31, 2009, the Company had $88.9 million of commercial paper outstanding. During 2010, the maximum amount outstanding for commercial paper was $108 million, and the average amount outstanding was $44 million. The maximum amount outstanding for commercial paper in 2009 was $152.1 million and the average amount outstanding was $51.7 million. The weighted average annual interest rate on commercial paper was 0.3% and 1.0% for 2010 and 2009, respectively. 7. COMMITMENTS Construction Program The construction program of the Company is currently estimated to include a base level investment of $381.5 million in 2011, $395.5 million in 2012, and $384.1 million in 2013. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $175.9 million, $227.8 million, and $214.0 million for 2011, 2012, and 2013, respectively. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The Company does not have any significant new generating capacity under construction. Construction of new transmission and distribution facilities and other capital improvements, including those needed to meet environmental standards for the Company’s existing generation, transmission, and distribution facilities, are ongoing. Long-Term Service Agreements The Company has a long-term service agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for a combined cycle generating facility. The LTSA provides that GE will perform all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in the LTSA. In general, the LTSA is in effect through two major inspection cycles of the unit. Scheduled payments to GE, which are subject to price escalation, are made at various intervals based on actual operating hours of the unit. Total remaining payments to GE under the LTSA for facilities owned are currently estimated at $50.5 million over the remaining life of the LTSA, which is currently estimated to be up to seven years. However, the LTSA contains various cancellation provisions at the option of the Company. Payments made under the LTSA prior to the performance of any planned inspections are recorded as prepayments. These amounts are included in deferred charges and other assets in the balance sheets for 2010 and current assets and deferred charges and other assets in the balance sheets for 2009. Inspection costs are capitalized or charged to expense based on the nature of the work performed. II-319 SoCo FOIA Response 002676 NOTES (continued) Gulf Power Company 2010 Annual Report Limestone Commitments As part of the Company's program to reduce sulfur dioxide emissions from certain of its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. The Company has a minimum contractual obligation of 0.8 million tons, equating to approximately $63 million, through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $6.4 million in 2011, $6.5 million in 2012, $6.7 million in 2013, $6.9 million in 2014, and $7.0 million in 2015. Limestone costs are recovered through the environmental cost recovery clause. Fuel and Purchased Power Commitments To supply a portion of the fuel requirements of the generating plants, the Company has entered into various long-term commitments for the procurement of fossil fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emissions allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2010. Also, the Company has entered into various long-term commitments for the purchase of capacity, energy, and transmission. The energy-related costs associated with PPAs are recovered through the fuel cost recovery clause. The capacityrelated costs associated with PPAs are recovered through the purchased power capacity cost recovery clause. Total estimated minimum long-term obligations at December 31, 2010 were as follows: Commitments Purchased Power* Natural Gas Coal (in thousands) 2011 2012 2013 2014 2015 2016 and thereafter Total $ 40,911 41,327 45,449 66,812 92,843 685,750 $ 973,092 $ 104,977 86,108 75,304 86,101 79,294 209,308 $ 641,092 $ 312,244 119,773 $ 432,017 *Included above is $186.6 million in obligations with affiliated companies. Certain PPAs are accounted for as operating leases. Additional commitments for fuel will be required to supply the Company’s future needs. SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. II-320 SoCo FOIA Response 002677 NOTES (continued) Gulf Power Company 2010 Annual Report Operating Leases The Company has operating lease agreements with various terms and expiration dates. Rental expenses related to these operating leases totaled $23.1 million, $10.1 million, and $5.0 million for 2010, 2009, and 2008, respectively. At December 31, 2010, estimated minimum lease payments for noncancelable operating leases were as follows: Minimum Lease Payments Barges & Rail Cars Other Total (in thousands) 2011 2012 2013 2014 2015 2016 and thereafter Total $ 18,482 16,608 15,529 14,385 554 1,045 $ 66,603 $ 2,147 452 233 131 $ 2,963 $ 20,629 17,060 15,762 14,516 554 1,045 $ 69,566 The Company and Mississippi Power jointly entered into operating lease agreements for aluminum rail cars for the transportation of coal to Plant Daniel. The Company has the option to purchase the rail cars at the greater of lease termination value or fair market value or to renew the leases at the end of each lease term. The Company and Mississippi Power also have separate lease agreements for other rail cars that do not include purchase options. The Company’s share of the lease costs, charged to fuel inventory and recovered through the fuel cost recovery clause, was $3.5 million in 2010, $4.0 million in 2009, and $4.0 million in 2008. The Company’s annual railcar lease payments for 2011 through 2015 will average approximately $1.1 million and after 2015, lease payments total in aggregate approximately $1.0 million. The Company has other operating lease agreements for aluminum rail cars for transportation of coal to Plant Scholtz and to the Alabama State Docks located in Mobile, Alabama. At the Alabama State Docks this coal is transferred from the railcar to barge for transportation to Plant Crist and Plant Smith. The Company has the option to renew the leases at the end of each lease term. The Company’s lease costs, charged to fuel inventory and recovered through the fuel cost recovery clause, were $3.9 million in 2010, $4.0 million in 2009, and none in 2008. The Company’s annual railcar lease payments for 2011 through 2013 will average approximately $2.1 million. The Company entered into operating lease agreements for barges and tow boats for the transport of coal to Plants Crist and Smith. The Company has the option to renew the leases at the end of each lease term. The Company’s lease costs, charged to fuel inventory and recovered through the fuel cost recovery clause, were $13.5 million in 2010 and none in both 2009 and 2008. The Company’s annual barge and tow boat lease payments for 2011 through 2014 will average approximately $13.4 million. 8. STOCK COMPENSATION Stock Option Plan Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2010, there were 290 current and former employees of the Company participating in the stock option plan, and there were 10 million shares of Southern Company common stock remaining available for awards under this plan and the Performance Share Plan discussed below. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting. The estimated fair values of stock options granted in 2010, 2009, and 2008 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. II-321 SoCo FOIA Response 002678 NOTES (continued) Gulf Power Company 2010 Annual Report Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Dividend yield Weighted average grant-date fair value 2010 17.4% 5.0 2.4% 5.6% $ 2.23 2009 15.6% 5.0 1.9% 5.4% $ 1.80 2008 13.1% 5.0 2.8% 4.5% $ 2.37 The Company’s activity in the stock option plan for 2010 is summarized below: Outstanding at December 31, 2009 Granted Exercised Cancelled Outstanding at December 31, 2010 Exercisable at December 31, 2010 Shares Subject to Option 1,658,121 324,919 (246,822) (253) 1,735,965 1,056,570 Weighted Average Exercise Price $ 32.28 31.18 29.50 30.17 $ 32.47 $ 32.92 The number of stock options vested, and expected to vest in the future, as of December 31, 2010 was not significantly different from the number of stock options outstanding at December 31, 2010 as stated above. As of December 31, 2010, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $10.0 million and $5.6 million, respectively. As of December 31, 2010, there was $0.3 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 11 months. For the years ended December 31, 2010, 2009, and 2008, total compensation cost for stock option awards recognized in income was $0.8 million, $0.9 million, and $0.8 million, respectively, with the related tax benefit also recognized in income of $0.3 million, $0.4 million, and $0.3 million, respectively. The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. The total intrinsic value of options exercised during the years ended December 31, 2010, 2009, and 2008 was $1.6 million, $0.2 million, and $1.3 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $0.6 million, $0.1 million, and $0.5 million for the years ended December 31, 2010, 2009, and 2008, respectively. Performance Share Plan In 2010, Southern Company implemented the performance share program under its omnibus incentive compensation plan, which provides performance share award units to a large segment of its employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company’s total shareholder return (TSR) over the three-year performance period which measures Southern Company’s relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the II-322 SoCo FOIA Response 002679 NOTES (continued) Gulf Power Company 2010 Annual Report performance period based on Southern Company’s actual TSR and may range from 0% to 200% of the original target performance share amount. The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company’s stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. Expected volatility used in the model of 20.7% was based on historical volatility of Southern Company’s stock over a period equal to the performance period. The risk-free rate of 1.4% was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units. The annualized dividend rate at the time of the grant was $1.75. During 2010, 35,933 performance share units were granted to the Company’s employees with a weighted-average grant date fair value of $30.13. During 2010, 365 performance share units were forfeited by the Company’s employees resulting in 35,568 unvested units outstanding at December 31, 2010. For the year ended December 31, 2010, the Company’s total compensation cost for performance share units recognized in income was $0.3 million, with the related tax benefit also recognized in income of $0.1 million. As of December 31, 2010, there was $0.6 million of total unrecognized compensation cost related to performance share award units that will be recognized over the next two years. 9. FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.    Level 1 consists of observable market data in an active market for identical assets or liabilities. Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs As of December 31, 2010: (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Energy-related derivatives Cash equivalents Total 11,770 $ 11,770 $ 2,380 $ 2,380 $ $ - $ 2,380 11,770 $ 14,150 Liabilities: Energy-related derivatives $ $13,608 $ - $ 13,608 $ - II-323 SoCo FOIA Response 002680 NOTES (continued) Gulf Power Company 2010 Annual Report Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and London Interbank Offered Rate interest rates. See Note 10 for additional information on how these derivatives are used. As of December 31, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: As of December 31, 2010: Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period None Daily Not applicable (in thousands) Cash equivalents: Money market funds $ 11,770 The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis, up to the full amount of the Company’s investment in the money market funds. As of December 31, 2010 and 2009, other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in thousands) Long-term debt: 2010 2009 $ 1,224,398 $ 1,118,914 $ 1,258,428 $ 1,137,761 The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). 10. DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Florida PSC, through the use of financial derivative contracts, and recently has started using financial options which is expected to continue to mitigate price volatility. To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. II-324 SoCo FOIA Response 002681 NOTES (continued) Gulf Power Company 2010 Annual Report Energy-related derivative contracts are accounted for in one of two methods:   Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause. Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2010, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Net Purchased mmBtu* Gas Longest Hedge Date Longest Non-Hedge Date 2015 - (in thousands) 19,620 *mmBtu - million British thermal units Interest Rate Derivatives The Company also enters into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. At December 31, 2010, there were no interest rate derivatives outstanding. For the year ended December 31, 2010, the Company had realized net gains of $1.5 million upon termination of certain interest rate derivatives at the same time the related debt was issued. The effective portion of these gains has been deferred in OCI and is being amortized to interest expense over the life of the original interest rate derivative, reflecting the period in which the forecasted hedge transaction affects earnings. The estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2011 are $0.9 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2020. II-325 SoCo FOIA Response 002682 NOTES (continued) Gulf Power Company 2010 Annual Report Derivative Financial Statement Presentation and Amounts At December 31, 2010 and 2009, the fair value of energy-related derivatives and interest rate derivatives were reflected in the balance sheets as follows: Derivative Category Asset Derivatives Balance Sheet Location 2010 2009 Liability Derivatives Balance Sheet Location 2010 (in thousands) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets Other deferred charges and assets Total derivatives designated as hedging instruments for regulatory purposes Derivatives designated as hedging instruments in cash flow hedges Interest rate derivatives: Other current assets Derivatives not designated as hedging instruments Energy-related derivatives: Other current assets Total $ 1,801 $ 142 575 48 $ 2,376 $ 190 $ - $ 2,934 $ 4 $ $ 2,380 2009 (in thousands) 12 Liabilities from risk management activities Other deferred credits and liabilities $ 9,415 $ 9,442 4,193 4,447 $ 13,608 $ 13,889 Liabilities from risk management activities $ - $ - Liabilities from risk management activities $ - $ - $ 3,136 $ 13,608 $ 13,889 All derivative instruments are measured at fair value. See Note 9 for additional information. At December 31, 2010 and 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: Derivative Category Unrealized Losses Balance Sheet Location 2010 2009 Unrealized Gains Balance Sheet Location 2010 (in thousands) Energy-related derivatives: Other regulatory assets, current Other regulatory assets, deferred Total energy-related derivative gains (losses) $ (9,415) $ (9,442) (4,193) $ (13,608) (4,447) $ (13,889) 2009 (in thousands) Other regulatory liabilities, current Other regulatory liabilities, deferred $ 1,801 $142 575 $ 2,376 48 $190 II-326 SoCo FOIA Response 002683 NOTES (continued) Gulf Power Company 2010 Annual Report For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Hedging Relationships Derivative Category Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount 2009 Statements of Income Location 2010 Gain (Loss) Recognized in OCI on Derivative (Effective Portion) 2009 2008 2010 (in thousands) Interest rate derivatives $ (1,405) $ 2,934 2008 (in thousands) $(2,792) Interest expense, net of amounts capitalized $ (974) $ (1,085) $ (949) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2010, the fair value of derivative liabilities with contingent features was $0.8 million. At December 31, 2010, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-riskrelated contingent features, at a rating below BBB- and/or Baa3, is $40.0 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. 11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial data for 2010 and 2009 are as follows: Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preference Stock (in thousands) March 2010 June 2010 September 2010 December 2010 $ 356,712 403,171 483,455 346,871 $ 52,430 65,066 82,896 46,408 $ 25,300 32,317 42,907 20,987 March 2009 June 2009 September 2009 December 2009 $ 284,284 341,095 377,641 299,209 $ 30,914 54,320 67,392 36,036 $ 16,542 32,269 41,208 21,214 The Company’s business is influenced by seasonal weather conditions. II-327 SoCo FOIA Response 002684 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 Gulf Power Company 2010 Annual Report Operating Revenues (in thousands) Net Income after Dividends on Preference Stock (in thousands) Cash Dividends on Common Stock (in thousands) Return on Average Common Equity (percent) Total Assets (in thousands) Gross Property Additions (in thousands) Capitalization (in thousands): Common stock equity Preference stock Long-term debt Total (excluding amounts due within one year) Capitalization Ratios (percent): Common stock equity Preference stock Long-term debt Total (excluding amounts due within one year) Customers (year-end): Residential Commercial Industrial Other Total Employees (year-end) 2010 $1,590,209 2009 $1,302,229 2008 $1,387,203 2007 $1,259,808 2006 $1,203,914 $121,511 $111,233 $98,345 $84,118 $75,989 $104,300 11.69 $3,584,939 $285,379 $89,300 12.18 $3,293,607 $450,421 $81,700 12.66 $2,879,025 $390,744 $74,100 12.32 $2,498,987 $239,337 $70,300 12.29 $2,340,489 $147,086 $1,075,036 97,998 1,114,398 $2,287,432 $1,004,292 97,998 978,914 $2,081,204 $822,092 97,998 849,265 $1,769,355 $731,255 97,998 740,050 $1,569,303 $634,023 53,887 696,098 $1,384,008 47.0 4.3 48.7 100.0 48.3 4.7 47.0 100.0 46.5 5.5 48.0 100.0 46.6 6.2 47.2 100.0 45.8 3.9 50.3 100.0 376,561 53,263 272 562 430,658 1,330 374,091 53,272 279 512 428,154 1,365 373,595 53,548 287 499 427,929 1,342 373,036 53,838 298 491 427,663 1,324 364,647 53,466 295 484 418,892 1,321 II-328 SoCo FOIA Response 002685 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 (continued) Gulf Power Company 2010 Annual Report Operating Revenues (in thousands): Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total revenues from sales of electricity Other revenues Total Kilowatt-Hour Sales (in thousands): Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total Average Revenue Per Kilowatt-Hour (cents): Residential Commercial Industrial Total retail Wholesale Total sales Residential Average Annual Kilowatt-Hour Use Per Customer Residential Average Annual Revenue Per Customer Plant Nameplate Capacity Ratings (year-end) (megawatts) Maximum Peak-Hour Demand (megawatts): Winter Summer Annual Load Factor (percent) Plant Availability Fossil-Steam (percent) Source of Energy Supply (percent): Coal Gas Purchased power From non-affiliates From affiliates Total 2010 2009 2008 2007 2006 $707,196 439,468 157,591 4,471 1,308,726 109,172 110,051 1,527,949 62,260 $1,590,209 $588,073 376,125 138,164 4,206 1,106,568 94,105 32,095 1,232,768 69,461 $1,302,229 $581,723 369,625 165,564 3,854 1,120,766 97,065 106,989 1,324,820 62,383 $1,387,203 $537,668 329,651 135,179 3,831 1,006,329 83,514 113,178 1,203,021 56,787 $1,259,808 $510,995 305,049 132,339 3,655 952,038 87,142 118,097 1,157,277 46,637 $1,203,914 5,651,274 3,996,502 1,685,817 25,602 11,359,195 1,675,079 2,436,883 15,471,157 5,254,491 3,896,105 1,727,106 25,121 10,902,823 1,813,592 870,470 13,586,885 5,348,642 3,960,923 2,210,597 23,237 11,543,399 1,816,839 1,871,158 15,231,396 5,477,111 3,970,892 2,048,389 24,496 11,520,888 2,227,026 2,884,440 16,632,354 5,425,491 3,843,064 2,136,439 23,886 11,428,880 2,079,165 2,937,735 16,445,780 12.51 11.00 9.35 11.52 5.33 9.88 11.19 9.65 8.00 10.15 4.70 9.07 10.88 9.33 7.49 9.71 5.53 8.70 9.82 8.30 6.60 8.73 3.85 7.23 9.42 7.94 6.19 8.33 4.09 7.04 15,036 14,049 14,274 14,755 15,032 $1,882 $1,572 $1,552 $1,448 $1,416 2,663 2,659 2,659 2,659 2,659 2,544 2,519 56.1 94.7 2,310 2,538 53.8 89.7 2,360 2,533 56.7 88.6 2,215 2,626 55.0 93.4 2,195 2,479 57.9 91.3 64.6 17.8 61.7 28.0 77.3 15.3 81.8 13.6 82.5 12.4 13.2 4.4 100.0 2.2 8.1 100.0 2.6 4.8 100.0 1.6 3.0 100.0 1.9 3.2 100.0 II-329 SoCo FOIA Response 002686 MISSISSIPPI POWER COMPANY FINANCIAL SECTION 11?330 SoCo FOIA Response 002687 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Mississippi Power Company 2010 Annual Report The management of Mississippi Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010. Edward Day, VI President and Chief Executive Officer Moses H. Feagin Vice President, Treasurer, and Chief Financial Officer February 25, 2011 II-331 SoCo FOIA Response 002688 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Mississippi Power Company We have audited the accompanying balance sheets and statements of capitalization of Mississippi Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2010 and 2009, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule of the Company listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements (pages II-363 to II-407) present fairly, in all material respects, the financial position of Mississippi Power Company at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. Atlanta, Georgia February 25, 2011 II-332 SoCo FOIA Response 002689 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Mississippi Power Company 2010 Annual Report OVERVIEW Business Activities Mississippi Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Mississippi and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. The Company has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with reasonable retail rates will continue to challenge the Company for the foreseeable future. Hurricane Katrina, the worst natural disaster in the Company’s history, hit the Gulf Coast of Mississippi in August 2005, causing substantial damage to the Company’s service territory. As of December 31, 2010, the Company had over 8,300 fewer retail customers as compared to pre-storm levels due to obstacles in the rebuilding process as a result of the storm, coupled with the recessionary economy. See Note 1 to the financial statements under “Government Grants” and Note 3 to the financial statements under “Retail Regulatory Matters − Storm Damage Cost Recovery” for additional information. The Company’s retail base rates are set under the Performance Evaluation Plan (PEP), a rate plan approved by the Mississippi Public Service Commission (PSC). PEP was designed with the objective to reduce the impact of rate changes on customers and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. On June 3, 2010, the Mississippi PSC issued a certification of public convenience and necessity authorizing the acquisition, construction, and operation of a new integrated coal gasification combined cycle (IGCC) electric generating plant located in Kemper County, Mississippi, which is scheduled to be placed into service in 2014. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. Key Performance Indicators In striving to maximize shareholder value while providing cost-effective energy to over 185,000 customers, the Company continues to focus on several key indicators. These indicators are used to measure the Company’s performance for customers and employees. In recognition that the Company’s long-term financial success is dependent upon how well it satisfies its customers’ needs, the Company’s retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to the Company’s allowed return. PEP measures the Company’s performance on a 10-point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40%); service reliability, measured in outage minutes per customer (40%); and customer satisfaction, measured in a survey of residential customers (20%). See Note 3 to the financial statements under “Retail Regulatory Matters – Performance Evaluation Plan” for more information on PEP. In addition to the PEP performance indicators, the Company focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. The Company’s financial success is directly tied to the satisfaction of its customers. Management uses customer satisfaction surveys to evaluate the Company’s results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The actual Peak Season EFOR performance for 2010 was one of the best in the history of the Company. Net income after dividends on preferred stock is the primary measure of the Company’s financial performance. Recognizing the critical role in the Company’s success played by the Company’s employees, employee-related measures are a significant management focus. These measures include safety and inclusion. The 2010 safety performance of the Company was the third best in the history of the Company with an Occupational Safety and Health Administration Incidence Rate of 0.55. This achievement resulted in the Company being recognized as one of the top in safety performance among all utilities in the Southeastern Electric Exchange. Inclusion initiatives resulted in performance above target levels for the year. II-333 SoCo FOIA Response 002690 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report The Company’s 2010 results compared with its targets for some of these key indicators are reflected in the following chart. 2010 Target Performance Top quartile in customer surveys 5.06% or less 2010 Actual Performance Top quartile overall and in all segments 0.82% $77.8 million $80.2 million Key Performance Indicator Customer Satisfaction Peak Season EFOR Net income after dividends on preferred stock See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2010 reflects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations. Earnings The Company’s net income after dividends on preferred stock was $80.2 million in 2010 compared to $85.0 million in 2009. The 5.6% decrease in 2010 was primarily the result of decreases in wholesale energy and capacity revenues from customers served outside the Company’s service territory and increases in operations and maintenance expenses, depreciation and amortization, and taxes other than income taxes. These decreases in earnings were partially offset by increases in allowance for equity funds used during construction, revenues attributable to collection of Municipal and Rural Associations (MRA) emissions allowance cost with the Federal Energy Regulatory Commission’s (FERC) December 2010 acceptance of the Company’s wholesale filing made in October 2010, and territorial base revenues primarily resulting from warmer weather in the second and third quarters 2010 and colder weather in the first and fourth quarters 2010 compared to the corresponding periods in 2009. The Company’s net income after dividends on preferred stock was $85.0 million in 2009 compared to $86.0 million in 2008. The 1.2% decrease in 2009 was primarily the result of decreases in wholesale energy revenues and total other income and (expense) primarily resulting from an increase in interest expense and decreases in contracting work performed for customers, as well as an increase in income tax expense. These decreases in earnings were partially offset by an increase in territorial base revenues primarily due to a wholesale base rate increase accepted by the FERC effective in January 2009 and higher demand as well as a decrease in other non-fuel related expenses. Net income after dividends on preferred stock was $86.0 million in 2008 compared to $84.0 million in 2007. The 2.4% increase in 2008 was primarily the result of an increase in territorial base revenues due to a retail base rate increase effective January 2008 and an increase in wholesale capacity revenues, partially offset by an increase in depreciation and amortization primarily due to the amortization of regulatory items, an increase in non-fuel related expenses, and an increase in charitable contributions. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information. II-334 SoCo FOIA Response 002691 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report RESULTS OF OPERATIONS A condensed statement of income follows: Amount 2010 Increase (Decrease) from Prior Year 2009 2008 2010 (in millions) Operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Total other income and (expense) Income taxes Net income Dividends on preferred stock Net income after dividends on preferred stock $1,143.1 501.8 83.7 268.1 76.9 69.8 1,000.3 142.8 (14.6) 46.3 81.9 1.7 $ 80.2 $(6.3) (17.8) (8.3) 21.3 6.0 5.7 6.9 (13.2) 4.5 (3.9) (4.8) $ (4.8) $(107.1) (66.8) (34.6) (13.3) (0.1) (1.0) (115.8) 8.7 (7.8) 1.9 (1.0) $ (1.0) $142.8 92.2 30.7 4.8 10.7 4.8 143.2 (0.4) (1.1) (3.4) 1.9 $ 1.9 Operating Revenues Details of the Company’s operating revenues in 2010 and the prior two years were as follows: 2010 Amount 2009 2008 (in millions) Retail – prior year Estimated change in – Rates and pricing Sales growth (decline) Weather Fuel and other cost recovery Retail – current year Wholesale revenues – Non-affiliates Affiliates Total wholesale revenues Other operating revenues Total operating revenues Percent change $ 790.9 0.9 (2.9) 15.0 (6.0) 797.9 288.0 41.6 329.6 15.6 $1,143.1 (0.6)% $ 785.4 0.6 (1.3) 1.7 4.5 790.9 299.3 44.5 343.8 14.7 $1,149.4 (8.5)% $ 727.2 18.8 (1.1) (1.8) 42.3 785.4 353.8 100.9 454.7 16.4 $1,256.5 12.8% Total retail revenues for 2010 increased 0.9% when compared to 2009 primarily as a result of higher weather-driven energy sales, partially offset by lower fuel revenues. Total retail revenues for 2009 increased 0.7% when compared to 2008 primarily as a result of slightly higher energy sales and fuel revenues. Total retail revenues for 2008 increased 8.0% when compared to 2007 primarily as a result of a retail base rate increase effective in January 2008 and higher fuel revenues. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (or decline) and weather. II-335 SoCo FOIA Response 002692 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information. The fuel and other cost recovery revenues decreased in 2010 when compared to 2009 primarily as a result of lower recoverable fuel costs, partially offset by an increase in revenues related to ad valorem taxes. The fuel and other cost recovery revenues increased in 2009 when compared to 2008 primarily as a result of higher recoverable fuel costs. The fuel and other cost recovery revenues increased in 2008 when compared to 2007 primarily as a result of the increase in fuel and purchased power expenses. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside the Company’s service territory. Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Wholesale revenues from sales to non-affiliates decreased $11.4 million, or 3.8%, in 2010 as compared to 2009 as a result of an $11.8 million decrease in energy revenues, of which $9.5 million was associated with lower fuel prices and $2.3 million was associated with a decrease in kilowatt-hour (KWH) sales, partially offset by a $0.4 million increase in capacity revenues. Wholesale revenues from sales to non-affiliates decreased $54.5 million, or 15.4%, in 2009 as compared to 2008 as a result of a $54.1 million decrease in energy revenues, of which $27.6 million was associated with lower fuel prices and $26.4 million was associated with a decrease in KWH sales, and a $0.5 million decrease in capacity revenues. Wholesale revenues from sales to non-affiliates increased $30.7 million, or 9.5%, in 2008 as compared to 2007 as a result of a $30.4 million increase in energy revenues, of which $40.4 million was associated with higher fuel prices and a $0.3 million increase in capacity revenues, partially offset by a $10.0 million decrease in KWH sales. Included in wholesale revenues from sales to non-affiliates are revenues from rural electric cooperative associations and municipalities located in southeastern Mississippi. The related revenues increased 4.2%, 1.5%, and 8.3% in 2010, 2009, and 2008, respectively. The 2010 increase was driven primarily by warmer weather in the second and third quarters 2010 and colder weather in the first and fourth quarters 2010 compared to the corresponding periods in 2009. The customer demand experienced by these utilities is determined by factors very similar to those experienced by the Company. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at marketbased rates (MBRs) that generally provide a margin above the Company’s variable cost to produce the energy. Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. Wholesale revenues from sales to affiliated companies decreased 6.6% in 2010 when compared to 2009, decreased 55.9% in 2009 when compared to 2008, and increased 118.6% in 2008 when compared to 2007. These energy sales do not have a significant impact on earnings since this energy is generally sold at marginal cost. Other operating revenues in 2010 increased $1.0 million, or 6.6%, from 2009 primarily due to an $0.8 million increase in rent from electric property. Other operating revenues in 2009 decreased $1.7 million, or 10.6%, from 2008 primarily due to a $1.0 million decrease in transmission revenues. Other operating revenues in 2008 decreased $0.9 million, or 5.0%, from 2007 primarily due to a sale of oil inventory and a customer contract buyout in 2007 totaling $0.9 million. II-336 SoCo FOIA Response 002693 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2010 and percent change by year were as follows: Total KWHs 2010 Total KWH Percent Change 2009 2008 2010 Weather-Adjusted Percent Change 2009 2008 2010 (in millions) Residential Commercial Industrial Other Total retail Wholesale Non-affiliated Affiliated Total wholesale Total energy sales 2,296 2,922 4,466 39 9,723 9.8% 2.5 3.2 (0.7) 4.4 (1.4)% (0.2) 3.4 1.2 (0.6)% (0.7) (3.0) 0.3 (1.7) 4,284 774 5,058 14,781 (7.9) (7.8) (7.9) (0.2)% (7.3) (43.6) (15.6) (5.8)% (3.3) 44.9 4.7 0.8% (0.3)% (2.1) 3.2 (0.7) 0.7 (2.1)% (0.7) 3.4 0.8 (0.2)% 0.5 (3.0) 0.3 (1.3) Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Residential energy sales increased 9.8% in 2010 compared to 2009 due to warmer weather in the second and third quarters 2010 and colder weather in the first and fourth quarters 2010 compared to the corresponding periods in 2009. Residential energy sales decreased 1.4% in 2009 compared to 2008 due to the recessionary economy and a declining number of customers. Residential energy sales decreased 0.6% in 2008 compared to 2007 due to decreased customer usage mainly due to the recessionary economy and unfavorable summer weather. Commercial energy sales increased 2.5% in 2010 compared to 2009 due to warmer weather in the second and third quarters 2010 and colder weather in the first and fourth quarters 2010 compared to the corresponding periods in 2009 and improving economic conditions. Commercial energy sales decreased 0.2% in 2009 compared to 2008 due to the recessionary economy and a net decline in commercial customers. Commercial energy sales decreased 0.7% in 2008 compared to 2007 due to unfavorable weather and slower than expected customer growth due to the economy. Industrial energy sales increased 3.2% in 2010 compared to 2009 due to a return to more normal production levels for most of the Company’s industrial customers from an improving economy. Industrial energy sales increased 3.4% in 2009 compared to 2008 due to increased production of some of the Company’s industrial customers and the impacts of Hurricane Gustav, which negatively impacted industrial energy sales in 2008. Industrial energy sales decreased 3.0% in 2008 compared to 2007 due to lower customer use from the recessionary economy. Wholesale energy sales to non-affiliates decreased 7.9%, 7.3%, and 3.3% in 2010, 2009, and 2008, respectively. Included in wholesale sales to non-affiliates are sales to rural electric cooperative associations and municipalities located in southeastern Mississippi. Compared to the prior year, KWH sales to these customers increased 9.2% in 2010 due to warmer weather in the second and third quarters 2010 and colder weather in the first and fourth quarters 2010 compared to the corresponding periods in 2009, remained at the same levels in 2009 despite the recessionary economy and unfavorable weather, and decreased 0.9% in 2008 due to slowing growth and unfavorable weather. KWH sales to non-territorial customers located outside the Company’s service territory decreased 79.8% in 2010 as compared to 2009 primarily due to fewer short-term opportunity sales related to lower gas prices. KWH sales to non-territorial customers located outside the Company’s service territory decreased 29.0% in 2009 as compared to 2008 primarily due to fewer short-term opportunity sales related to lower gas prices. KWH sales to non-territorial customers located outside the Company’s service territory decreased 9.6% in 2008 as compared to 2007 primarily due to lower off-system sales. Wholesale sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Wholesale energy sales to affiliates decreased 7.8% in 2010 as compared to 2009 primarily due to an increase in the Company’s generation and an increase in territorial sales, resulting in less capacity available to sell to affiliate companies. Wholesale energy sales II-337 SoCo FOIA Response 002694 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report to affiliates decreased 43.6% in 2009 as compared to 2008 primarily due to a decrease in the Company’s generation and an increase in territorial sales, resulting in less capacity available to sell to affiliate companies. Wholesale energy sales to affiliates increased 44.9% in 2008 as compared to 2007 primarily due to the availability of the Company’s lower cost generation resources for sale to affiliated companies. Fuel and Purchased Power Expenses Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows: 2009 2008 2010 12,970 14,324 Total generation (millions of KWHs) 13,146 Total purchased power (millions of KWHs) 2,539 2,091 2,330 Sources of generation (percent) – Coal 48 67 51 Gas 52 33 49 Cost of fuel, generated (cents per net KWH) – Coal 4.29 3.52 4.08 Gas 4.43 6.83 4.22 Average cost of fuel, generated (cents per net KWH) 4.36 4.43 4.14 Average cost of purchased power (cents per net KWH) 3.62 6.05 3.59 Fuel and purchased power expenses were $585.5 million in 2010, a decrease of $26.1 million, or 4.3%, below the prior year costs. This decrease was primarily due to a $26.6 million decrease in the cost of fuel and purchased power, partially offset by a $0.5 million increase related to total KWHs generated and purchased. Fuel and purchased power expenses were $611.6 million in 2009, a decrease of $101.4 million, or 14.2%, below the prior year costs. This decrease was primarily due to a $69.9 million decrease in the cost of fuel and purchased power and a $31.5 million decrease related to total KWHs generated and purchased. Fuel and purchased power expenses were $713.1 million in 2008, an increase of $122.9 million, or 20.8%, above the prior year costs. This increase was primarily due to a $116.5 million increase in the cost of fuel and purchased power and a $6.4 million increase related to total KWHs generated and purchased. Fuel expense decreased $17.8 million in 2010 as compared to 2009. Approximately $25.8 million of the reduction in fuel expenses resulted primarily from lower fuel prices, partially offset by an $8.0 million increase in generation from Company-owned facilities. Fuel expense decreased $66.8 million in 2009 as compared to 2008. Approximately $8.1 million of the reduction in fuel expenses resulted primarily from lower gas prices and a $58.7 million decrease in generation from Company-owned facilities. Fuel expense increased $92.2 million in 2008 as compared to 2007. Approximately $86.1 million in additional fuel expenses resulted from higher coal, gas, and transportation prices and a $6.1 million increase in generation from Company-owned facilities. Purchased power expense decreased $8.3 million, or 9.0%, in 2010 when compared to 2009. The decrease was primarily due to a $0.7 million decrease in the cost of purchased power and a $7.6 million decrease in the amount of energy purchased resulting from higher cost opportunity purchases. Purchased power expense decreased $34.6 million, or 27.4%, in 2009 when compared to 2008. The decrease was primarily due to a $61.8 million decrease in the cost of purchased power, partially offset by a $27.2 million increase in the amount of energy purchased which was due to lower cost opportunity purchases. Purchased power expense increased $30.7 million, or 32.0%, in 2008 when compared to 2007. The increase was primarily due to a $30.4 million increase in the cost of purchased power. Energy purchases vary from year to year depending on demand and the availability and cost of the Company’s generating resources. These expenses do not have a significant impact on earnings since the energy purchases are generally offset by energy revenues through the Company’s fuel cost recovery clause. From an overall global market perspective, coal prices increased substantially in 2010 from the levels experienced in 2009, but remained lower than the unprecedented high levels of 2008. The slowly recovering U.S. economy and global demand from coal importing countries drove the higher prices in 2010, with concerns over regulatory actions, such as permitting issues, and their negative impact on production also contributing upward pressure. Domestic natural gas prices continued to be depressed by robust II-338 SoCo FOIA Response 002695 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report supplies, including production from shale gas, as well as lower demand. These lower natural gas prices contributed to increased use of natural gas-fueled generating units in 2009 and 2010. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” and Note 1 to the financial statements under “Fuel Costs” for additional information. Other Operations and Maintenance Expenses Total other operations and maintenance expenses increased $21.3 million in 2010 as compared to 2009 primarily due to an $8.5 million increase in generation maintenance expenses for several major planned outages, a $4.2 million increase in transmission and distribution expenses related to substation and overhead line maintenance and vegetation management costs, a $4.6 million increase in administrative and general expenses, and a $5.6 million increase in labor costs. Total other operations and maintenance expenses decreased $13.3 million in 2009 as compared to 2008 primarily due to a decrease of $12.2 million in transmission, distribution, customer service, and administrative and general expenses driven by overall reductions in spending in an effort to offset the effects of the recessionary economy. Also contributing to the decrease was an $8.3 million reduction in generation outage expenses in 2009. These decreases were partially offset by a $3.9 million increase in expenses for the combined cycle long-term service agreement due to a 36% increase in operating hours as a result of lower gas prices. Also offsetting the decrease was $3.4 million resulting from the 2008 reclassification of generation construction screening expenses to a regulatory asset upon the FERC’s acceptance of the wholesale base rate increase effective in January 2009. Total other operations and maintenance expenses increased $4.8 million in 2008 as compared to 2007 primarily due to a $6.9 million increase in transmission and distribution expenses, an increase in administrative expenses primarily resulting from the reclassification of System Restoration Rider (SRR) revenues of $3.8 million to expense pursuant to a January 2009 order from the Mississippi PSC, a $1.9 million increase in generation-related environmental expenses, and a $1.1 million increase in generation operations and outagerelated expenses. These increases were partially offset by a $9.3 million reclassification of generation construction screening expenses to a regulatory asset upon the FERC’s acceptance of the wholesale base rate increase effective in January 2009. See FUTURE EARNINGS POTENTIAL – “PSC Matters – System Restoration Rider,” and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information. Depreciation and Amortization Depreciation and amortization increased $6.0 million in 2010 compared to 2009 primarily due to a $2.9 million increase in amortization of environmental costs related to the approved Environmental Compliance Overview (ECO) Plan and a $2.7 million increase in depreciation primarily resulting from an increase in plant in service. Depreciation and amortization decreased $0.1 million in 2009 compared to 2008 primarily due to a $3.1 million decrease in amortization of environmental costs related to the approved ECO Plan, partially offset by a $2.8 million increase in depreciation resulting from an increase in plant in service. Depreciation and amortization increased $10.7 million in 2008 compared to 2007 primarily due to a $5.7 million increase in amortization related to a regulatory liability recorded in 2003 that ended in December 2007 in connection with the Mississippi PSC’s accounting order on Plant Daniel capacity, a $2.9 million increase in depreciation primarily due to an increase in plant in service, and a $2.4 million increase for amortization of certain reliability-related maintenance costs deferred in 2007 in accordance with a Mississippi PSC order. See Note 3 to the financial statements under “Retail Regulatory Matters – Performance Evaluation Plan” and “Environmental Compliance Overview Plan” for additional information. Taxes Other Than Income Taxes Taxes other than income taxes increased $5.7 million in 2010 compared to 2009 primarily as a result of a $5.5 million increase in ad valorem taxes and a $0.2 million increase in payroll taxes. Taxes other than income taxes decreased $1.0 million in 2009 compared to 2008 primarily as a result of an $0.8 million decrease in payroll taxes and a $0.2 million decrease in franchise taxes. Taxes other than income taxes increased $4.8 million in 2008 compared to 2007 primarily as a result of a $2.7 million increase in ad valorem taxes and a $1.3 million increase in municipal franchise taxes. II-339 SoCo FOIA Response 002696 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Allowance for Equity Funds Used During Construction Allowance for funds used during construction (AFUDC) equity increased $3.4 million in 2010 as compared to 2009. This increase was primarily due to increases in construction of the Kemper IGCC. The AFUDC equity change for 2009 as compared to 2008 was immaterial. The increase of $0.6 million in 2008 as compared to 2007 was primarily related to the Plant Watson cooling tower project. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. Interest Income Interest income decreased $0.6 million in 2010 as compared to 2009 primarily due to lower interest income related to a regulatory recovery mechanism for fuel and energy cost hedging. Interest income decreased $1.2 million in 2009 as compared to 2008 primarily due to lower interest income related to a regulatory recovery mechanism for fuel and energy cost hedging. The interest income change for 2008 as compared to 2007 was immaterial. Interest Expense, Net of Amounts Capitalized Interest expense, net of amounts capitalized decreased $0.6 million in 2010 compared to 2009 primarily due to a $2.8 million increase in AFUDC debt associated with the Kemper IGCC, partially offset by an increase in interest expense associated with the issuances of new long-term debt in September and December 2010. Interest expense, net of amounts capitalized increased $5.0 million in 2009 compared to 2008 primarily due to a $5.2 million increase in interest expense associated with the issuances of new long-term debt in November 2008 and March 2009, partially offset by the maturity of long-term debt and lower interest rates in 2009. Interest expense, net of amounts capitalized decreased $0.2 million in 2008 compared to 2007 primarily due to a $2.7 million decrease in borrowing and lower interest rates on short-term indebtedness and a $0.7 million decrease related to the redemption of outstanding trust preferred securities in 2007, partially offset by a $3.0 million increase in interest expense associated with the issuances of new long-term debt in November 2008 and November 2007. Other Income (Expense), Net Other income (expense), net increased $1.1 million in 2010 compared to 2009 primarily due to a $1.4 million increase in amounts collected from customers for contributions in aid of construction, partially offset by a $0.2 million decrease resulting from mark-tomarket losses on energy-related derivative positions. Other income (expense), net decreased $1.5 million in 2009 compared to 2008 primarily due to a $3.0 million decrease in customer projects and amounts collected from customers for construction of substation projects which had a tax effect of $2.6 million, partially offset by higher charitable contributions of $3.9 million in 2008. Other income (expense), net decreased $1.9 million in 2008 compared to 2007 primarily due to higher charitable contributions of $3.1 million, partially offset by a $0.4 million increase in revenues from contracting work performed for customers and a $0.6 million decrease in other deductions. Income Taxes Income taxes decreased $3.9 million, or 7.8%, in 2010 compared to 2009 primarily due to decreased pre-tax income, a decrease in unrecognized tax benefits, and an increase in AFUDC equity, which is non-taxable, partially offset by a decrease in the federal production activities deduction and a decrease in a State of Mississippi manufacturing investment tax credit. Income taxes increased $1.9 million, or 3.9%, in 2009 compared to 2008 primarily due to increased pre-tax income, the 2008 amortization of a regulatory liability pursuant to a December 2007 regulatory accounting order from the Mississippi PSC which occurred in 2008, and actualization of permanent differences from previous year tax returns, partially offset by an increase in the federal production activities deduction and an increase in a State of Mississippi manufacturing investment tax credit. Income taxes decreased $3.4 million, or 6.7%, in 2008 compared to 2007 primarily due to decreased pre-tax income, the amortization of a regulatory liability pursuant to a December 2007 regulatory accounting order from the Mississippi PSC, and a State of Mississippi manufacturing investment tax credit, partially offset by a decrease in the federal production activities deduction. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information. Effects of Inflation The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company’s results of operations has not been substantial in recent years. II-340 SoCo FOIA Response 002697 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in southeast Mississippi and to wholesale customers in the southeast U.S. Prices for electricity provided by the Company to retail customers are set by the Mississippi PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. See “FERC Matters” herein, ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein, and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information about regulatory matters. The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the Company’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company’s service area. Changes in economic conditions impact sales for the Company, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information. New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. These actions were filed concurrently with the issuance of notices of violation to the Company with respect to the Company’s Plant Watson. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. In early 2000, the EPA filed a motion to amend its complaint to add the Company as a defendant based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against Alabama Power is ongoing. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to the facility co-owned by the Company. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. II-341 SoCo FOIA Response 002698 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. II-342 SoCo FOIA Response 002699 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Environmental Statutes and Regulations General The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2010, the Company had invested approximately $226 million in environmental capital projects to comply with these requirements, with annual totals of $2 million, $22 million, and $41 million for 2010, 2009, and 2008, respectively. The Company expects that capital expenditures to comply with existing statutes and regulations will be $45 million, $94 million, and $127 million for 2011, 2012, and 2013, respectively. These environmental costs that are known and estimable at this time are included under the heading “Capital” in the table under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations of $0 in 2011, up to $18 million in 2012, and up to $55 million in 2013. The Company’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of any new or revised environmental statutes and regulations that are enacted, including the proposed environmental legislation and regulations described below; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel mix. Compliance with any new federal or state legislation or regulations relating to global climate change, air quality, coal combustion byproducts, including coal ash, water quality, or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the Company’s commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2010, the Company had spent approximately $109 million in reducing sulfur dioxide (SO 2 ) and nitrogen oxide (NO x ) emissions and in monitoring emissions pursuant to the Clean Air Act. As a result, emissions control projects have been completed recently or are underway. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements. The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone air quality standard. No area within the Company’s service area is currently designated as nonattainment under the current standard. In March 2008, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the level of the standard. Under the EPA’s current schedule, a final revision to the eight-hour ozone standard is expected in July 2011, with state implementation plans for any resulting nonattainment areas due in mid-2014. The revised eight-hour ozone standard is expected to result in designation of nonattainment areas within the Company’s service territory and could result in additional required reductions in NO x emissions. Final revisions to the National Ambient Air Quality Standard for SO 2 , including the establishment of a new one-hour standard, became effective on August 23, 2010. Since the EPA intends to rely on computer modeling for implementation of the SO 2 standard, the identification of potential nonattainment areas remains uncertain and could ultimately include areas within the Company’s service territory. Implementation of the revised SO 2 standard could result in additional required reductions in SO 2 emissions and increased compliance and operation costs. Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO 2 ), which established a new one-hour standard, became effective on April 12, 2010. Although none of the areas within the Company’s service territory are expected to be designated as nonattainment for the NO 2 standard, based on current ambient air quality monitoring data, the new NO 2 standard could result in significant additional compliance and operational costs for units that require new source permitting. II-343 SoCo FOIA Response 002700 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Twenty-eight eastern states, including the States of Mississippi and Alabama, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO x and/or SO 2 to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. The States of Mississippi and Alabama have completed plans to implement CAIR, and emissions reductions are being accomplished by the installation and operation of emissions controls at the Company’s coal-fired facilities and/or by the purchase of emissions allowances. On August 2, 2010, the EPA published a proposed rule, referred to as the Transport Rule, to replace CAIR. This proposed rule would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO 2 and NO x that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, to reduce annual emissions of SO 2 and NO x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Alabama and Mississippi, to achieve additional reductions in NO x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requested comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA stated that it also intends to develop a second phase of the Transport Rule in 2011 to address the more stringent ozone air quality standards after they are finalized. The EPA expects to finalize the Transport Rule in June 2011 and require compliance beginning in 2012. The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO 2 and NO x , and no additional controls beyond CAIR are anticipated to be necessary at any of the Company’s facilities. States have completed or are currently completing implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress. The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal- and oil-fired electric generating units which will establish emission limitations for numerous hazardous air pollutants, including mercury. As part of a proceeding in the U.S. District Court for the District of Columbia, the EPA has entered into a consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011. The impacts of the eight-hour ozone, SO 2 and NO 2 standards, the proposed Transport Rule, the Clean Air Visibility Rule, and the proposed MACT rule for electric generating units on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any pending and future legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO 2 and NO x emissions controls at certain facilities within the next several years to ensure continued compliance with applicable air quality requirements. See Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Compliance Overview Plan” for additional information. Water Quality In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. In April 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is expected to propose revisions to the regulations in March 2011 and issue final regulations in mid-2012. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will II-344 SoCo FOIA Response 002701 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report depend on the specific provisions of the EPA’s final rule and on the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time. However, if the final rules require the installation of cooling towers at certain existing facilities of the Company, the Company may be subject to significant additional compliance costs and capital expenditures that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. In December 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted, and the EPA has announced its intention to adopt such revisions by January 2014. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Company facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, and, therefore, cannot be determined at this time. Environmental Remediation The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” for additional information. Coal Combustion Byproducts The Company currently operates two electric generating plants with on-site coal combustion byproduct storage facilities (with both “wet” (ash ponds) and “dry” (landfill) storage facilities). In addition to on-site storage, the Company also sells a portion of its coal combustion byproducts to third parties for beneficial reuse (approximately 40% in recent years). Historically, individual states have regulated coal combustion byproducts and the states in Southern Company’s service territory, including the States of Mississippi and Alabama, each have their own regulatory parameters. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments and compliance with applicable regulations. The EPA is currently evaluating whether additional regulation of coal combustion byproducts (including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June 21, 2010, the EPA published a proposed rule that requested comments on two potential regulatory options for the management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of, or significant change to, existing storage facilities and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. On November 19, 2010, Southern Company filed publicly available comments with the EPA regarding the rulemaking proposal. These comments included a preliminary cost analysis under various alternatives in the rulemaking proposal. The Company regards these estimates as pre-screening figures that should be distinguished from the more formalized cost estimates the Company provides for projects that are more definite as to the elements and timing of execution. Although its analysis was preliminary, Southern Company concluded that potential compliance costs under the proposed rules would be substantially higher than the estimates reflected in the EPA’s rulemaking proposal. The ultimate financial and operational impact of any new regulations relating to coal combustion byproducts cannot be determined at this time and will be dependent upon numerous factors. These factors include: whether coal combustion byproducts will be regulated as hazardous waste or non-hazardous waste; whether the EPA will require early closure of existing wet storage facilities; whether beneficial reuse will be limited or eliminated through a hazardous waste designation; whether the construction of lined landfills is required; whether hazardous waste landfill permitting will be required for on-site storage; whether additional waste water treatment will be required; the extent of any additional groundwater monitoring requirements; whether any equipment modifications will be required; the extent of any changes to site safety practices under a hazardous waste designation; and the time period over which compliance will be required. There can be no assurance as to the timing of adoption or the ultimate form of any such rules. II-345 SoCo FOIA Response 002702 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report While the ultimate outcome of this matter cannot be determined at this time, and will depend on the final form of any rules adopted and the outcome of any legal challenges, additional regulation of coal combustion byproducts could have a material impact on the generation, management, beneficial use, and disposal of such byproducts. Any material changes are likely to result in substantial additional compliance, operational, and capital costs that could affect future unit retirement and replacement decisions. Moreover, the Company could incur additional material asset retirement obligations with respect to closing existing storage facilities. The Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition Global Climate Issues Although the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas emissions, neither this legislation nor similar measures passed the U.S. Senate before the end of the 2010 session. Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are expected to continue to be considered in Congress. The financial and operational impacts of climate or energy legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates. While climate legislation has yet to be adopted, the EPA is moving forward with regulation of greenhouse gases under the Clean Air Act. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. In December 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, which began on January 2, 2011, applies to sources and projects that would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed settlement agreement to issue standards of performance for greenhouse gas emissions from new and modified fossil-fuel fired electric generating units and greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012. All of the EPA’s final Clean Air Act rulemakings have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit; however, the court declined motions to stay the rules pending resolution of those challenges. As a result, the rules may impact the amount of time it takes to obtain PSD permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate outcome of these rules cannot be determined at this time and will depend on the content of the final rules and the outcome of any legal challenges. International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The most recent round of negotiations took place in December 2010. The outcome and impact of the international negotiations cannot be determined at this time. Although the outcome of federal, state, and international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level II-346 SoCo FOIA Response 002703 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. See Item 1 – BUSINESS – “Rate Matters – Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. In 2009, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 10 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2010 is approximately 10 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The Company is actively evaluating and developing electric generating technologies with lower greenhouse gas emissions. This includes construction of the Kemper IGCC facility with approximately 65% carbon capture. FERC Matters In October 2010, the Company filed a request with the FERC for a revised wholesale electric tariff and revised rates. Prior to making this filing, the Company reached a settlement with all of its customers who take service under the tariff. This settlement agreement was filed with the FERC as part of the request. The settlement agreement provided for an increase in annual base wholesale revenues in the amount of $4.1 million, effective January 1, 2011. In addition, the settlement agreement allows the Company to implement an emissions allowance cost clause, effective January 1, 2011. The emissions allowance cost clause contains an over and under recovery provision similar to the fuel recovery clause and is projected to collect $6.9 million in 2011. The settlement agreement also provided for collection of $2.8 million of 2010 emissions allowance expense for the period of September 1, 2010 through December 31, 2010 and allows the Company to defer the wholesale portion of the income tax expense associated with the change in taxability of the federal subsidy under the Patient Protection and Affordable Care Act (PPACA) and the Health Care and Education Reconciliation Act of 2010 (together with PPACA, the Acts). On December 7, 2010, the Company received notice that the FERC had accepted the filing effective December 21, 2010. As a result of the FERC acceptance, the $2.8 million of emission allowance revenue is included in the statements of income for 2010. Beginning January 1, 2011, the Company implemented the wholesale emissions allowance cost clause and revised monthly charges for the increase in annual base wholesale revenues. PSC Matters Mississippi Baseload Construction Legislation In the 2008 regular session of the Mississippi legislature, a bill was passed and signed by the Governor in May 2008 to enhance the Mississippi PSC’s authority to facilitate development and construction of base load generation in the State of Mississippi (Baseload Act). The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. The effect of this legislation on the Company cannot now be determined. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information on the application of the Baseload Act to the Kemper County IGCC facility. Performance Evaluation Plan In the May 2004 order establishing the Company’s forward-looking PEP, the Mississippi PSC ordered that the Mississippi Public Utilities Staff and the Company review the operations of the PEP in 2007. By mutual agreement, this review was deferred until 2008 and continued into 2009. In March 2009, concurrent with this review, the annual PEP evaluation filing for 2009 was suspended. In August 2009, the Mississippi Public Utilities Staff and the Company filed a joint report with the Mississippi PSC proposing several changes to the PEP. In November 2009, the Mississippi PSC approved the revised PEP, which resulted in a lower performance II-347 SoCo FOIA Response 002704 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report incentive under the PEP and therefore smaller and/or less frequent rate changes in the future. In November 2009, the Company resumed annual evaluations and filed its annual PEP filing for 2010 under the revised PEP, which resulted in a lower allowed return on investment but no rate change. On November 15, 2010, the Company filed its annual PEP filing for 2011 under the revised PEP, which indicated a rate increase of 1.936%, or $16.1 million, annually. On January 10, 2011, the Mississippi Public Utilities Staff contested the filing. Under the revised PEP, the review of the annual PEP filing must be concluded by the first billing cycle in April. The ultimate outcome of this matter cannot be determined at this time. In April 2007, the Mississippi PSC issued an order allowing the Company to defer certain reliability related maintenance costs beginning January 1, 2007 and recover them evenly over a four-year period beginning January 1, 2008. These costs related to maintenance that was needed as follow-up to emergency repairs that were made subsequent to Hurricane Katrina. At December 31, 2007, the Company had incurred and deferred the retail portion of $9.5 million of such costs. At December 31, 2010, the Company had a balance of the deferred retail portion of $2.4 million included in current assets as other regulatory assets. See Note 3 to the financial statements under “Retail Regulatory Matters – Performance Evaluation Plan” for more information on PEP. On March 15, 2010, the Company submitted its annual PEP lookback filing for 2009, which recommended no surcharge or refund. On October 26, 2010, the Company and the Mississippi Public Utilities Staff agreed and stipulated that no surcharge or refund is required. On November 2, 2010, the Mississippi PSC accepted the stipulation. On or before March 15, 2011, the Company will submit its annual PEP lookback filing for 2010. The ultimate outcome of this matter cannot be determined at this time. System Restoration Rider The Company is required to make annual SRR filings to determine the revenue requirement associated with the property damage. The purpose of the SRR is to provide for recovery of costs associated with property damage (including certain property insurance and the costs of self insurance) and to facilitate the Mississippi PSC’s review of these costs. The Mississippi PSC periodically agrees on SRR revenue levels that are developed based on historical data, expected exposure, type and amount of insurance coverage excluding insurance costs, and other relevant information. The applicable SRR rate level will be adjusted every three years, unless a significant change in circumstances occurs such that the Company and the Mississippi Public Utilities Staff or the Mississippi PSC deems that a more frequent change would be appropriate. The Company will submit annual filings setting forth SRR-related revenues, expenses, and investment for the projected filing period, as well as the true-up for the prior period. As a result of the Mississippi PSC establishing the current SRR calculation in January 2009, the December 2008 retail regulatory liability of $6.8 million was reclassified to the property damage reserve. In February 2009, the Company submitted its 2009 SRR rate filing with the Mississippi PSC, which proposed that the 2009 SRR rate level remain at zero and the Company be allowed to accrue approximately $4.0 million to the property damage reserve in 2009. In September 2009, the Mississippi PSC issued an order requiring the Company to develop SRR factors designed to reduce SRR revenue by approximately $1.5 million from November 2009 to March 2010 under the new rate. On January 29, 2010, the Company submitted its 2010 SRR rate filing with the Mississippi PSC, which allowed the Company to accrue $3.1 million to the property damage reserve in 2010. On January 31, 2011, the Company submitted its 2011 SRR rate filing with the Mississippi PSC, which proposed that the Company be allowed to accrue approximately $3.6 million to the property damage reserve in 2011. The ultimate outcome of this matter cannot be determined at this time. Environmental Compliance Overview Plan On February 14, 2011, the Company submitted its 2011 ECO Plan notice which proposed an immaterial decrease in annual revenues for the Company. In addition, the Company proposed to change the ECO Plan collection period to more appropriately match ECO revenues with ECO expenditures. The ultimate outcome of this matter cannot be determined at this time. On February 12, 2010, the Company submitted its 2010 ECO Plan notice which proposed an increase in annual revenues for the Company of approximately $3.9 million. Due to changes in ECO Plan cost projections, on August 20, 2010, the Company submitted a revised 2010 ECO Plan which reduced the requested increase in annual revenues to $1.7 million. In its 2010 ECO Plan filing, the Company proposed to change the true-up provision of the ECO Plan rate schedule to consider actual revenues collected in addition to actual costs. Hearings on the 2010 ECO Plan were held with the Mississippi PSC on October 5, 2010. On October 25, 2010, the Mississippi PSC held a public meeting to discuss the 2010 ECO Plan and issued an order approving the revised 2010 ECO Plan with the new rates effective in November 2010. The Company and the Mississippi Public Utilities Staff jointly agreed to defer the decision on the change in the true-up provision of the ECO Plan rate schedule. As a result of the change in the collection period requested in the Company’s 2011 ECO filing, the Company has decided not to pursue the change in the true-up provision. II-348 SoCo FOIA Response 002705 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report In February 2009, the Company submitted its 2009 ECO Plan notice which proposed an increase in annual revenues for the Company of approximately $1.5 million. In June 2009, the Mississippi PSC approved the ECO Plan with the new rates effective in June 2009. On July 22, 2010, the Company filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by the Company and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million. The project is scheduled for completion in the fourth quarter 2014. The Company’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through the ECO Plan. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011 with a final order expected by February 28, 2011. The ultimate outcome of this matter cannot be determined at this time. Fuel Cost Recovery The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred on November 15, 2010. The Mississippi PSC approved the retail fuel cost recovery factor on December 7, 2010, with the new rates effective in January 2011. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 5.0% of total 2010 retail revenue. At December 31, 2010, the amount of over recovered retail fuel costs included in the balance sheets was $55.2 million compared to $29.4 million at December 31, 2009. The Company also has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2011, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 3.5% of total 2010 MRA revenue. Effective February 1, 2011, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 7.0% of total 2010 MB revenue. At December 31, 2010, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $17.5 million and $4.4 million compared to $16.8 million and $2.4 million, respectively, at December 31, 2009. The Company’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this decrease to the billing factor will have no significant effect on the Company’s revenues or net income, but will decrease annual cash flow. In October 2010, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of the Company’s fuelrelated expenditures included in the retail fuel adjustment clause and energy cost management clause (ECM) for 2010. The audit is scheduled to be completed in 2011. The ultimate outcome of this matter cannot be determined at this time. A similar audit was conducted beginning in August 2009 for the years 2009 and 2008. The audit was completed in December 2009 with no audit findings. In October 2008, the Mississippi PSC opened a docket to investigate and review interest and carrying charges under the fuel adjustment clause for utilities within the State of Mississippi including the Company. In March 2009, the Mississippi PSC issued an order to apply the prime rate in calculating the carrying costs on the retail over or under recovery balances related to fuel cost recovery. In May 2009, the Company filed the carrying cost calculation methodology as part of its compliance filing. Legislation Stimulus Funding On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S. Department of Energy (DOE), formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. The Company will receive, and will match, $25.9 million under this agreement. The ultimate outcome of this matter cannot be determined at this time. Healthcare Reform On March 23, 2010, the PPACA was signed into law and, on March 30, 2010, the Acts, which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, the Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by II-349 SoCo FOIA Response 002706 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the Company’s financial statements. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and related employee benefit plan costs. Any future impact on the Company’s financial statements cannot be determined at this time. See Note 5 to the financial statements under “Current and Deferred Income Taxes” for additional information. Income Tax Matters Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $4.7 million for the Company. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. Bonus Depreciation On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which could have a significant impact on the future cash flows of the Company. The application of the bonus depreciation provisions in these acts in 2010 provided approximately $28 million in increased cash flow. The Company estimates the potential increased cash flow for 2011 to be between approximately $20 million and $25 million. Internal Revenue Code Section 199 Domestic Production Deduction The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 2010, and none is projected to be available for 2011. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. Integrated Coal Gasification Combined Cycle In January 2009, the Company filed for a Certificate of Public Convenience and Necessity (CPCN) with the Mississippi PSC to allow the acquisition, construction, and operation of the IGCC project located in Kemper County, Mississippi. The Kemper IGCC would utilize an IGCC technology with an output capacity of 582 megawatts (MWs). The estimated cost of the plant is $2.4 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2). The plant will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. In conjunction with the plant, the Company will own a lignite mine and equipment and will acquire mineral reserves located around the plant site in Kemper County. The estimated capital cost of the mine is approximately $214 million. On May 27, 2010, the Company executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations. The agreement is effective June 1, 2010 through the end of the mine reclamation. The plant, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. As part of its filing, the Company requested certain rate recovery treatment in accordance with the Baseload Act. II-350 SoCo FOIA Response 002707 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Beginning in December 2006, the Mississippi PSC approved the Company’s requested accounting treatment to defer the costs associated with the Company’s generation resource planning, evaluation, and screening activities as a regulatory asset. In April 2009, the Company received an accounting order from the Mississippi PSC directing the Company to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a CPCN and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of the Company’s prudent expenditures. In June 2009, the Mississippi PSC issued an order initiating an evaluation of the Company’s CPCN petition and established a twophase procedural schedule to evaluate the need for and the resources and cost of the new generating capacity separately. In November 2009, the Mississippi PSC issued an order that found the Company had demonstrated a need for additional capacity of approximately 304 MWs to 1,276 MWs based on an analysis of expected load forecasts, costs, and anticipated retirements. Hearings related to the appropriate resource to meet that need as well as cost recovery of that resource through application of the Baseload Act were held in February 2010. On April 29, 2010, the Mississippi PSC issued an order finding that the Company’s application to acquire, construct, and operate the plant did not satisfy the requirement of public convenience and necessity in the form that the project and the related cost recovery were originally proposed by the Company, unless the Company accepted certain conditions on the issuance of the CPCN, including a cost cap of approximately $2.4 billion. The April 2010 order also approved recovery of $46 million out of $50.5 million in prudent pre-construction costs incurred through March 2009. The remaining $4.5 million is associated with overhead costs and variable pay of Southern Company Services, Inc., which were recommended for exclusion from pre-construction costs by a consultant hired by the Mississippi Public Utilities Staff. An additional $3.5 million was incurred for costs of this type from March 2009 through May 2010. The remaining $4.5 million, as well as additional pre-construction amounts incurred during the generation screening and evaluation process through May 2010, will be reviewed and addressed in a future proceeding. On May 10, 2010, the Company filed a motion in response to the April 29, 2010 order of the Mississippi PSC relating to the Kemper IGCC, or in the alternative, for alteration or rehearing of such order. On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order (1) approved an alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the costs of the lignite mine and equipment and the carbon dioxide pipeline facilities), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity; (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in the Company’s proposal; and (3) approved financing cost recovery on construction work in progress (CWIP) balances under the Baseload Act, which provides for the accrual of AFUDC in 2010 and 2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by the Company in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, the Company filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted the Company’s motion and issued the CPCN authorizing acquisition, construction, and operation of the plant. As of May 31, 2010, construction related screening costs of $116.2 million were reclassified to CWIP while the noncapital related costs of $11.2 million and $0.6 million were classified in other regulatory assets and other deferred charges, respectively, and $1.0 million was previously expensed. Pursuant to the Mississippi PSC’s order granting the CPCN for the Kemper IGCC, the Mississippi PSC and Mississippi Public Utilities Staff has hired various consultants to assist both organizations in monitoring the construction of the plant. On June 17, 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant the CPCN for the plant with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, on July 6, 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. On July 20, 2010, the Chancery Court issued a stay of the proceeding pending the resolution of the jurisdictional issues raised in a motion filed by the Company on July 16, 2010 to confirm jurisdiction in the Mississippi Supreme Court. On October 7, 2010, the Mississippi Supreme Court denied the Company’s motion and dismissed the Sierra Club’s direct appeal. The appeal will now proceed in the Chancery Court. On II-351 SoCo FOIA Response 002708 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report December 22, 2010, the Chancery Court denied the Company’s motion to dismiss. A decision on the Sierra Club’s appeal from the Chancery court is expected in March 2011. On November 12, 2010, the Company filed a petition with the Mississippi PSC requesting an accounting order that would establish regulatory assets for certain non-capital costs related to the Kemper IGCC. In its petition, the Company outlined three categories of non-capital, plant-related costs that it proposed to defer in a regulatory asset until construction is complete and a cost recovery mechanism is established for the plant: (1) regulatory costs; (2) costs of executing non-construction contracts; and (3) other projectrelated costs not permitted to be capitalized. The Company filed an application in June 2006 with the DOE for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The DOE subsequently certified the plant, and in November 2006, the IRS allocated Internal Revenue Code Section 48A tax credits (Phase I) of $133 million to the Company. In May 2009, the Company received notification from the IRS formally certifying these tax credits. In addition, the Company filed an application in November 2009 with the DOE and in December 2009 with the IRS for certain tax credits (Phase II) available to projects using advanced coal technologies under the Energy Improvement and Extension Act of 2008. The DOE subsequently certified the Kemper IGCC, and on April 30, 2010, the IRS allocated $279 million of Phase II tax credits under Section 48A of the Internal Revenue Code to the Company. On September 30, 2010, the Company and the IRS executed the closing agreement for the Phase II tax credits. The Company has secured all environmental reviews and permits necessary to commence construction of the plant and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for these credits. The utilization of Phase I and Phase II credits are dependent upon meeting the IRS certification requirements, including an in-service date no later than May 2014 for the Phase I credits. In order to remain eligible for the Phase II tax credits, the Company plans to capture and sequester (via enhanced oil recovery) at least 65% of the carbon dioxide produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits. Through December 31, 2010, the Company received tax benefits of $21.9 million for these tax credits. In February 2008, the Company requested that the DOE transfer the remaining funds previously granted under the CCPI2 from a cancelled IGCC project of one of Southern Company’s subsidiaries that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. On August 19, 2010, the National Environmental Policy Act (NEPA) Record of Decision (ROD) by the DOE for the CCPI2 grants was noted in the Federal Register. The NEPA ROD and its accompanying final environmental impact statement were the final major hurdles necessary for the Company to receive grant funds of $245 million during the construction of the plant and $25 million during the initial operation of the plant. As of December 31, 2010, the Company has received $23.1 million and billed an additional $9.5 million associated with this grant. On July 27, 2010, the Company and South Mississippi Electric Power Association (SMEPA) entered into an Asset Purchase Agreement whereby SMEPA will purchase an undivided 17.5% interest in the plant. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. On December 2, 2010, the Company and SMEPA filed a Joint Petition with the Mississippi PSC requesting regulatory approval for SMEPA’s 17.5% ownership of the Kemper IGCC. On March 9, 2010, the Mississippi Department of Environmental Quality issued the PSD air permit modification for the plant, which modifies the original PSD air permit issued in October 2008. The Sierra Club has requested a formal evidentiary hearing regarding the issuance of the modified permit. On November 18, 2010, the U.S. Army Corps of Engineers issued the Section 404 wetlands permit for the generating facility. On December 10, 2010, the U.S. Army Corps of Engineers issued the same permit for the Liberty Fuels Lignite Mine. As of December 31, 2010, the Company had spent a total of $255.1 million on the plant, including regulatory filing costs. Of this total, $207.6 million was included in CWIP (net of $32.7 million of CCPI2 grant funds), $12.3 million was recorded in other regulatory assets, $1.5 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed. The ultimate outcome of these matters cannot be determined at this time. II-352 SoCo FOIA Response 002709 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Other Matters In February 2008, the Company received notice of termination from SMEPA of an approximately 100 MW territorial wholesale market-based contract effective March 31, 2011 which will result in a decrease in annual base revenues of approximately $12 million. In December 2008, the Company entered into a 10-year power supply agreement with SMEPA for approximately 152 MWs. This contract is effective April 1, 2011. This contract is expected to increase the Company’s annual territorial wholesale base revenues by approximately $16.1 million. In September 2010, SMEPA executed a 10-year Network Integration Transmission Service Agreement with Southern Company. Service will begin on April 1, 2011. The estimated Open Access Transmission Tariff revenue over the life of the contract is approximately $39.3 million with the Company’s share being $29.3 million. The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues. ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors. Electric Utility Regulation The Company is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company. As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements. Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The II-353 SoCo FOIA Response 002710 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following: • Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters. • Changes in existing income tax regulations or changes in IRS or state revenue department interpretations of existing regulations. • Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party. • Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. • Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA. Unbilled Revenues Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations. Plant Daniel Operating Lease As discussed in Note 7 to the financial statements under “Operating Leases – Plant Daniel Combined Cycle Generating Units,” the Company leases a 1,064-MW natural gas combined cycle facility at Plant Daniel (Facility) from Juniper Capital L.P. (Juniper). For both accounting and rate recovery purposes, this transaction is treated as an operating lease, which means that the related obligations under this agreement are not reflected in the balance sheets. See FINANCIAL CONDITION AND LIQUIDITY – “Off-Balance Sheet Financing Arrangements”herein for further information. The operating lease determination was based on assumptions and estimates related to the following: • Fair market value of the Facility at lease inception; • The Company’s incremental borrowing rate; • Timing of debt payments and the related amortization of the initial acquisition cost during the initial lease term; • Residual value of the Facility at the end of the lease term; • Estimated economic life of the Facility; and • Juniper’s status as a voting interest entity. The determination of operating lease treatment was made at the inception of the lease agreement and is not subject to change unless subsequent changes are made to the agreement. However, the Company is also required to monitor Juniper’s ongoing status as a voting interest entity. Changes in that status could require the Company to consolidate the Facility’s assets and the related debt and to record interest expense and depreciation of approximately $37 million annually, rather than annual lease expense of approximately $26 million. II-354 SoCo FOIA Response 002711 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Pension and Other Postretirement Benefits The Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. Key elements in determining the Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company’s investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company’s target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. A 25 basis point change in any significant assumption would result in a $1.3 million or less change in the total benefit expense and a $14 million or less change in projected obligations. FINANCIAL CONDITION AND LIQUIDITY Overview The Company’s financial condition remained stable at December 31, 2010. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information. The Company’s investments in the qualified pension plan remained stable in value as of December 31, 2010. In December 2010, the Company contributed $42.9 million to the qualified pension plan. Net cash provided from operating activities totaled $132.7 million in 2010 compared to $170.6 million for 2009. The $38.0 million decrease in net cash provided from operating activities was primarily due to a $42.9 million cash payment to fund the qualified pension plan, an increase in spending related to the Kemper IGCC generation construction screening costs of $19.9 million, and a decrease in cash received related to lower fuel rates effective in the first quarter 2010. These decreases in cash are partially offset by an increase in deferred income taxes of $77.4 million primarily related to a long-term service agreement (LTSA), bonus depreciation, and an increase in investment tax credits of $22.2 million related to the Kemper IGCC. Net cash provided from operating activities in 2009 increased from 2008 by $76.2 million. The increase in net cash provided from operating activities was primarily due to an increase in cash related to higher fuel rates effective in March 2009 and a decrease in deferred income taxes. Net cash provided from operating activities in 2008 decreased from 2007 by $112.2 million. The decrease in net cash provided from operating activities was primarily due to the receipt of grant proceeds of $74.3 million in June 2007 and a decrease in operating activities related to receivables in 2008 in the amount of $49.5 million. The decrease in receivables is primarily due to the change in under recovered regulatory clause revenues of $24.7 million and a $24.1 million change in affiliate receivables. Also impacting operating activities were decreases related to fossil fuel stock of $33.3 million primarily due to increases in coal and coal in-transit of $22.0 million and $15.6 million, respectively. These were offset by an increase in deferred income taxes and investment tax credits of $61.4 million. Net cash used for investing activities totaled $254.4 million for 2010 compared to $119.4 million for 2009. The $135.0 million increase was primarily due to an increase in property additions of $145.0 million primarily related to the Kemper IGCC and an increase in investment in restricted cash of $50.0 million, partially offset by capital grant proceeds of $23.7 million related to CCPI2 and the Smart Grid Investment grant and $33.8 million in construction payables. See FUTURE EARNINGS POTENTIAL – “Integrated Coal Gasification Combined Cycle” and “Legislation” herein for additional information. Net cash used for investing activities totaled $119.4 million for 2009 compared to $155.8 million for 2008. The $36.4 million decrease was primarily due to a decrease in property additions. The $55.3 million increase in net cash used for investing activities in 2008 was primarily due to a II-355 SoCo FOIA Response 002712 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report $12.1 million increase in construction payables and a $27.6 million increase due to the capital portion of Hurricane Katrina grant proceeds received in 2007. Net cash provided from financing activities totaled $217.5 million in 2010 compared to net cash used for financing activities of $8.6 million in 2009. The $226.1 million increase was primarily due to a $100.0 million increase in long-term debt at December 31, 2010, a $60.6 million increase in capital contributions from Southern Company, and a $40.0 million redemption of long-term debt in the third quarter 2009. Net cash used for financing activities totaled $8.6 million in 2009 compared to $78.9 million that was provided from financing activities in 2008. The $87.5 million decrease was primarily due to a $42.6 million decrease in notes payable and a $40 million decrease in long-term debt as a result of a March 2009 senior note redemption, when compared to the corresponding period in 2008. Net cash provided from financing activities totaled $78.9 million in 2008 compared to $105.5 million that was used in financing activities for the corresponding period in 2007. The $184.5 million increase in net cash provided from financing activities was primarily due to the $80 million long-term bank loan issued to the Company in March 2008, the $50 million senior notes issued in November 2008, and the $36 million redemption of the long-term debt to an affiliated trust in the first nine months of 2007. Notes payable increased by $57.8 million primarily due to additional borrowings from commercial paper. Significant changes in the balance sheet as of December 31, 2010 compared to 2009 include an increase in cash and cash equivalents of $95.8 million resulting from bond proceeds and a capital contribution from Southern Company in December 2010. Restricted cash increased $50.0 million primarily due to the issuance of the second series of revenue bonds. The second series revenue bonds were redeemed on February 8, 2011. Total property, plant, and equipment increased $281.2 million primarily due to the increase in CWIP related to the Kemper IGCC. Upon the Mississippi PSC issuance of the final certificate order in May 2010, the expenditures associated with the Kemper IGCC of approximately $116.2 million of regulatory assets, deferred was reclassified to CWIP during the second quarter 2010. Securities due within one year increased by $255.1 million primarily due to the reclassification of an $80.0 million long-term bank loan maturing in March 2011, a $125.0 million bank loan maturing in September 2011, and the redemption of $50.0 million second series revenue bonds on February 8, 2011. Over recovered regulatory clause liabilities increased $28.5 million primarily due to lower fuel costs and the implementation of higher fuel rates in 2009 as compared to 2010. Long-term debt decreased $31.4 million primarily due to the reclassification of an $80.0 million long-term bank loan maturing in March 2011 partially offset by obligations incurred relating to a $50.0 million issuance of revenue bonds. The change in accumulated deferred income taxes of $58.9 million was primarily due to bonus depreciation, LTSA, and funding of the qualified pension plan. Employee benefit obligations decreased by $47.8 million primarily due to the funding of the qualified pension plan. Paid in capital increased $67.2 million primarily due to the capital contribution from Southern Company. The Company’s ratio of common equity to total capitalization, excluding long-term debt due within one year, increased from 55.6% in 2009 to 59.8% at December 31, 2010. Sources of Capital Except as described below with respect to potential DOE loan guarantees, the Company plans to obtain the funds required for construction and other purposes from sources such as operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. In December 2010, the Company received $60 million in capital contributions from Southern Company. See “Capital Requirements and Contractual Obligations” herein and Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. The amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. In addition, the Company has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. The Company is in advanced due diligence with the DOE but has yet to begin discussions with the DOE regarding the terms and conditions of any loan guarantee. There can be no assurance that the DOE will issue federal loan guarantees to the Company. In addition, the Company has been awarded DOE CCPI2 grant funds of $245 million to be used for the construction of the Kemper IGCC and $25 million to be used for the initial operation of the plant. As of December 31, 2010, the Company had received $23.1 million and billed an additional $9.5 million associated with this grant. The issuance of securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the FERC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. II-356 SoCo FOIA Response 002713 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. To meet short-term cash needs and contingencies, the Company has various sources of liquidity. At December 31, 2010, the Company had approximately $160.8 million of cash and cash equivalents, $50.0 million of restricted cash, and $161.0 million of unused credit arrangements with banks. These credit arrangements provide liquidity support to the Company’s variable rate pollution control revenue bonds and commercial paper borrowings. As of December 31, 2010, the Company had $90.1 million outstanding revenue bonds requiring liquidity support. Subsequent to December 31, 2010, $50.0 million of revenue bonds were redeemed on February 8, 2011, reducing liquidity support to $40.1 million. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support. At December 31, 2010 and 2009, the Company had no commercial paper outstanding. During 2010, the maximum amount outstanding for commercial paper was $63.0 million and the average amount outstanding was $12.0 million. During 2009, the maximum amount outstanding for commercial paper was $66.7 million and the average amount outstanding was $15.9 million. The weighted average annual interest rate on commercial paper was 0.3% for 2010 and 0.3% for 2009. Financing Activities In September 2010, the Company entered into a one-year $125 million aggregate principal amount long-term floating rate bank loan that bears interest based on the one-month London Interbank Offered Rate. The proceeds were used to repay a portion of the Company’s short-term indebtedness and for general corporate purposes, including the Company’s continuous construction program. In December 2010, the Company incurred obligations in connection with the issuance of $100 million of revenue bonds in two series, each of which is due December 1, 2040. The first series of $50 million was issued with an initial fixed rate of 2.25% through January 14, 2013 and the second series of $50 million was issued with a floating rate. The proceeds from the first series bonds were used to finance the acquisition and construction of buildings and immovable equipment in connection with the Company’s construction of the Kemper IGCC facility in Kemper County, Mississippi. Proceeds from the second series were classified as restricted cash at December 31, 2010. The second series bonds were redeemed on February 8, 2011. In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm restoration costs, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Off-Balance Sheet Financing Arrangements In 2001, the Company began an initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel. In June 2003, the Company entered into a restructured lease agreement for the Facility with Juniper, as discussed in Note 7 to the financial statements under “Operating Leases – Plant Daniel Combined Cycle Generating Units.” Juniper has also entered into leases with other parties unrelated to the Company. The assets leased by the Company comprise less than 50% of Juniper’s assets. The Company does not consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. Accordingly, the lease is not reflected in the balance sheets. The initial lease term ends in 2011, and the lease includes a renewal and a purchase option based on the cost of the facility at the inception of the lease, which was approximately $370 million. The Company is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. In April 2010, the Company was required to notify the lessor, Juniper, if it intended to terminate the lease at the end of the initial term expiring in October 2011. The Company chose not to give notice to terminate the lease. The Company has the option to purchase the Plant Daniel combined cycle generating units for approximately $354 million or renew the lease for approximately $31 million annually for 10 years. The Company will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be determined at this time. The lease also provides for a residual value guarantee, approximately 73% of the acquisition cost, by the Company that is due upon termination of the lease in the event that the Company does not renew the lease or purchase the Facility and that the fair market value II-357 SoCo FOIA Response 002714 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report is less than the unamortized cost of the Facility. See Note 7 to the financial statements under “Operating Leases – Plant Daniel Combined Cycle Generating Units” for additional information. Credit Rating Risk The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At December 31, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $353 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market. On August 12, 2010, Moody’s Investors Services (Moody’s) downgraded the issuer and long-term debt ratings of the Company (senior unsecured to A2 from A1). Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of several Southern Company subsidiaries (including the Company) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of the Company to VMIG-2 from VMIG-1 and the preferred stock ratings of the Company (to Baa1 from A3). Moody’s announced that the ratings outlook for the Company is stable. On September 3, 2010, Fitch Ratings, Inc (Fitch) downgraded the issuer and long-term debt ratings of the Company (senior unsecured to A+ from AA- and issuer default rating to A from A+). Fitch also announced that it had downgraded the short-term ratings of the Company to F1 from F1+. In addition, Fitch announced that it had downgraded the pollution control revenue bond ratings of the Company to A+ from AA- and the preferred stock ratings of the Company (to A- from A). Fitch announced that the ratings outlook for the Company is stable. Market Price Risk Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques that include, but are not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. The Company does not currently hedge interest rate risk. The weighted average interest rate on $295 million of variable rate longterm debt at January 1, 2011 was 0.56%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $3.0 million at January 1, 2011. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. At December 31, 2010, exposure from these activities was not material to the Company’s financial statements. In addition, per the guidelines of the Mississippi PSC, the Company has implemented a fuel-hedging program. At December 31, 2010, exposure from these activities was not material to the Company’s financial statements. II-358 SoCo FOIA Response 002715 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the years ended December 31 were as follows: 2009 2010 Changes Changes Fair Value (in thousands) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes(a) Contracts outstanding at the end of the period, assets (liabilities), net $(41,734) 32,853 (34,889) $(43,770) $(51,985) 53,905 (43,654) $(41,734) (a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any. The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2010 was a decrease of $2.0 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 2010, the Company had a net hedge volume of 24.0 million mmBtu with a weighted average contract cost of approximately $1.92 per mmBtu above market prices, and 23.2 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.83 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the Company’s ECM clause. At December 31, 2010 and 2009, substantially all of the Company’s energy-related derivative contracts were designated as regulatory hedges and are related to the Company’s fuel hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM clause. Gains and losses on energy-related derivatives that are designated as cash flow hedges are used to hedge anticipated purchases and sales and are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented. The pre-tax gains/(losses) reclassified from other comprehensive income to revenue and fuel expense were not material for any period presented and are not expected to be material for 2011. Additionally, there was no material ineffectiveness recorded in earnings for any period presented. The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 9 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2010 were as follows: December 31, 2010 Fair Value Measurements Total Maturity Fair Value Year 1 Years 2&3 Years 4&5 (in thousands) Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period $ (43,770) $(43,770) $ (26,622) $(26,622) $ (17,148) $(17,148) $ $ - The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s, a division of The McGraw Hill Companies, Inc., or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under “Financial Instruments” and Note 10 to the financial statements. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized. II-359 SoCo FOIA Response 002716 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Capital Requirements and Contractual Obligations The construction program of the Company is currently estimated to include a base level investment of $818 million, $1.0 billion, and $878 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are expenditures related to the Kemper IGCC of $665 million, $813 million, and $616 million in 2011, 2012, and 2013, respectively. Also included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $45 million, $94 million, and $127 million for 2011, 2012, and 2013, respectively. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations are $0 for 2011, up to $18 million for 2012, and up to $55 million for 2013. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants, including unit retirement and replacement decisions, to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the FERC. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 6, 7, and 10 to the financial statements for additional information. II-360 SoCo FOIA Response 002717 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Contractual Obligations 20122013 2011 20142015 After 2015 Uncertain Timing (d) Total (in thousands) Long-term debt(a) – Principal Interest Preferred stock dividends(b) Energy-related derivative obligations(c) Unrecognized tax benefits and interest(d) Operating leases (e) Capital leases(f) Purchase commitments(g) – Capital(h) Coal Natural gas(i) Long-term service agreements(j) Pension and other postretirement benefits plans(k) Foreign currency derivatives(l) Total (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) $ 255,000 $ 23,649 1,733 27,459 38,513 1,437 818,004 324,360 180,653 13,272 50,000 44,134 3,465 18,386 18,562 633 1,899,388 145,405 246,995 27,413 275 549 66 29 $1,684,421 $2,454,959 $ - $412,695 $ 38,101 213,401 3,465 9,151 1,045 9,400 177,012 28,658 36,480 162,723 55,231 $265,787 $881,575 $ - $ 717,695 319,285 8,663 45,845 4,701 4,701 67,271 2,070 - 2,717,392 515,645 767,383 124,574 824 95 4,701 $5,291,443 All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2011, as reflected in the statements of capitalization. Long-term debt excludes capital lease amounts (shown separately). Preferred stock does not mature; therefore, amounts are provided for the next five years only. For additional information, see Notes 1 and 10 to the financial statements. The timing related to the realization of $4.7 million in unrecognized tax benefits and corresponding interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Note 5 to the financial statements for additional information. The decrease from 2011 to 2012-2013 is primarily a result of the Plant Daniel operating lease contract that is scheduled to end during 2011, at which time the Company can exercise a purchase option or renew the lease. See Note 7 to the financial statements for additional information. The capital lease of $6.4 million is being amortized over a five-year period ending in 2012. The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2010, 2009, and 2008 were $268 million, $247 million, and $260 million, respectively. The Company provides forecasted capital expenditures for a three-year period. Amounts represent current estimates of total expenditures, excluding the Company’s estimates of potential incremental investments to comply with anticipated new environmental regulations of $0 for 2011, up to $18 million for 2012, and up to $55 million for 2013. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. Estimates include the sale of 17.5% of the Kemper IGCC to SMEPA. At December 31, 2010, significant purchase commitments were outstanding in connection with the construction program. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2010. Long-term service agreements include price escalation based on inflation indices. The Company forecasts contributions to the qualified pension and other postretirement benefit plans over a three-year period. The Company does not expect to be required to make any contributions to the qualified pension plan during the next three years. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company’s corporate assets. For additional information, see Note 10 to the financial statements. II-361 SoCo FOIA Response 002718 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2010 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company’s 2010 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, customer growth, storm damage cost recovery and repairs, economic recovery, fuel cost recovery, and other rate actions, environmental regulations and expenditures, future earnings, access to sources of capital, projections for the qualified pension plan and postretirement benefit trust contributions, financing activities, start and completion of construction projects, impacts of adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: • • • • • • • • • • • • • • • • • • • • • • the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, hazardous air pollutants, including mercury, carbon, soot, particulate matter, and coal combustion byproducts and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters and EPA civil actions; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures; available sources and costs of fuels; effects of inflation; ability to control costs and avoid cost overruns during the development and construction of facilities; investment performance of the Company’s employee benefit plans; advances in technology; state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms; regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals and potential DOE loan guarantees; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers; the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings; the ability of the Company to obtain additional generating capacity at competitive prices; catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC. The Company expressly disclaims any obligation to update any forward-looking statements. II-362 SoCo FOIA Response 002719 STATEMENTS OF INCOME For the Years Ended December 31, 2010, 2009, and 2008 Mississippi Power Company 2010 Annual Report 2010 2009 2008 (in thousands) Operating Revenues: Retail revenues Wholesale revenues, non-affiliates Wholesale revenues, affiliates Other revenues Total operating revenues Operating Expenses: Fuel Purchased power, non-affiliates Purchased power, affiliates Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Interest income Interest expense, net of amounts capitalized Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Net Income Dividends on Preferred Stock Net Income After Dividends on Preferred Stock $797,912 287,917 41,614 15,625 1,143,068 $790,950 299,268 44,546 14,657 1,149,421 $785,434 353,793 100,928 16,387 1,256,542 501,830 8,426 75,230 268,063 76,891 69,810 1,000,250 142,818 519,687 8,831 83,104 246,758 70,916 64,068 993,364 156,057 586,503 27,036 99,526 260,011 71,039 65,099 1,109,214 147,328 3,795 215 (22,341) 3,738 (14,593) 128,225 46,275 81,950 1,733 $ 80,217 387 804 (22,940) 2,606 (19,143) 136,914 50,214 86,700 1,733 $ 84,967 560 1,998 (17,979) 4,135 (11,286) 136,042 48,349 87,693 1,733 $ 85,960 The accompanying notes are an integral part of these financial statements. II-363 SoCo FOIA Response 002720 STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2010, 2009, and 2008 Mississippi Power Company 2010 Annual Report 2010 2009 2008 (in thousands) Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating activities -Depreciation and amortization, total Deferred income taxes Investment tax credits received Allowance for equity funds used during construction Pension, postretirement, and other employee benefits Stock based compensation expense Tax benefit of stock options Generation construction screening costs Other, net Changes in certain current assets and liabilities --Receivables -Under recovered regulatory clause revenues -Fossil fuel stock -Materials and supplies -Prepaid income taxes -Other current assets -Other accounts payable -Accrued taxes -Accrued compensation -Over recovered regulatory clause revenues -Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Investment in restricted cash Cost of removal net of salvage Construction payables Capital grant proceeds Other investing activities Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds -Capital contributions from parent company Gross excess tax benefit of stock options Pollution control revenue bonds Senior notes issuances Other long-term debt issuances Redemptions -Pollution control revenue bonds Capital leases Senior notes Payment of preferred stock dividends Payment of common stock dividends Other financing activities Net cash provided from (used for) financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Supplemental Cash Flow Information: Cash paid during the period for -Interest (net of $2,903, $117 and $229 capitalized, respectively) Income taxes (net of refunds) Noncash transactions - accrued property additions at year-end $ 81,950 $ 86,700 $ 87,693 82,294 37,557 22,173 (3,795) (34,911) 1,186 399 (50,554) (3,803) 78,914 (39,849) (387) 7,077 886 34 (30,638) (3,263) 75,765 24,840 (560) 8,182 724 489 (26,662) (20,207) (8,185) 14,997 (879) (17,075) (4,633) (12,630) (4,268) 2,291 28,450 2,137 132,701 9,677 54,994 (41,699) (649) 1,061 2,065 (7,590) 8,800 (6,819) 48,596 2,732 170,642 (9,982) (14,450) (38,072) 297 3,243 (2,022) 3,251 2,428 (1,362) 836 94,431 (247,005) (50,000) (9,240) 33,767 23,657 (5,587) (254,408) (101,995) (9,352) (5,091) (2,971) (119,409) (153,401) (6,411) (4,084) 7,314 819 (155,763) (26,293) 16,350 4,567 117 125,000 - 3,541 934 7,900 50,000 80,000 65,215 624 225,000 (1,330) (1,733) (68,600) (1,715) 217,461 95,754 65,025 $ 160,779 $19,518 7,546 37,736 (40,000) (1,733) (68,500) (1,779) (8,621) 42,612 22,413 $ 65,025 (7,900) (1,733) (68,400) (1,774) 78,918 17,586 4,827 $ 22,413 $19,832 77,206 3,689 $15,753 23,829 8,776 The accompanying notes are an integral part of these financial statements. II-364 SoCo FOIA Response 002721 BALANCE SHEETS At December 31, 2010 and 2009 Mississippi Power Company 2010 Annual Report Assets 2009 2010 (in thousands) Current Assets: Cash and cash equivalents Restricted cash Receivables -Customer accounts receivable Unbilled revenues Other accounts and notes receivable Affiliated companies Accumulated provision for uncollectible accounts Fossil fuel stock, at average cost Materials and supplies, at average cost Other regulatory assets, current Prepaid income taxes Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Plant in service, net of depreciation Construction work in progress Total property, plant, and equipment Other Property and Investments Deferred Charges and Other Assets: Deferred charges related to income taxes Other regulatory assets, deferred Other deferred charges and assets Total deferred charges and other assets Total Assets $ 160,779 50,000 37,532 31,010 11,220 17,837 (638) 112,240 28,671 63,896 59,596 19,057 591,200 $ 65,025 36,766 27,168 11,337 13,215 (940) 127,237 27,793 53,273 32,237 12,625 405,736 2,392,477 971,559 1,420,918 274,585 1,695,503 5,900 2,316,494 950,373 1,366,121 48,219 1,414,340 7,018 18,065 132,420 33,233 183,718 $2,476,321 8,536 209,100 27,951 245,587 $2,072,681 The accompanying notes are an integral part of these financial statements. II-365 SoCo FOIA Response 002722 BALANCE SHEETS At December 31, 2010 and 2009 Mississippi Power Company 2010 Annual Report Liabilities and Stockholder's Equity 2009 2010 (in thousands) Current Liabilities: Securities due within one year Accounts payable -Affiliated Other Customer deposits Accrued taxes -Accrued income taxes Other accrued taxes Accrued interest Accrued compensation Other regulatory liabilities, current Over recovered regulatory clause liabilities Liabilities from risk management activities Other current liabilities Total current liabilities Long-Term Debt (See accompanying statements) Deferred Credits and Other Liabilities: Accumulated deferred income taxes Deferred credits related to income taxes Accumulated deferred investment tax credits Employee benefit obligations Other cost of removal obligations Other regulatory liabilities, deferred Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Redeemable Preferred Stock (See accompanying statements) Common Stockholder's Equity (See accompanying statements) Total Liabilities and Stockholder's Equity Commitments and Contingent Matters (See notes) $ 256,437 $ 1,330 51,887 59,295 12,543 49,209 38,662 11,143 4,356 51,709 5,933 16,076 6,177 77,046 27,525 20,115 589,099 462,032 10,590 49,547 5,739 13,785 7,610 48,596 19,454 21,142 276,807 493,480 281,967 11,792 33,678 113,964 111,614 58,814 43,213 655,042 1,706,173 32,780 737,368 $2,476,321 223,066 13,937 12,825 161,778 97,820 54,576 47,090 611,092 1,381,379 32,780 658,522 $2,072,681 The accompanying notes are an integral part of these financial statements. II-366 SoCo FOIA Response 002723 STATEMENTS OF CAPITALIZATION At December 31, 2010 and 2009 Mississippi Power Company 2010 Annual Report 2010 2009 (in thousands) Long-Term Debt: Long-term notes payable -6.00% due 2013 2.25% to 5.625% due 2017-2040 Adjustable rates (0.56% to 0.71% at 1/1/11) due 2011 Adjustable rates (0.44% at 1/1/11) due 2040 Total long-term notes payable Other long-term debt -Pollution control revenue bonds: 5.15% due 2028 Variable rates (0.34% to 0.51% at 1/1/11) due 2020-2028 Total other long-term debt Capitalized lease obligations Unamortized debt discount Total long-term debt (annual interest requirement -- $23.6 million) Less amount due within one year Long-term debt excluding amount due within one year Cumulative Redeemable Preferred Stock: $100 par value Authorized: 1,244,139 shares Outstanding: 334,210 shares 4.40% to 5.25% (annual dividend requirement -- $1.7 million) Common Stockholder's Equity: Common stock, without par value -Authorized: 1,130,000 shares Outstanding: 1,121,000 shares Paid-in capital Retained earnings Accumulated other comprehensive income (loss) Total common stockholder's equity Total Capitalization 50,000 330,000 205,000 50,000 635,000 42,625 40,070 82,695 2,070 (1,296) 2010 2009 (percent of total) 50,000 280,000 80,000 410,000 42,625 40,070 82,695 3,399 (1,284) 718,469 256,437 462,032 494,810 1,330 493,480 37.5% 41.6% 32,780 32,780 2.7 2.8 37,691 392,790 306,885 2 737,368 $1,232,180 37,691 325,562 295,269 658,522 $1,184,782 59.8 100.0% 55.6 100.0% The accompanying notes are an integral part of these financial statements. II-367 SoCo FOIA Response 002724 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2010, 2009, and 2008 Mississippi Power Company 2010 Annual Report Number of Common Shares Issued Common Stock Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total (in thousands) Balance at December 31, 2007 Net income after dividends on preferred stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2008 Net income after dividends on preferred stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2009 Net income after dividends on preferred stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Other Balance at December 31, 2010 1,121 1,121 1,121 1,121 $37,691 37,691 37,691 $37,691 $314,324 5,634 319,958 5,604 325,562 67,228 $392,790 $261,242 85,960 (68,400) 278,802 84,967 (68,500) 295,269 80,217 (68,600) (1) $306,885 $573 (573) 2 $ 2 $613,830 85,960 5,634 (573) (68,400) 636,451 84,967 5,604 (68,500) 658,522 80,217 67,228 2 (68,600) (1) $737,368 The accompanying notes are an integral part of these financial statements. II-368 SoCo FOIA Response 002725 STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2010, 2009, and 2008 Mississippi Power Company 2010 Annual Report 2010 2009 2008 (in thousands) Net income after dividends on preferred stock Other comprehensive income (loss): Qualifying hedges: Changes in fair value, net of tax of $1, $-, and $(355), respectively Comprehensive Income $80,217 $84,967 $85,960 2 $80,219 $84,967 (573) $85,387 The accompanying notes are an integral part of these financial statements. II-369 SoCo FOIA Response 002726 NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 2010 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Mississippi Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment, but is not the primary beneficiary. The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Mississippi Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $125.1 million, $84.0 million, and $87.1 million during 2010, 2009, and 2008, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. The Company provided no significant service to an affiliate in 2010, 2009, and 2008. The Company received storm restoration assistance from other Southern Company subsidiaries totaling $3.2 million in 2008. There was no storm assistance received in 2010 or 2009. In June 2010, the Company purchased a turbine rotor assembly part from Gulf Power for approximately $6 million. In September 2010, Southern Power purchased a turbine rotor assembly part owned by the Company for approximately $7 million. These affiliate transactions were in accordance with FERC and state PSC rules and guidelines. The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of all associated expenditures and costs. The Company reimbursed Alabama Power for the Company’s proportionate share of related expenses which totaled $11.2 million, $10.2 million, and $11.1 million in 2010, 2009, and 2008, respectively. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs. Gulf Power reimbursed the Company for Gulf Power’s proportionate share of related expenses which totaled $25.0 million, $20.9 million, and $22.8 million in 2010, 2009, and 2008, respectively. See Note 4 for additional information. II-370 SoCo FOIA Response 002727 NOTES (continued) Mississippi Power Company 2010 Annual Report The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information. Regulatory Assets and Liabilities The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2009 2010 Note (in thousands) Hurricane Katrina Retiree benefit plans Property damage Deferred income tax charges Property tax Transmission & distribution deferral Vacation pay Loss on reacquired debt Loss on redeemed preferred stock Loss on rail cars Other regulatory assets Fuel-hedging (realized and unrealized) losses Asset retirement obligations Deferred income tax credits Other cost of removal obligations Fuel-hedging (realized and unrealized) gains Generation screening costs Other liabilities Deferred income tax charges − Medicare subsidy Total assets (liabilities), net $ (143) 86,748 ( 61,171) 13,654 18,649 2,367 9,143 7,775 57 8 48,729 9,302 (13,189) (111,614) (2,067) 12,295 (81) 5,521 $ 25,983 $ (143) (a) 99,690 (b,k) (57,814) (m) 9,027 (d) 17,170 (e) 4,734 (f) 8,756 (g,k) 8,409 (h) 229 (i) 108 (h) 1,087 (c) 44,116 (j,k) 8,955 (d) (14,853) (d) (97,820) (d) (551) (j,k) 68,496 (l) (2,628) (c) (n) $ 96,968 Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) For additional information, see Note 3 under “Retail Regulatory Matters – Storm Damage Cost Recovery.” Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. Recorded and recovered as approved by the Mississippi PSC over periods not exceeding two years. Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. Amortized over a four-year period ending December 2011. Recorded as earned by employees and recovered as paid, generally within one year. Recovered over the remaining life of the original issue/lease or, if refinanced, over the life of the new issue/lease, which may range up to 50 years. Amortized over a seven-year period ending in April 2011. Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, costs are recovered through the Energy Cost Management clause (ECM). Not earning a return as offset in rate base by a corresponding asset or liability. For additional information, see Note 3 under “Integrated Coal Gasification Combined Cycle.” For additional information, see Note 1 under “Provision for Property Damage” and Note 3 under “Retail Regulatory Matters – System Restoration Rider.” Recovered and amortized over a 10-year period beginning in 2011, as approved by the Mississippi PSC for the retail portion and a five-year period for the wholesale portion, as approved by FERC. See Note 5 for additional information. II-371 SoCo FOIA Response 002728 NOTES (continued) Mississippi Power Company 2010 Annual Report In the event that a portion of the Company’s operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off or reclassify to accumulated other comprehensive income (OCI) related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Retail Regulatory Matters” and “Integrated Coal Gasification Combined Cycle” for additional information. Government Grants The Company received a grant in October 2006 from the Mississippi Development Authority (MDA) for $276.4 million, primarily for storm damage cost recovery. In 2007, the Company received $109.3 million of storm restoration bond proceeds under the state bond program of which $25.2 million was for retail storm restoration costs, $60.0 million was to increase the Company’s retail property damage reserve, and $24.1 million was to cover the retail portion of construction of a new storm operations center. In 2008, the Company received grant payments in the amount of $7.3 million and anticipates the receipt of approximately $3.2 million in 2011. The grant proceeds do not represent a future obligation of the Company. The portion of any grants received related to retail storm recovery was applied to the retail regulatory asset that was established as restoration costs were incurred. The portion related to wholesale storm recovery was recorded either as a reduction to operations and maintenance expense or as a reduction to total property, plant, and equipment depending on the restoration work performed and the appropriate allocations of cost of service. In August 2010, the Department of Energy (DOE), through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper integrated coal gasification combined cycle (IGCC) through the Clean Coal Power Initiative Round 2 (CCPI2) funds. As of December 31, 2010, the Company had collected $23.1 million and billed an additional $9.5 million, for a total of $32.6 million, which is reflected in the Company’s financial statements as a reduction to the Kemper IGCC capital costs. Revenues Energy and other revenues are recognized as services are provided. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company’s retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery factor annually. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel hedging programs as approved by the Mississippi PSC. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information. II-372 SoCo FOIA Response 002729 NOTES (continued) Mississippi Power Company 2010 Annual Report Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction for projects over $1 million where recovery of construction work in progress is not allowed in rates. The Company’s property, plant, and equipment consisted of the following at December 31: 2010 2009 (in thousands) Generation Transmission Distribution General Total plant in service $ 990,151 464,716 765,578 172,032 $2,392,477 $ 963,145 449,452 748,066 155,831 $2,316,494 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense except for the cost of maintenance of coal cars and a portion of the railway track maintenance costs, which are charged to fuel stock and recovered through the Company’s fuel clause. Depreciation and Amortization Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.4% in 2010, 3.3% in 2009, and 3.3% in 2008. Depreciation studies are conducted periodically to update the composite rates. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities. In September 2009, the Company filed a depreciation study as of December 31, 2008, with the Mississippi PSC and the FERC. The FERC accepted this study in October 2009. On April 20, 2010, the Mississippi PSC issued an order approving the depreciation rates effective January 1, 2010. This change did not have a material impact on the financial statements. In April 2007, the Mississippi PSC issued an order allowing the Company to defer certain reliability related maintenance costs beginning January 1, 2007 and recover them evenly over a four-year period beginning January 1, 2008. These costs related to maintenance that was needed as follow-up to emergency repairs that were made subsequent to Hurricane Katrina. At December 31, 2007, the Company had incurred and deferred the retail portion of $9.5 million of such costs. At December 31, 2010, the Company had a balance of the deferred retail portion of $2.4 million in other regulatory assets. Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. The Company has retirement obligations related to various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. II-373 SoCo FOIA Response 002730 NOTES (continued) Mississippi Power Company 2010 Annual Report Details of the asset retirement obligations included in the balance sheets are as follows: 2009 2010 (in thousands) Balance at beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions Balance at end of year $17,431 (1) 155 1,016 $18,601 $17,977 378 (1,892) 1,049 (81) $17,431 Allowance for Funds Used During Construction (AFUDC) In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 7.33%, 7.92%, and 6.9% for the years ended December 31, 2010, 2009, and 2008, respectively. The AFUDC rate is applied to construction work in progress based on jurisdictional regulatory recovery mechanisms. AFUDC, net of income taxes as a percentage of net income after dividends on preferred stock was 6.97%, 0.5%, and 0.82% for 2010 2009, and 2008, respectively. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the asset and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. Provision for Property Damage The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. The Company made no discretionary retail accruals in 2008 as a result of the Hurricane Katrina-related financing order issued by the Mississippi PSC which ordered the Company to cease all accruals to the retail property damage reserve until a new reserve cap was established. However, in the same financing order, the Mississippi PSC approved the replenishment of the retail property damage reserve with $60 million that was funded with a portion of the proceeds of bonds issued by the Mississippi Development Bank on behalf of the State of Mississippi and reported as liabilities by the State of Mississippi. In January 2009, the Mississippi PSC approved the System Restoration Rider (SRR) stipulation between the Company and the Mississippi Public Utilities Staff. In accordance with the stipulation, every three years the Mississippi PSC, Mississippi Public Utilities Staff, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the Mississippi Public Utilities Staff or the Mississippi PSC deem the change appropriate. Each year the Company will set rates to collect the approved SRR revenues. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In 2010 and 2009, the Company made retail accruals of $3.1 million II-374 SoCo FOIA Response 002731 NOTES (continued) Mississippi Power Company 2010 Annual Report and $3.7 million, respectively, per the annual SRR rate filings. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. See Note 3 under “Retail Regulatory Matters − Storm Damage Cost Recovery” and “Retail Regulatory Matters − System Restoration Rider” for additional information. The Company accrued $0.3 million annually in 2010 and 2009, and $0.2 million in 2008 for the wholesale jurisdiction. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Restricted Cash In December 2010, the Company incurred obligations relating to the issuance of $50 million of revenue bonds. The proceeds of this issuance are presented as restricted cash on the balance sheet at December 31, 2010. These bonds were redeemed on February 8, 2011. See Note 6 under “Revenue Bonds” for additional information. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Mississippi PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 9 for additional information. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from the fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Mississippi PSC approved fuel hedging program as discussed below. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 10 for additional information. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2010. The Mississippi PSC has approved the Company’s request to implement an ECM which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company’s jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC. The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk. II-375 SoCo FOIA Response 002732 NOTES (continued) Mississippi Power Company 2010 Annual Report Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. Variable Interest Entities Effective January 1, 2010, the Company adopted new accounting guidance which modified the consolidation model and expanded disclosures related to variable interest entities (VIE). The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the Company consolidating any VIEs that were not already consolidated under previous guidance, nor deconsolidating any VIEs. The Company is required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC (Liberty Fuels) in conjunction with the construction of the Kemper IGCC. Liberty Fuels qualifies as a VIE for which the Company is the primary beneficiary. As of December 31, 2010, Liberty Fuels did not have a material impact on the financial position and results of operations of the Company. 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2010, the Company contributed approximately $43 million to the qualified pension plan. No contributions to the qualified pension plan are expected for the year ending December 31, 2011. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the FERC. For the year ending December 31, 2011, other postretirement trust contributions are expected to total approximately $0.3 million. Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2007 for the 2008 plan year using a discount rate of 6.30% and an annual salary increase of 3.75%. Discount rate: Pension plans Other postretirement benefit plans Annual salary increase Long-term return on plan assets: Pension plans Other postretirement benefit plans 2010 2009 2008 5.51% 5.39 3.84 5.92% 5.83 4.18 6.75% 6.75 3.75 8.75 7.65 8.50 7.62 8.50 7.85 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio. II-376 SoCo FOIA Response 002733 NOTES (continued) Mississippi Power Company 2010 Annual Report An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate of 8.25% for 2011, decreasing gradually to 5.00% through the year 2019 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2010 as follows: 1 Percent 1Percent Increase Decrease (in thousands) Benefit obligation Service and interest costs $ 5,786 310 $ 4,930 264 Pension Plans The total accumulated benefit obligation for the pension plans was $307 million in 2010 and $289 million in 2009. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2009 2010 (in thousands) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Plan amendments Actuarial loss (gain) Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability $309,179 8,300 17,916 (12,206) 48 7,078 330,315 $266,879 6,792 17,577 (11,965) 29,896 309,179 218,015 33,780 44,109 (12,206) 283,698 $(46,617) 198,510 30,088 1,382 (11,965) 218,015 $(91,164) At December 31, 2010, the projected benefit obligations for the qualified and non-qualified pension plans were $305 million and $25 million, respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s pension plan consist of the following: 2009 2010 (in thousands) Other regulatory assets, deferred Other current liabilities Employee benefit obligations $78,130 (1,516) (45,101) $85,357 (1,484) (89,680) Presented below are the amounts included in regulatory assets at December 31, 2010 and 2009 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2011. 2010 2009 Estimated Amortization in 2011 (in thousands) Prior service cost Net (gain) loss Other regulatory assets, deferred $ 7,879 70,251 $ 78,130 $ 9,222 76,135 $ 85,357 $ 1,309 1,114 II-377 SoCo FOIA Response 002734 NOTES (continued) Mississippi Power Company 2010 Annual Report The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2010 and 2009 are presented in the following table: Regulatory Assets (in thousands) $ 66,602 20,872 - Balance at December 31, 2008 Net loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net (gain) Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 (1,578) (539) (2,117) 18,755 $ 85,357 (5,250) 48 (1,391) (634) (2,025) (7,227) $ 78,130 Components of net periodic pension cost were as follows: 2009 2010 2008 (in thousands) Service cost Interest cost Expected return on plan assets Recognized net (gain) loss Net amortization Net periodic pension cost $ 8,300 17,916 (21,451) 634 1,391 $ 6,790 $ 6,792 17,577 (21,065) 539 1,578 $ 5,421 $ 6,846 15,802 (20,611) 481 1,668 $ 4,186 Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2010, estimated benefit payments were as follows: Benefit Payments (in thousands) 2011 2012 2013 2014 2015 2016 to 2020 $13,753 14,847 15,763 16,753 17,691 105,208 II-378 SoCo FOIA Response 002735 NOTES (continued) Mississippi Power Company 2010 Annual Report Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows: 2009 2010 (in thousands) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial gain Plan amendments Retiree drug subsidy Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability $ 83,774 1,305 4,763 (4,245) (2,511) (1,824) 426 81,688 $ 84,733 1,328 5,535 (4,041) (1,550) (2,592) 361 83,774 20,292 2,297 2,185 (3,819) 20,955 $(60,733) 18,623 2,902 2,447 (3,680) 20,292 $(63,482) Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s other postretirement benefit plans consist of the following: 2009 2010 (in thousands) Other regulatory assets, deferred Employee benefit obligations $ 8,618 (60,733) $ 14,332 (63,482) Presented below are the amounts included in regulatory assets at December 31, 2010 and 2009 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2011. 2010 2009 Estimated Amortization in 2011 (in thousands) Prior service cost Net (gain) loss Transition obligation Other regulatory assets, deferred $ (2,873) 11,092 399 $ 8,618 $ (1,107) 14,811 628 $ 14,332 $ (188) 234 228 II-379 SoCo FOIA Response 002736 NOTES (continued) Mississippi Power Company 2010 Annual Report The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2010 and 2009 are presented in the following table: Regulatory Assets (in thousands) $ 20,491 (2,648) (2,592) Balance at December 31, 2008 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2009 Net gain Change in prior service costs/transition obligation Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2010 (307) (51) (561) (919) (6,159) $ 14,332 (3,316) (1,824) (228) 57 (403) (574) (5,714) $ 8,618 Components of the other postretirement benefit plans’ net periodic cost were as follows: 2010 2009 2008 (in thousands) Service cost Interest cost Expected return on plan assets Net amortization Net postretirement cost $ 1,305 4,763 (1,826) 574 $ 4,816 $ 1,328 5,535 (1,783) 919 $ 5,999 $ 1,396 5,199 (1,805) 1,066 $ 5,856 The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2010, 2009, and 2008 by approximately $1.6 million, $1.7 million, and $1.8 million, respectively, and is expected to have a similar impact on future expenses. Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows: Benefit Payments Subsidy Receipts Total (in thousands) 2011 2012 2013 2014 2015 2016 to 2020 $ 4,745 5,098 5,544 5,861 6,214 33,655 $ (489) (556) (614) (686) (751) (3,735) $ 4,256 4,542 4,930 5,175 5,463 29,920 Benefit Plan Assets Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities II-380 SoCo FOIA Response 002737 NOTES (continued) Mississippi Power Company 2010 Annual Report over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The composition of the Company’s pension plan and other postretirement benefit plan assets as of December 31, 2010 and 2009, along with the targeted mix of assets for each plan, is presented below: Pension plan assets: Domestic equity International equity Fixed income Special situations Real estate investments Private equity Total Target 2010 2009 29% 28 15 3 15 10 100% 29% 27 22 13 9 100% 33% 29 15 13 10 100% Other postretirement benefit plan assets: Domestic equity 23% International equity 22 Fixed income 32 Special situations 3 Real estate investments 12 Private equity 8 Total 100% 23% 22 38 10 7 100% 26% 22 34 10 8 100% The investment strategy for plan assets related to the Company’s qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is longterm in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. An actively-managed mix of growth stocks and value stocks with both developed and emerging market exposure. • Fixed income. A mix of domestic and international bonds. • Special situations. Though currently unfunded, established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private-market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. II-381 SoCo FOIA Response 002738 NOTES (continued) Mississippi Power Company 2010 Annual Report • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2010 and 2009. The fair values presented are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund. The fair values of pension plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $ 52,553 53,006 $21,208 18,377 85 7,645 $113,289 (28) $113,261 $ 28 - $ 73,789 71,383 12,629 10,250 24,663 8,353 19,849 $115,329 85 27,976 26,475 $54,564 12,629 10,250 24,748 8,353 19,934 35,621 26,475 $283,182 $115,329 $54,564 (28) $283,154 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. II-382 SoCo FOIA Response 002739 NOTES (continued) Mississippi Power Company 2010 Annual Report As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $ 43,279 55,948 $17,897 5,575 $ - $ 61,176 61,523 108 6,747 $106,082 16,118 4,382 10,803 390 13,211 $68,376 21,195 21,498 $42,693 16,118 4,382 10,803 390 13,319 27,942 21,498 $217,151 (172) $105,910 (43) $68,333 $42,693 (215) $216,936 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 are as follows: 2010 Real Estate Investments Private Equity 2009 Real Estate Investments Private Equity (in thousands) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $21,195 $21,498 $32,700 $19,092 3,959 747 4,706 2,075 $27,976 4,313 747 5,060 (83) $26,475 (9,492) (2,516) (12,008) 503 $21,195 1,322 387 1,709 697 $21,498 II-383 SoCo FOIA Response 002740 NOTES (continued) Mississippi Power Company 2010 Annual Report The fair values of other postretirement benefit plan assets as of December 31, 2010 and 2009 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. As of December 31, 2010: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total $3,049 3,076 $ 1,230 1,068 $ 1 - $ 4,280 4,144 4 442 $6,571 4,632 596 1,431 485 1,408 $10,850 1,625 1,538 $3,164 4,632 596 1,431 485 1,412 2,067 1,538 $20,585 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. II-384 SoCo FOIA Response 002741 NOTES (continued) Mississippi Power Company 2010 Annual Report As of December 31, 2009: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Special situations Real estate investments Private equity Total Liabilities: Derivatives Total $ 3,011 3,893 $ 1,245 387 $ - $ 4,256 4,280 8 468 $ 7,380 5,155 304 751 27 1,295 $ 9,164 1,475 1,497 $ 2,972 5,155 304 751 27 1,303 1,943 1,497 $19,516 (12) $ 7,368 (3) $ 9,161 $ 2,972 (15) $19,501 *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is welldiversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2010 and 2009 are as follows: 2010 Real Estate Investments Private Equity 2009 Real Estate Investments Private Equity (in thousands) Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Transfers into/out of Level 3 Ending balance $1,475 $1,497 $2,287 $1,335 29 29 121 $1,625 47 47 (6) $1,538 (676) (171) (847) 35 $ 1,475 87 28 115 47 $1,497 Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2010, 2009, and 2008 were $3.8 million, $3.9 million, and $3.7 million, respectively. II-385 SoCo FOIA Response 002742 NOTES (continued) Mississippi Power Company 2010 Annual Report 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. Environmental Matters New Source Review Actions In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. These actions were filed concurrently with the issuance of notices of violation to the Company with respect to the Company’s Plant Watson. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. In early 2000, the EPA filed a motion to amend its complaint to add the Company as a defendant based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against Alabama Power is ongoing. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to the facility co-owned by the Company. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law II-386 SoCo FOIA Response 002743 NOTES (continued) Mississippi Power Company 2010 Annual Report public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Remediation The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through regulatory mechanisms. In 2003, the Texas Commission on Environmental Quality (TCEQ) designated the Company as a potentially responsible party at a site in Texas. The site was owned by an electric transformer company that handled the Company’s transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with the Company and several other utilities to investigate and remediate the site. Amounts expensed during 2008, 2009, and 2010 related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on the Company will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by the Company are expected to be recovered through the Environmental Compliance Overview (ECO) Plan. II-387 SoCo FOIA Response 002744 NOTES (continued) Mississippi Power Company 2010 Annual Report The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, the Company does not believe that additional liabilities, if any, at these sites would be material to the financial statements. FERC Matters In August 2008, the Company filed a request with the FERC for a revised wholesale electric tariff and revised rates. Prior to making this filing, the Company reached a settlement with all of its customers who take service under the tariff. This settlement agreement was filed with the FERC as part of the request. The settlement agreement provided for an increase in annual base wholesale revenues in the amount of $5.8 million, effective January 1, 2009. In addition, the settlement agreement allows the Company to increase its annual accrual for the wholesale portion of property damage to $303,000 per year, to defer any property damage costs prudently incurred in excess of the wholesale property damage reserve balance, and to defer the wholesale portion of the generation screening and evaluation costs associated with the Kemper IGCC. The settlement agreement also provided that the Company will not seek a change in wholesale full-requirements rates before November 1, 2010, except for changes associated with the fuel adjustment clause and the ECM, changes associated with property damages that exceed the amount in the wholesale property damage reserve, and changes associated with costs and expenses associated with environmental requirements affecting fossil fuel generating facilities. In October 2008, the Company received notice that the FERC had accepted the filing effective November 1, 2008, and the revised monthly charges were applied beginning January 1, 2009. As result of the order, the Company reclassified $9.3 million of previously expensed generation screening and evaluation costs to a regulatory asset. See “Integrated Coal Gasification Combined Cycle” herein for additional information. In October 2010, the Company filed with the FERC a request for revised wholesale electric tariff and rates. Prior to making this filing, the Company reached a settlement with all of its customers who take service under the tariff. This settlement agreement was filed with the FERC as part of the request. The settlement agreement provided for an increase in annual base wholesale revenues in the amount of $4.1 million, effective January 1, 2011. In addition, the settlement agreement allows the Company to implement an emissions allowance cost clause, effective January 1, 2011. The emissions allowance cost clause contains an over and under recovery provision similar to the fuel recovery clause and is projected to collect $6.9 million in 2011. The settlement agreement also provides for collection of $2.8 million of 2010 emissions allowance expense for the period of September 1, 2010 through December 31, 2010 and allows the Company to defer the wholesale portion of the income tax expense associated with the change in taxability of the federal subsidy under the Patient Protection and Affordable Care Act (PPACA) and the Health Care and Education Reconciliation Act of 2010 (together with PPACA, the Acts). On December 7, 2010, the Company received notice that the FERC had accepted the filing effective December 21, 2010. As a result of the FERC acceptance, the $2.8 million of emission allowance revenue is included in the statements of income for 2010. Beginning January 1, 2011, the Company implemented the wholesale emissions allowance cost clause and revised monthly charges for the increase in annual base wholesale revenues. Right of Way Litigation Southern Company and certain of its subsidiaries, including the Company, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of the Company believes that it has complied with applicable laws and that the plaintiffs’ claims are without merit. To date, the Company has entered into agreements with plaintiffs in approximately 95% of the actions pending against the Company to clarify the Company’s easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and the related cases have been dismissed. These agreements have not resulted in any material effects on the Company’s financial statements. In addition, in late 2001, certain subsidiaries of Southern Company, including the Company, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network, Inc., a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of II-388 SoCo FOIA Response 002745 NOTES (continued) Mississippi Power Company 2010 Annual Report jurisdiction. On August 24, 2010, the defendants filed a motion to dismiss the suit for lack of prosecution. In January 2011, the court indicated that it intended to deny the defendant’s motion to dismiss the claim; however, no written order denying the motion has been entered into the record. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined. Retail Regulatory Matters Performance Evaluation Plan The Company’s retail base rates are set under the Performance Evaluation Plan (PEP), a rate plan approved by the Mississippi PSC. PEP was designed with the objective that PEP would reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. PEP is a mechanism for rate adjustments based on three indicators: price, customer satisfaction, and service reliability. In May 2004, the Mississippi PSC approved the Company’s requested changes to PEP, including the use of a forward-looking test year, with appropriate oversight; annual, rather than semi-annual, filings; and certain changes to the performance indicator mechanisms. Rate changes are limited to 4% of retail revenues annually under the revised PEP. PEP will remain in effect until the Mississippi PSC modifies, suspends, or terminates the plan. In the May 2004 order, the Mississippi PSC ordered that the Mississippi Public Utilities Staff and the Company review the operations of the PEP in 2007. By mutual agreement, this review was deferred until 2008 and continued into 2009. In March 2009, concurrent with this review, the annual PEP evaluation filing for 2009 was suspended. In August 2009, the Mississippi Public Utilities Staff and the Company filed a joint report with the Mississippi PSC proposing several changes to the PEP. In November 2009, the Mississippi PSC approved the revised PEP, which resulted in a lower performance incentive under the PEP and therefore smaller and/or less frequent rate changes in the future. In November 2009, the Company resumed annual evaluations and filed its annual PEP filing for 2010 under the revised PEP, which resulted in a lower allowed return on investment but no rate change. On November 15, 2010, the Company filed its annual PEP filing for 2011 under the revised PEP, which indicated a rate increase of 1.936%, or $16.1 million annually. On January 10, 2011, the Mississippi Public Utilities Staff contested the filing. Under the revised PEP, the review of the annual PEP filing must be concluded by the first billing cycle in April 2011. The ultimate outcome of this matter cannot be determined at this time. In April 2007, the Mississippi PSC issued an order allowing the Company to defer certain reliability-related maintenance costs beginning January 1, 2007 and recover them evenly over a four-year period beginning January 1, 2008. These costs related to maintenance that was needed as follow-up to emergency repairs that were made subsequent to Hurricane Katrina. At December 31, 2007, the Company had incurred and deferred the retail portion of $9.5 million of such costs. At December 31, 2010, the Company had a balance of the deferred retail portion of $2.4 million included in current assets as other regulatory assets. In December 2007, the Company submitted its annual PEP filing for 2008, which resulted in a rate increase of 1.983% or $15.5 million annually, effective January 2008. In December 2007, the Company received an order from the Mississippi PSC requiring it to defer $1.4 million associated with the retail portion of certain tax credits and adjustments related to permanent differences pertaining to its 2006 income tax returns filed in September 2007. These tax differences were recorded in a regulatory liability included in the current portion of other regulatory liabilities and were amortized ratably over the 12-month period beginning January 2008. The amortization of $1.4 million is included in income taxes on the statement of income for 2008. On March 15, 2010, the Company submitted its annual PEP lookback filing for 2009, which recommended no surcharge or refund. On October 26, 2010, the Company and the Mississippi Public Utilities Staff agreed and stipulated that no surcharge or refund is required. On November 2, 2010, the Mississippi PSC accepted the stipulation. On or before March 15, 2011, the Company will submit its annual PEP lookback filing for 2010. The ultimate outcome of this matter cannot now be determined. System Restoration Rider The Company is required to make annual SRR filings to determine the revenue requirement associated with the property damage. The purpose of the SRR is to provide for recovery of costs associated with property damage (including certain property insurance and the costs of self insurance) and to facilitate the Mississippi PSC’s review of these costs. The Mississippi PSC periodically agrees on SRR revenue levels that are developed based on historical data, expected exposure, type and amount of insurance coverage excluding II-389 SoCo FOIA Response 002746 NOTES (continued) Mississippi Power Company 2010 Annual Report insurance costs, and other relevant information. The applicable SRR rate level will be adjusted every three years, unless a significant change in circumstances occurs such that the Company and the Mississippi Public Utilities Staff or the Mississippi PSC deems that a more frequent change would be appropriate. The Company will submit annual filings setting forth SRR-related revenues, expenses, and investment for the projected filing period, as well as the true-up for the prior period. As a result of the Mississippi PSC establishing the current SRR calculation in January 2009, the December 2008 retail regulatory liability of $6.8 million was reclassified to the property damage reserve. In February 2009, the Company submitted its 2009 SRR rate filing with the Mississippi PSC, which proposed that the 2009 SRR rate level remain at zero and the Company be allowed to accrue approximately $4.0 million to the property damage reserve in 2009. In September 2009, the Mississippi PSC issued an order requiring the Company to develop SRR factors designed to reduce SRR revenue by approximately $1.5 million from November 2009 to March 2010 under the new rate. On January 29, 2010, the Company submitted its 2010 SRR rate filing with the Mississippi PSC, which allowed the Company to accrue $3.1 million to the property damage reserve in 2010. On January 31, 2011, the Company submitted its 2011 SRR rate filing with the Mississippi PSC, which proposed that the Company be allowed to accrue approximately $3.6 million to the property damage reserve in 2011. The ultimate outcome of this matter cannot be determined at this time. Environmental Compliance Overview Plan On February 14, 2011, the Company submitted its 2011 ECO Plan notice which proposed an immaterial decrease in annual revenues for the Company. In addition, the Company proposed to change the ECO Plan collection period to more appropriately match ECO revenues with ECO expenditures. The ultimate outcome of this matter cannot be determined at this time. On February 12, 2010, the Company submitted its 2010 ECO Plan notice which proposed an increase in annual revenues for the Company of approximately $3.9 million. Due to changes in ECO Plan cost projections, on August 20, 2010, the Company submitted a revised 2010 ECO Plan which reduced the requested increase in annual revenues to $1.7 million. In its 2010 ECO Plan filing, the Company proposed to change the true-up provision of the ECO Plan rate schedule to consider actual revenues collected in addition to actual costs. Hearings on the 2010 ECO Plan were held with the Mississippi PSC on October 5, 2010. On October 25, 2010, the Mississippi PSC held a public meeting to discuss the 2010 ECO Plan and issued an order approving the revised 2010 ECO Plan with the new rates effective in November 2010. The Company and the Mississippi Public Utilities Staff jointly agreed to defer the decision on the change in the true-up provision of the ECO Plan rate schedule. As a result of the change in the collection period requested in the Company’s 2011 ECO filing, the Company has decided not to pursue the change in the true-up provision. In February 2009, the Company submitted its 2009 ECO Plan notice which proposed an increase in annual revenues for the Company of approximately $1.5 million. In June 2009, the Mississippi PSC approved the ECO Plan with the new rates effective June 2009. In February 2008, the Company filed with the Mississippi PSC its annual ECO Plan evaluation for 2008. After the filing of the ECO Plan evaluation in February 2008, the regulations addressing mercury emissions were altered by a decision issued by the U.S. Court of Appeals for the District of Columbia Circuit in February 2008. In April 2008, the Company filed with the Mississippi PSC a supplemental ECO Plan evaluation in which the projects included in the ECO Plan evaluation in February 2008 being undertaken primarily for mercury control were removed. In this supplemental ECO Plan filing, the Company requested a 15 cent per 1,000 kilowatt-hour decrease for retail residential customers. The Mississippi PSC approved the supplemental ECO Plan evaluation in June 2008, with the new rates effective in June 2008. On July 22, 2010, the Company filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by the Company and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million. The project is scheduled for completion in the fourth quarter 2014. The Company’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through the ECO Plan. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011 with a final order expected by February 28, 2011. The ultimate outcome of this matter cannot be determined at this time. Fuel Cost Recovery The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred on November 15, 2010. The Mississippi PSC approved the retail fuel cost recovery factor on December 7, 2010, with the new rates effective in January 2011. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 5.0% of total 2010 retail revenue. At December 31, 2010, the amount of over recovered retail fuel cost included in the balance sheets was $55.2 million compared to $29.4 million at II-390 SoCo FOIA Response 002747 NOTES (continued) Mississippi Power Company 2010 Annual Report December 31, 2009. The Company also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2011, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 3.5% of total 2010 MRA revenue. Effective February 1, 2011, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 7.0% of total 2010 MB revenue. At December 31, 2010, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $17.5 million and $4.4 million compared to $16.8 million and $2.4 million, respectively, at December 31, 2009. The Company’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this decrease to the billing factor will have no significant effect on the Company’s revenues or net income, but will decrease annual cash flow. In October 2010, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of the Company’s fuelrelated expenditures included in the retail fuel adjustment clause and ECM for 2010. The audit is scheduled to be completed in 2011. The ultimate outcome of this matter cannot be determined at this time. A similar audit was conducted beginning in August 2009 for the years 2009 and 2008. The audit was completed in December 2009 with no audit findings. In October 2008, the Mississippi PSC opened a docket to investigate and review interest and carrying charges under the fuel adjustment clause for utilities within the State of Mississippi including the Company. In March 2009, the Mississippi PSC issued an order to apply the prime rate in calculating the carrying costs on the retail over or under recovery balances related to fuel cost recovery. In May 2009, the Company filed the carrying cost calculation methodology as part of its compliance filing. Storm Damage Cost Recovery In August 2005, Hurricane Katrina hit the Gulf Coast of the U.S. and caused significant damage within the Company’s service area. The estimated total storm restoration costs relating to Hurricane Katrina through December 31, 2007 of $302.4 million, which was net of expected insurance proceeds of approximately $77 million, without offset for the property damage reserve of $3.0 million, was affirmed by the Mississippi PSC in June 2006, and the Company was ordered to establish a regulatory asset for the retail portion. The Mississippi PSC issued an order directing the Company to file an application with the MDA for a Community Development Block Grant (CDBG). In October 2006, the Company received from the MDA a CDBG in the amount of $276.4 million, which was allocated to both the retail and wholesale jurisdictions. In the same month, the Mississippi PSC issued a financing order that authorized the issuance of system restoration bonds for the remaining $25.2 million of the retail portion of storm recovery costs not covered by the CDBG. These funds were received in June 2007. The Company affirmed the $302.4 million total storm costs incurred as of December 31, 2007. In March 2009, the Company filed with the Mississippi PSC its final accounting of the restoration cost relating to Hurricane Katrina and the storm operations center. The final net retail receivable of approximately $3.2 million is expected to be recovered in 2011. Income Tax Matters Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $4.7 million for the Company. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. Integrated Coal Gasification Combined Cycle In January 2009, the Company filed for a Certificate of Public Convenience and Necessity (CPCN) with the Mississippi PSC to allow the acquisition, construction, and operation of the IGCC project located in Kemper County, Mississippi. The Kemper IGCC would utilize an IGCC technology with an output capacity of 582 megawatts (MWs). The estimated cost of the plant is $2.4 billion, net of $245 million of grants awarded to the project by the DOE under the CCPI2. The plant will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. In conjunction with the plant, the Company will own a lignite mine and equipment and will acquire mineral reserves located around the plant site in Kemper County. The estimated capital cost of the mine is approximately $214 million. On May 27, 2010, the Company executed a 40-year management fee contract with II-391 SoCo FOIA Response 002748 NOTES (continued) Mississippi Power Company 2010 Annual Report Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations. The agreement is effective June 1, 2010 through the end of the mine reclamation. The plant, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. As part of its filing, the Company requested certain rate recovery treatment in accordance with the State of Mississippi Baseload Act of 2008 (Baseload Act). Beginning in December 2006, the Mississippi PSC approved the Company’s requested accounting treatment to defer the costs associated with the Company’s generation resource planning, evaluation, and screening activities as a regulatory asset. In April 2009, the Company received an accounting order from the Mississippi PSC directing the Company to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a CPCN and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of the Company’s prudent expenditures. In June 2009, the Mississippi PSC issued an order initiating an evaluation of the Company’s CPCN petition and established a twophase procedural schedule to evaluate the need for and the resources and cost of the new generating capacity separately. In November 2009, the Mississippi PSC issued an order that found the Company had demonstrated a need for additional capacity of approximately 304 MWs to 1,276 MWs based on an analysis of expected load forecasts, costs, and anticipated retirements. Hearings related to the appropriate resource to meet that need as well as cost recovery of that resource through application of the Baseload Act were held in February 2010. On April 29, 2010, the Mississippi PSC issued an order finding that the Company’s application to acquire, construct, and operate the plant did not satisfy the requirement of public convenience and necessity in the form that the project and the related cost recovery were originally proposed by the Company, unless the Company accepted certain conditions on the issuance of the CPCN, including a cost cap of approximately $2.4 billion. The April 2010 order also approved recovery of $46 million out of $50.5 million in prudent pre-construction costs incurred through March 2009. The remaining $4.5 million is associated with overhead costs and variable pay of SCS, which were recommended for exclusion from pre-construction costs by a consultant hired by the Mississippi Public Utilities Staff. An additional $3.5 million was incurred for costs of this type from March 2009 through May 2010. The remaining $4.5 million, as well as additional pre-construction amounts incurred during the generation screening and evaluation process through May 2010, will be reviewed and addressed in a future proceeding. On May 10, 2010, the Company filed a motion in response to the April 29, 2010 order of the Mississippi PSC relating to the Kemper IGCC, or in the alternative, for alteration or rehearing of such order. On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order (1) approved an alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the costs of the lignite mine and equipment and the carbon dioxide pipeline facilities), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity; (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in the Company’s proposal; and (3) approved financing cost recovery on construction work in progress (CWIP) balances under the Baseload Act, which provides for the accrual of AFUDC in 2010 and 2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by the Company in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, the Company filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted the Company’s motion and issued the CPCN authorizing acquisition, construction, and operation of the plant. As of May 31, 2010, construction related screening costs of $116.2 million were reclassified to CWIP while the noncapital related costs of $11.2 million and $0.6 million were classified in other regulatory assets and other deferred charges, respectively, and $1.0 million was previously expensed. Pursuant to the Mississippi PSC’s order granting the CPCN for the Kemper IGCC, the Mississippi PSC and Mississippi Public Utilities Staff has hired various consultants to assist both organizations in monitoring the construction of the plant. On June 17, 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant the CPCN for the plant with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, II-392 SoCo FOIA Response 002749 NOTES (continued) Mississippi Power Company 2010 Annual Report on July 6, 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. On July 20, 2010, the Chancery Court issued a stay of the proceeding pending the resolution of the jurisdictional issues raised in a motion filed by the Company on July 16, 2010 to confirm jurisdiction in the Mississippi Supreme Court. On October 7, 2010, the Mississippi Supreme Court denied the Company’s motion and dismissed the Sierra Club’s direct appeal. The appeal will now proceed in the Chancery Court. On December 22, 2010, the Chancery Court denied the Company’s motion to dismiss. A decision on the Sierra Club’s appeal from the Chancery court is expected in March 2011. On November 12, 2010, the Company filed a petition with the Mississippi PSC requesting an accounting order that would establish regulatory assets for certain non-capital costs related to the Kemper IGCC. In its petition, the Company outlined three categories of non-capital, plant-related costs that it proposed to defer in a regulatory asset until construction is complete and a cost recovery mechanism is established for the plant: (1) regulatory costs; (2) costs of executing non-construction contracts; and (3) other projectrelated costs not permitted to be capitalized. The Company filed an application in June 2006 with the U.S. Department of Energy (DOE) for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The DOE subsequently certified the plant, and in November 2006, the IRS allocated Internal Revenue Code Section 48A tax credits (Phase I) of $133 million to the Company. In May 2009, the Company received notification from the IRS formally certifying these tax credits. In addition, the Company filed an application in November 2009 with the DOE and in December 2009 with the IRS for certain tax credits (Phase II) available to projects using advanced coal technologies under the Energy Improvement and Extension Act of 2008. The DOE subsequently certified the Kemper IGCC, and on April 30, 2010, the IRS allocated $279 million of Phase II tax credits under Section 48A of the Internal Revenue Code to the Company. On September 30, 2010, the Company and the IRS executed the closing agreement for the Phase II tax credits. The Company has secured all environmental reviews and permits necessary to commence construction of the plant and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for these credits. The utilization of Phase I and Phase II credits are dependent upon meeting the IRS certification requirements, including an in-service date no later than May 2014 for the Phase I credits. In order to remain eligible for the Phase II tax credits, the Company plans to capture and sequester (via enhanced oil recovery) at least 65% of the carbon dioxide produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits. Through December 31, 2010, the Company received tax benefits of $21.9 million for these tax credits. In February 2008, the Company requested that the DOE transfer the remaining funds previously granted under the CCPI2 from a cancelled IGCC project of one of Southern Company’s subsidiaries that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. On August 19, 2010, the National Environmental Policy Act (NEPA) Record of Decision (ROD) by the DOE for the CCPI2 grants was noted in the Federal Register. The NEPA ROD and its accompanying final environmental impact statement were the final major hurdles necessary for the Company to receive grant funds of $245 million during the construction of the plant and $25 million during the initial operation of the plant. As of December 31, 2010, the Company has received $23.1 million and billed an additional $9.5 million associated with this grant. In April 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more. The Company expects the Kemper IGCC, including the gasification portion, to be a qualifying project under the law. On July 27, 2010, the Company and South Mississippi Electric Power Association (SMEPA) entered into an Asset Purchase Agreement whereby SMEPA will purchase an undivided 17.5% interest in the plant. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. On December 2, 2010, the Company and SMEPA filed a Joint Petition with the Mississippi PSC requesting regulatory approval for SMEPA’s 17.5% ownership of the Kemper IGCC. On March 9, 2010, the Mississippi Department of Environmental Quality issued the PSD air permit modification for the plant, which modifies the original PSD air permit issued in October 2008. The Sierra Club has requested a formal evidentiary hearing regarding the issuance of the modified permit. As of December 31, 2010, the Company had spent a total of $255.1 million on the plant, including regulatory filing costs. Of this total, $207.6 million was included in CWIP (net of $32.7 million of CCPI2 grant funds), $12.3 million was recorded in other regulatory assets, $1.5 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed. II-393 SoCo FOIA Response 002750 NOTES (continued) Mississippi Power Company 2010 Annual Report The ultimate outcome of these matters cannot be determined at this time. 4. JOINT OWNERSHIP AGREEMENTS The Company and Alabama Power own, as tenants in common, Units 1 and 2 (total capacity of 500 MWs) at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power. Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 (total capacity of 1,000 MWs) at Plant Daniel, which is located in Mississippi and operated by the Company. At December 31, 2010, the Company’s percentage ownership and investment in these jointly owned facilities were as follows: Generating Plant Percent Ownership Gross Investment Accumulated Depreciation (in thousands) Greene County Units 1 and 2 Daniel Units 1 and 2 40% $ 87,326 $ 45,101 50% $280,885 $ 140,029 The Company’s proportionate share of plant operating expenses is included in the statements of income and the Company is responsible for providing its own financing. 5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. Current and Deferred Income Taxes Details of the income tax provisions are as follows: 2010 2009 2008 (in thousands) Federal – Current Deferred State – Current Deferred Total $ 5,399 35,367 40,766 $77,619 (32,980) 44,639 $20,834 22,054 42,888 3,319 2,190 5,509 $46,275 12,444 (6,869) 5,575 $50,214 2,675 2,786 5,461 $48,349 II-394 SoCo FOIA Response 002751 NOTES (continued) Mississippi Power Company 2010 Annual Report The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2010 2009 (in thousands) Deferred tax liabilities – Accelerated depreciation Basis differences Energy cost management clause under recovered Regulatory assets associated with asset retirement obligations Regulatory assets associated with employee benefit obligations Regulatory assets associated with the Kemper IGCC OCI Other Total $321,918 $279,683 1,499 19,730 10,216 25,232 6,876 7,338 35,021 43,535 4,640 1 21,679 40,416 421,049 396,735 Deferred tax assets – Federal effect of state deferred taxes Fuel clause over recovered Other property basis differences Pension and other benefits Property insurance Unbilled fuel Long-term service agreement Asset retirement obligations Other Total Total deferred tax liabilities, net Portion included in (accrued) prepaid income taxes, net Accumulated deferred income taxes 8,979 11,323 39,779 44,009 7,367 3,013 53,213 64,553 23,880 22,365 16,703 12,194 4,740 21,317 6,876 7,338 21,614 18,246 181,603 205,906 239,446 190,829 42,521 32,237 $281,967 $223,066 - At December 31, 2010, the tax-related regulatory assets and liabilities were $19.2 million and $13.2 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest. In 2010, the Company deferred $5.5 million as a regulatory asset related to the impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (together, the Acts). The Acts eliminated the deductibility of health care costs that are covered by federal Medicare subsidy payments. The Company will amortize the regulatory asset to income tax expense over 10 years beginning January 1, 2011, as approved by the Mississippi PSC for the retail portion and over five years for the wholesale portion, as approved by the FERC. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits. In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $1.3 million, $1.2 million, and $1.2 million for 2010, 2009, and 2008, respectively. At December 31, 2010, all investment tax credits available to reduce federal income taxes payable had been utilized. In 2010, the Company began recognizing investment tax credits associated with the construction expenditures related to the Kemper IGCC. At December 31, 2010, the Company had $22.2 million in unamortized investment tax credits associated with this facility. On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance II-395 SoCo FOIA Response 002752 NOTES (continued) Mississippi Power Company 2010 Annual Report Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013). The application of the bonus depreciation provisions in these acts in 2010 significantly increased deferred tax liabilities related to accelerated depreciation. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Federal statutory rate State income tax, net of federal deduction Non-deductible book depreciation Medicare subsidy Amortization of permanent tax items(a) AFUDC-equity Other Effective income tax rate 2010 35.0% 2.8 0.3 (0.2) 0.0 (1.0) (0.8) 36.1% 2009 35.0% 2.7 0.3 (0.4) 0.0 (0.1) (0.8) 36.7% 2008 35.0% 2.6 0.3 (0.5) (0.7) 0.0 (1.2) 35.5% (a) Amortization of Regulatory Liability Tax Credits. See Note 3 under “Retail Regulatory Matters - Performance Evaluation Plan.” The Company’s 2010 effective tax rate decreased from 2009 primarily due to the increase in AFUDC equity related to increased construction expenditures. The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions there was no domestic production deduction available to the Company for 2010. Unrecognized Tax Benefits For 2010, the total amount of unrecognized tax benefits increased by $1.3 million, resulting in a balance of $4.3 million as of December 31, 2010. Changes during the year in unrecognized tax benefits were as follows: 2010 2009 2008 (in thousands) Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions from prior periods Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year $3,026 868 611 (217) $4,288 $1,772 1,309 (55) $3,026 $ 935 653 265 (81) $1,772 The tax positions increase from current periods relate primarily to miscellaneous uncertain tax positions. The tax positions increase from prior periods relates primarily to the tax accounting method change for repairs and other miscellaneous uncertain tax positions. See Note 3 under “Income Tax Matters” for additional information. II-396 SoCo FOIA Response 002753 NOTES (continued) Mississippi Power Company 2010 Annual Report The impact on the Company’s effective tax rate, if recognized, is as follows: 2010 2009 2008 (in thousands) Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits $3,058 1,230 $4,288 $3,026 $3,026 $1,772 $1,772 The tax positions impacting the effective tax rate primarily relate to the production activities deduction tax position and other miscellaneous uncertain tax positions. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note 3 under “Income Tax Matters” for additional information. Accrued interest for unrecognized tax benefits was as follows: 2010 2009 2008 (in thousands) Interest accrued at beginning of year Interest reclassified due to settlements Interest accrued during the year Balance at end of year $230 183 $413 $203 27 $230 $106 (17) 114 $203 The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible conclusion or settlement of state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has audited and closed all tax returns prior to 2007. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006. 6. FINANCING Bank Term Loans In September 2010, the Company entered into a one-year $125 million aggregate principal amount long-term floating rate bank loan that bears interest based on the one-month London Interbank Offered Rate (LIBOR). The proceeds of this loan were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes, including the Company’s continuous construction program. In 2008, the Company borrowed $80 million under a three-year term loan agreement that matures in March 2011. The proceeds were used for general corporate purposes, including the Company’s continuous construction program. Senior Notes In March 2009, the Company issued $125 million of Series 2009A 5.55% Senior Notes due March 1, 2019. Proceeds were used to repay at maturity the Company’s $40.0 million aggregate principal amount of Series F Floating Rate Senior Notes due March 9, 2009, to repay a portion of its short-term indebtedness and for general corporate purposes, including the Company’s continuous construction program. The Company had a total of $330 million of senior notes outstanding at December 31, 2010 and 2009. Revenue Bonds In December 2010, the Company incurred obligations relating to the issuance of $100 million of revenue bonds in two series, each of which is due December 1, 2040. The first series of $50 million was issued with an initial fixed rate of 2.25% through January 14, 2013 and the second series of $50 million was issued with a floating rate. Proceeds from the second series bonds were classified as restricted cash at December 31, 2010 and these bonds were redeemed on February 8, 2011. The proceeds from the first series bonds II-397 SoCo FOIA Response 002754 NOTES (continued) Mississippi Power Company 2010 Annual Report were used to finance the acquisition and construction of buildings and immovable equipment in connection with the Company’s construction of the Kemper IGCC. Securities Due Within One Year At December 31, 2010 and 2009, the Company had scheduled maturities of capital leases due within one year of $1.4 million and $1.3 million, respectively. At December 31, 2010, the Company had planned the redemption of the second series revenue bonds issued in December 2010 in the amount of $50.0 million for February 2011. In addition, a long term bank loan of $80 million matures in March 2011 and a $125.0 million term loan matures in September 2011. Maturities through 2013 applicable to total long-term debt are as follows: $256.4 million in 2011; $0.6 million in 2012; and $50.0 million in 2013. There are no scheduled maturities in 2014 and 2015. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2010 and 2009 was $82.7 million. In September 2008, the Company was required to purchase a total of approximately $7.9 million of variable rate pollution control revenue bonds that were tendered by investors. In December 2008, the bonds were successfully remarketed. On the statement of cash flow for 2008, the $7.9 million is presented as proceeds and redemptions. Outstanding Classes of Capital Stock The Company currently has preferred stock (including depositary shares which represent one-fourth of a share of preferred stock) and common stock authorized and outstanding. The preferred stock of the Company contains a feature that allows the holders to elect a majority of the Company’s board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, this preferred stock is presented as “Cumulative Redeemable Preferred Stock” in a manner consistent with temporary equity under applicable accounting standards. The Company’s preferred stock and depositary preferred stock, without preference between classes, rank senior to the Company’s common stock with respect to payment of dividends and voluntary or involuntary dissolution. Certain series of the preferred stock and depositary preferred stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the stock. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Bank Credit Arrangements At the beginning of 2011, the Company had total unused committed credit agreements with banks of $161 million, all of which expire in 2011. Approximately $41 million of the facilities contain two-year term loan options and $65 million contain one-year term loan options. The Company expects to renew its credit facilities, as needed, prior to expiration. In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. Commitment fees average less than 3/8 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. The credit arrangements contain covenants that limit the ratio of indebtedness to capitalization (each as defined in the arrangements) to 65%. For purposes of these definitions, indebtedness excludes long-term debt payable to affiliated trusts and, in certain cases, other hybrid securities. In addition, the credit arrangements contain cross default provisions that would trigger an event of default if the Company defaulted on other indebtedness above a specified threshold. At December 31, 2010, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowing. II-398 SoCo FOIA Response 002755 NOTES (continued) Mississippi Power Company 2010 Annual Report This $161 million in unused credit arrangements provides required liquidity support to the Company’s borrowings through a commercial paper program. At December 31, 2010 and 2009, the Company had no commercial paper outstanding. The credit arrangements also provide support to the Company’s variable rate tax-exempt bonds totaling $90.1 million. Subsequent to December 31, 2010, $50.0 million of revenue bonds were redeemed on February 8, 2011, reducing liquidity support to $40.1 million. During 2010, the maximum amount outstanding for commercial paper was $63.0 million and the average amount outstanding was $12.0 million. During 2009, the maximum amount outstanding for commercial paper was $66.7 million and the average amount outstanding was $15.9 million. The weighted average annual interest rate on commercial paper was 0.3% for 2010 and 0.3% for 2009. 7. COMMITMENTS Construction Program The construction program of the Company is currently estimated to include a base level investment of $818 million in 2011, $1.0 billion in 2012, and $878 million in 2013. Included in these estimated amounts are expenditures related to the Kemper IGCC of $665 million, $813 million, and $616 million in 2011, 2012, and 2013, respectively, which are net of SMEPA’s 17.5% expected ownership share of the Kemper IGCC of approximately $354 million and $91 million in 2012 and 2013, respectively. Also included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $45 million, $94 million, and $127 million for 2011, 2012, and 2013, respectively. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2010, significant purchase commitments were outstanding in connection with the ongoing construction program. Capital improvements to generating, transmission, and distribution facilities, including those to meet environmental standards, will continue. See Note 3 under “Integrated Coal Gasification Combined Cycle” for additional information. Long-Term Service Agreements The Company has entered into a long-term service agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the leased combined cycle units at Plant Daniel. The LTSA provides that GE will cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in the LTSA. In general, the LTSA is in effect through two major inspection cycles of the units. Scheduled payments to GE under the LTSA, which are subject to price escalation, are made monthly based on estimated operating hours of the units and are recognized as expense based on actual hours of operation. The Company has recognized $12.6 million, $13.3 million, and $9.4 million for 2010, 2009, and 2008, respectively, which is included in other operations and maintenance expense in the statements of income. Remaining payments to GE under the LTSA are currently estimated to total $106.7 million over the next nine years. However, the LTSA contains various cancellation provisions at the option of the Company. The Company also has entered into a LTSA with Alstom Power, Inc. for the purpose of securing maintenance support for its Chevron Unit 5 combustion turbine plant. In summary, the LTSA stipulates that Alstom Power, Inc. will perform all planned maintenance on the covered equipment, which includes the cost of all labor and materials. Alstom Power, Inc is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the LTSA. In general, this LTSA is in effect through two major inspection cycles. Scheduled payments to Alstom Power, Inc., which are subject to price escalation, are made at various intervals based on actual operating hours of the unit. Payments to Alstom Power, Inc. under the LTSA are currently estimated to total $17.9 million over the remaining term of the LTSA, which is approximately seven years. However, the LTSA contains various cancellation provisions at the option of the Company. Payments made to Alstom Power, Inc. under the LTSA prior to the performance of any planned maintenance are recorded as a prepayment in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed. After the LTSA expires, the Company expects to replace it with a new contract with similar terms. II-399 SoCo FOIA Response 002756 NOTES (continued) Mississippi Power Company 2010 Annual Report Fuel Commitments To supply a portion of the fuel requirements of the generating plants, the Company has entered into various long-term commitments for the procurement of fossil fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emissions allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2010. Total estimated minimum long-term commitments at December 31, 2010 were as follows: Commitments Natural Gas Coal (in thousands) 2011 2012 2013 2014 2015 2016 and thereafter Total $180,653 138,530 108,465 82,367 94,645 162,723 $767,383 $324,360 122,400 23,005 8,440 960 36,480 $515,645 Coal commitments include a minimum annual management fee of $38.1 million beginning in 2014 from the executed 40-year management contract with Liberty Fuels, LLC related to the Kemper IGCC. Additional commitments for fuel will be required to supply the Company’s future needs. SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. Operating Leases Plant Daniel Combined Cycle Generating Units In 2001, the Company began the initial 10-year term of the lease agreement for a 1,064-MW natural gas combined cycle generating facility built at Plant Daniel (Facility). The lease arrangement provided a lower cost alternative to its cost based rate regulated customers than a traditional rate base asset. See Note 3 under “Retail Regulatory Matters – Performance Evaluation Plan” for a description of the Company’s formulary rate plan. In 2003, the Facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with the Company. Simultaneously, Juniper entered into a restructured lease agreement with the Company. Juniper has also entered into leases with other parties unrelated to the Company. The assets leased by the Company comprise less than 50% of Juniper’s assets. The Company is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease agreement is treated as an operating lease for accounting purposes as well as for both retail and wholesale rate recovery purposes. For income tax purposes, the Company retains tax ownership. The initial lease term ends in 2011 and the lease includes a purchase and renewal option based on the cost of the Facility at the inception of the lease, which was $370 million. The Company is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. In April 2010, the Company was required to notify the lessor, Juniper, if it intended to terminate the lease at the end of the initial term expiring in October 2011. The Company chose not to give notice to terminate the lease. The Company has the option to purchase the Plant Daniel combined cycle generating units for approximately $354 million or renew the lease for approximately $31 million annually for 10 years. The Company will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. If the lease is renewed, the agreement calls for the Company to amortize an additional 17% of the initial completion cost over the renewal period. Upon termination of the II-400 SoCo FOIA Response 002757 NOTES (continued) Mississippi Power Company 2010 Annual Report lease, at the Company’s option, it may either exercise its purchase option or the Facility can be sold to a third party. If the Company does not exercise either its purchase option or its renewal option, the Company could lose its rights to some or all of the 1,064 MWs of capacity at that time. The ultimate outcome of this matter cannot be determined at this time. The lease provides for a residual value guarantee, approximately 73% of the acquisition cost, by the Company that is due upon termination of the lease in the event that the Company does not renew the lease or purchase the Facility and that the fair market value is less than the unamortized cost of the Facility. A liability of approximately $2 million, $3 million, and $5 million for the fair market value of this residual value guarantee is included in the balance sheets at December 31, 2010, 2009, and 2008, respectively. Lease expenses were $26 million, $26 million, and $26 million in 2010, 2009, and 2008, respectively. The Company estimates that its annual amount of future minimum operating lease payments under this arrangement, exclusive of any payment related to the residual value guarantee or purchase or renewal options, as of December 31, 2010, are as follows: Minimum Lease Payments (in thousands) 2011 2012 and thereafter Total commitments $28,291 $28,291 Other Operating Leases The Company and Gulf Power have jointly entered into operating lease agreements for the use of 745 aluminum railcars. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. The Company also has multiple operating lease agreements for the use of additional railcars that do not contain a purchase option. All of these leases are for the transport of coal to Plant Daniel. The Company’s share (50%) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $3.5 million in 2010, $4.0 million in 2009, and $4.0 million in 2008. The Company’s annual railcar lease payments for 2011 through 2015 will average approximately $1.1 million and after 2015, lease payments total in aggregate approximately $1.0 million. In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson and operating leases for barges and tow/shift boats for the transport of coal at Plant Watson. The Company’s share (50% at Plant Daniel and 100% at Plant Watson) of the leases for fuel handling was charged to fuel handling expense in the amount of $0.7 million in 2010 and $0.6 million in 2009. The Company’s annual lease payments for 2011 through 2014 will average approximately $0.2 million for fuel handling equipment. The Company charged to fuel stock and recovered through fuel cost recovery the barge transportation leases in the amount of $8.4 million in 2010 and $8.4 million in 2009 related to barges and tow/shift boats. The Company’s annual lease payments for 2011 through 2014 with respect to these barge transportation leases will average approximately $7.9 million. 8. STOCK COMPENSATION Stock Option Plan Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2010, there were 281 current and former employees of the Company participating in the stock option plan and there were 10 million shares of Southern Company common stock remaining available for awards under this plan and the Performance Share Plan discussed below. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting. The estimated fair values of stock options granted in 2010, 2009, and 2008 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to II-401 SoCo FOIA Response 002758 NOTES (continued) Mississippi Power Company 2010 Annual Report employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Dividend yield Weighted average grant-date fair value 2010 17.4% 5.0 2.4% 5.6% $ 2.23 2009 15.6% 5.0 1.9% 5.4% $ 1.80 2008 13.1% 5.0 2.8% 4.5% $2.37 The Company’s activity in the stock option plan for 2010 is summarized below: Outstanding at December 31, 2009 Granted Exercised Cancelled Outstanding at December 31, 2010 Shares Subject Weighted Average to Option Exercise Price 1,856,656 $31.83 361,352 31.19 (371,799) 28.86 (2,839) 32.38 1,843,370 $32.30 Exercisable at December 31, 2010 1,161,617 $32.60 The number of stock options vested, and expected to vest in the future, as of December 31, 2010 was not significantly different from the number of stock options outstanding at December 31, 2010 as stated above. As of December 31, 2010, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and five years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $10.9 million and $6.5 million, respectively. As of December 31, 2010, there was $0.2 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months. For the years ended December 31, 2010, 2009, and 2008, total compensation cost for stock option awards recognized in income was $0.8 million, $0.9 million, and $0.7 million, respectively, with the related tax benefit also recognized in income of $0.3 million, $0.3 million, and $0.3 million, respectively. The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. The total intrinsic value of options exercised during the years ended December 31, 2010, 2009, and 2008 was $2.7 million, $0.4 million, and $3.7 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1.0 million, $0.2 million, and $1.4 million for the years ended December 31, 2010, 2009, and 2008, respectively. Performance Share Plan In 2010, Southern Company implemented the performance share program under its omnibus incentive compensation plan, which provides performance share award units to a large segment of employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company’s total shareholder return (TSR) over the three-year performance period which measures Southern Company’s relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the II-402 SoCo FOIA Response 002759 NOTES (continued) Mississippi Power Company 2010 Annual Report performance period based on Southern Company’s actual TSR and may range from 0% to 200% of the original target performance share amount. The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company’s stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. Expected volatility used in the model of 20.7% was based on historical volatility of Southern Company’s stock over a period equal to the performance period. The risk-free rate of 1.4% was based on the U.S. Treasury yield curve in effect at the time of the grant that covers the performance period of the award units. The annualized dividend rate at the time of the grant was $1.75. During 2010, 39,883 performance share units were granted to the Company’s employees with a weighted-average grant date fair value of $30.13. During 2010, 2,902 performance share units were forfeited by the Company’s employees resulting in 36,981 unvested units outstanding at December 31, 2010. For the year ended December 31, 2010, the Company’s total compensation cost for performance share units recognized in income was $0.3 million, with the related tax benefit also recognized in income of $0.1 million. As of December 31, 2010, there was $0.7 million of total unrecognized compensation cost related to performance share award units that will be recognized over the next two years. 9. FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.    Level 1 consists of observable market data in an active market for identical assets or liabilities. Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: Fair Value Measurements Using At December 31, 2010: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Assets: Energy-related derivatives Foreign currency derivatives Cash equivalents Total Liabilities: Energy-related derivatives Foreign currency derivatives Total $ 160,200 $160,200 $ - $ $2,075 3,419 $5,494 $45,845 95 $45,940 $ $ $ $ - $ 2,075 3,419 160,200 $165,694 - $ 45,845 95 $ 45,940 II-403 SoCo FOIA Response 002760 NOTES (continued) Mississippi Power Company 2010 Annual Report Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR. Foreign currency derivatives are also standard over-the-counter financial products valued using the market approach using inputs from observable market sources. See Note 10 for additional information on how these derivatives are used. As of December 31, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: As of December 31, 2010: Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period None Daily Not applicable (in thousands) Cash equivalents: Money market funds $160,200 The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the Securities and Exchange Commission and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis, up to the full amount of the Company’s investment in the money market funds. As of December 31, 2010 and 2009, other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in thousands) Long-term debt: 2010 2009 $716,399 $491,410 $738,211 $497,933 The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). 10. DERIVATIVES The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Mississippi PSC, through the use of financial derivative contracts, and recently has started using significantly more financial options which is expected to continue to mitigate price volatility. To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. II-404 SoCo FOIA Response 002761 NOTES (continued) Mississippi Power Company 2010 Annual Report Energy-related derivative contracts are accounted for in one of three methods:    Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2010, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Net Purchased mmBtu* Gas Longest Hedge Date Longest Non-Hedge Date 2015 - (in millions) 24.04 * mmBtu - million British thermal units For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending December 31, 2011 are immaterial. Foreign Currency Derivatives The Company may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives’ fair value gains or losses and the hedged items’ fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. II-405 SoCo FOIA Response 002762 NOTES (continued) Mississippi Power Company 2010 Annual Report At December 31, 2010, the following foreign currency derivatives were outstanding: Notional Amount Forward Rate Hedge Maturity Date Fair Value Gain (Loss) December 31, 2010 (in millions) (in thousands) Fair value hedges of firm commitments EUR 41.1 1.256 Dollars per Euro* Various through July 2012 $3,324 * Weighted Average Derivative Financial Statement Presentation and Amounts At December 31, 2010 and 2009, the fair value of energy-related derivatives and foreign currency derivatives was reflected in the balance sheets as follows: Derivative Category Asset Derivatives Balance Sheet Location 2010 Liability Derivatives Balance Sheet Location 2010 2009 (in thousands) Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets Other deferred charges and assets Total derivatives designated as hedging instruments for regulatory purposes Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Foreign currency derivatives: Other current assets Other current assets Other deferred charges and assets Total derivatives designated as hedging instruments in cash flow and fair value hedges Derivatives not designated as hedging instruments Energy-related derivatives: Total $ 830 $446 1,238 105 $2,068 $551 $ $ 3 Other current assets - 2,403 - 1,016 - $3,422 $ Liabilities from risk management activities Other deferred credits and liabilities Liabilities from risk management activities Liabilities from risk management activities Other deferred credits and liabilities - 4 $ 12 $5,494 $563 $ 2009 (in thousands) $27,459 $19,454 18,386 22,843 $45,845 $42,297 $ $ Liabilities from risk management activities $ $ - - 66 - 29 - 95 - $45,940 $ - $ - $42,297 All derivative instruments are measured at fair value. See Note 9 for additional information. II-406 SoCo FOIA Response 002763 NOTES (continued) Mississippi Power Company 2010 Annual Report At December 31, 2010 and 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: Unrealized Losses Balance Sheet Location 2010 Derivative Category 2009 Unrealized Gains Balance Sheet Location 2010 (in thousands) Energy-related derivatives: Other regulatory assets, current Other regulatory assets, deferred Total energy-related derivative gains (losses) $(27,459) $(19,454) (18,386) (22,843) $(45,845) $(42,297) 2009 (in thousands) Other regulatory liabilities, current Other regulatory liabilities, deferred $ 830 $446 1,238 105 $2,068 $551 For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of energy-related derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Hedging Relationships Derivative Category Gain (Loss) Recognized in OCI on Derivative (Effective Portion) 2009 2008 2010 Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount 2009 2008 Statements of Income Location 2010 (in thousands) Energy-related derivatives $3 $ - (in thousands) $(929) Fuel $- $- $- There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material. For the twelve months ended December 31, 2010, the pre-tax gains from foreign currency derivatives designated as fair value hedging instruments on the Company’s statements of income were $3.3 million. These amounts were offset with changes in the fair value of the purchase commitment related to equipment purchases. Therefore, there is no impact on the Company’s statements of income. Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2010, the fair value of derivative liabilities with contingent features was $4.9 million. At December 31, 2010, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-riskrelated contingent features, at a rating below BBB- and/or Baa3, is $40.0 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. II-407 SoCo FOIA Response 002764 NOTES (continued) Mississippi Power Company 2010 Annual Report 11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial data for 2010 and 2009 are as follows: Operating Revenues Operating Income March 2010 June 2010 September 2010 December 2010 $283,638 276,821 327,083 255,526 $30,026 29,535 55,033 28,224 $15,253 15,219 33,593 16,152 March 2009 June 2009 September 2009 December 2009 $268,723 286,681 330,680 263,337 $31,418 40,899 63,075 20,665 $17,971 21,933 34,898 10,165 Quarter Ended Net Income After Dividends on Preferred Stock (in thousands) The Company’s business is influenced by seasonal weather conditions. II-408 SoCo FOIA Response 002765 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 Mississippi Power Company 2010 Annual Report Operating Revenues (in thousands) Net Income after Dividends on Preferred Stock (in thousands) Cash Dividends on Common Stock (in thousands) Return on Average Common Equity (percent) Total Assets (in thousands) Gross Property Additions (in thousands) Capitalization (in thousands): Common stock equity Redeemable preferred stock Long-term debt Total (excluding amounts due within one year) Capitalization Ratios (percent): Common stock equity Redeemable preferred stock Long-term debt Total (excluding amounts due within one year) Customers (year-end): Residential Commercial Industrial Other Total Employees (year-end) 2010 $1,143,068 2009 $1,149,421 2008 $1,256,542 2007 $1,113,744 2006 $1,009,237 $80,217 $84,967 $85,960 $84,031 $82,010 $68,600 11.49 $2,476,321 $340,162 $68,500 13.12 $2,072,681 $95,573 $68,400 13.75 $1,952,695 $139,250 $67,300 13.96 $1,727,665 $114,927 $65,200 14.25 $1,708,376 $127,290 $737,368 32,780 462,032 $1,232,180 $658,522 32,780 493,480 $1,184,782 $636,451 32,780 370,460 $1,039,691 $613,830 32,780 281,963 $928,573 $589,820 32,780 278,635 $901,235 59.8 2.7 37.5 100.0 55.6 2.8 41.6 100.0 61.2 3.2 35.6 100.0 66.1 3.5 30.4 100.0 65.4 3.6 31.0 100.0 151,944 33,121 504 187 185,756 1,280 151,375 33,147 513 180 185,215 1,285 152,280 33,589 518 183 186,570 1,317 150,601 33,507 514 181 184,803 1,299 147,643 32,958 507 177 181,285 1,270 II-409 SoCo FOIA Response 002766 SELECTED FINANCIAL AND OPERATING DATA 2006-2010 (continued) Mississippi Power Company 2010 Annual Report Operating Revenues (in thousands): Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total revenues from sales of electricity Other revenues Total Kilowatt-Hour Sales (in thousands): Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total Average Revenue Per Kilowatt-Hour (cents): Residential Commercial Industrial Total retail Wholesale Total sales Residential Average Annual Kilowatt-Hour Use Per Customer Residential Average Annual Revenue Per Customer Plant Nameplate Capacity Ratings (year-end) (megawatts) Maximum Peak-Hour Demand (megawatts): Winter Summer Annual Load Factor (percent) Plant Availability Fossil-Steam (percent) Source of Energy Supply (percent): Coal Oil and gas Purchased power From non-affiliates From affiliates Total 2010 2009 2008 2007 2006 $256,994 266,406 267,588 6,924 797,912 287,917 41,614 1,127,443 15,625 $1,143,068 $245,357 269,423 269,128 7,041 790,949 299,268 44,546 1,134,763 14,658 $1,149,421 $248,693 271,452 258,328 6,961 785,434 353,793 100,928 1,240,155 16,387 $1,256,542 $230,819 247,539 242,436 6,420 727,214 323,120 46,169 1,096,503 17,241 $1,113,744 $214,472 215,451 211,451 5,812 647,186 268,850 76,439 992,475 16,762 $1,009,237 2,296,157 2,921,942 4,466,560 38,570 9,723,229 4,284,289 774,375 14,781,893 2,091,825 2,851,248 4,329,924 38,855 9,311,852 4,651,606 839,372 14,802,830 2,121,389 2,856,744 4,187,101 38,886 9,204,120 5,016,655 1,487,083 15,707,858 2,134,883 2,876,247 4,317,656 38,764 9,367,550 5,185,772 1,026,546 15,579,868 2,118,106 2,675,945 4,142,947 36,959 8,973,957 4,624,092 1,679,831 15,277,880 11.19 9.12 5.99 8.21 6.51 7.63 11.73 9.45 6.22 8.49 6.26 7.67 11.72 9.50 6.17 8.53 6.99 7.90 10.81 8.61 5.61 7.76 5.94 7.04 10.13 8.05 5.10 7.21 5.48 6.50 15,130 13,762 13,992 14,294 14,480 $1,693 $1,614 $1,640 $1,545 $1,466 3,156 3,156 3,156 3,156 3,156 2,792 2,638 57.9 93.8 2,392 2,522 60.7 94.1 2,385 2,458 61.5 91.6 2,294 2,512 60.9 92.2 2,204 2,390 61.3 81.1 43.0 41.9 40.0 43.6 58.7 28.6 60.0 27.1 63.1 26.1 1.3 13.8 100.0 3.3 13.1 100.0 4.4 8.3 100.0 3.0 9.9 100.0 3.5 7.3 100.0 II-410 SoCo FOIA Response 002767 SOUTHERN POWER COMPANY FINANCIAL SECTION SoCo FOIA Response 002768 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Southern Power Company and Subsidiary Companies 2010 Annual Report The management of Southern Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010. Oscar C. Harper, IV President and Chief Executive Officer Michael W. Southern Senior Vice President and Chief Financial Officer February 25, 2011 II-412 SoCo FOIA Response 002769 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Southern Power Company We have audited the accompanying consolidated balance sheets of Southern Power Company and Subsidiary Companies (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements (pages II-434 to II-456) present fairly, in all material respects, the financial position of Southern Power Company and Subsidiary Companies at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Atlanta, Georgia February 25, 2011 II-413 SoCo FOIA Response 002770 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Southern Power Company and Subsidiary Companies 2010 Annual Report OVERVIEW Business Activities Southern Power Company and its wholly-owned subsidiaries (the Company) construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the wholesale market. The Company continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives. In general, the Company has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities. The Company is continuing construction of an electric generating plant in Cleveland County, North Carolina. This plant will consist of four combustion turbine natural gas generating units with a total expected generating capacity of 720 megawatts (MW). The units are expected to begin commercial operation in 2012. The Company has entered into long-term PPAs for 540 MWs of the generating capacity of the plant. The Company is also continuing construction of the Nacogdoches biomass generating plant near Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in late 2009 and the plant is expected to begin commercial operation in 2012. The entire output of the plant will be sold under a long-term PPA. As of December 31, 2010, the Company had units totaling 7,880 MWs nameplate capacity in commercial operation. The weighted average duration of the Company’s wholesale contracts exceeds 11.5 years, which reduces remarketing risk. The Company’s future earnings will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets. See FUTURE EARNINGS POTENTIAL herein for additional information. Key Performance Indicators To evaluate operating results and to ensure the Company’s ability to meet its contractual commitments to customers, the Company focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (EFOR) and net income. Peak season EFOR defines the hours during peak demand times when the Company’s generating units are not available due to forced outages (the lower the better). Net income is the primary measure of the Company’s financial performance. The Company’s actual performance in 2010 did not meet targets in these key performance areas. The Company did not meet peak season EFOR targets due to unplanned outages at Plant Stanton and Plant Harris. See RESULTS OF OPERATIONS herein for additional information on the Company’s net income for 2010. Earnings The Company’s 2010 net income was $130.0 million, a $25.8 million decrease over 2009. This decrease was primarily due to higher operations and maintenance expenses, higher depreciation and amortization, and profit recognized in 2009 on a construction contract with the Orlando Utilities Commission (OUC) whereby the Company provided engineering, procurement, and construction services to build a combined cycle unit for the OUC. These decreases were partially offset by lower interest expense, net of amounts capitalized. The Company’s 2009 net income was $155.9 million, an $11.5 million increase over 2008. This increase was primarily due to increased margins associated with the operation of Plant Franklin Unit 3 for all of 2009, increased generation from the Company’s combined cycle units due to lower natural gas prices, and profit recognized under a construction contract with the OUC. These favorable impacts were partially offset by a loss recognized on the transfer of DeSoto County Generating Company, LLC (DeSoto) to Broadway Gen Funding, LLC (Broadway) in December 2009, gains recognized in income in 2008 related to the sale of an undeveloped tract of land in Orange County, Florida to the OUC, and the receipt of a fee for participating in an asset auction as an unsuccessful bidder. Additionally, depreciation increased due to the completion of Plant Franklin Unit 3 in June 2008 and an increase in depreciation rates. Interest expense increased due to a reduction of capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008. II-414 SoCo FOIA Response 002771 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Southern Power Company and Subsidiary Companies 2010 Annual Report The Company’s 2008 net income was $144.4 million, a $12.7 million increase over 2007. This increase was primarily due to increased capacity sales to requirements service customers, market sales of uncontracted generating capacity, a gain on the sale of an undeveloped tract of land in 2008, a loss on the gasifier portion of the integrated coal gasification combined cycle (IGCC) project in 2007, and the receipt of a fee for participating in an asset auction in 2008 as an unsuccessful bidder. These increases were partially offset by transmission service expenses and tariff penalties incurred in 2008, timing of plant maintenance activities, increased general and administrative expenses associated with the implementation of the Federal Energy Regulatory Commission (FERC) separation order, and increased depreciation associated with Plant Oleander Unit 5 and Plant Franklin Unit 3 being placed into commercial operation in December 2007 and June 2008, respectively. RESULTS OF OPERATIONS A condensed statement of income follows: Increase (Decrease) from Prior Year 2009 2010 Amount 2010 2008 (in millions) Operating revenues Fuel Purchased power Other operations and maintenance Loss (gain) on sale of property Loss on IGCC project Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Interest expense Profit recognized on construction contract Other income (expense), net of amounts capitalized Income taxes Net income $ 1,129.1 391.5 170.1 147.4 0.5 119.0 17.8 846.3 282.8 76.1 0.5 (0.4) 76.8 $ 130.0 $ 182.5 159.1 26.1 10.8 (4.5) 20.9 0.9 213.3 (30.8) (8.9) (12.8) (8.9) $ (25.8) $ (366.9) (192.3) (184.0) (11.1) 11.0 9.6 (0.8) (367.6) 0.7 1.8 13.3 (8.0) (7.3) $ 11.5 $ 341.5 186.1 128.1 12.7 (6.0) (17.6) 14.5 2.0 319.8 21.7 4.0 4.3 9.3 $ 12.7 Operating Revenues Operating revenues in 2010 were $1.1 billion, a $182.5 million (19.3%) increase from 2009. This increase was primarily due to a $377.2 million increase in energy and capacity revenues under new and existing PPAs, $80.8 million associated with higher revenues from energy sales that were not covered by PPAs due to more favorable weather in 2010 compared to 2009, and a $46.8 million increase in revenues from power sales under the Intercompany Interchange Contract (IIC). These increases were partially offset by a $321.4 million decrease in energy and capacity revenues associated with the expiration of PPAs in December 2009 and May 2010. Operating revenues in 2009 were $946.7 million, a $366.9 million (27.9%) decrease from 2008. This decrease was primarily due to lower natural gas prices that reduced energy revenues. This decrease was partially offset by increased capacity and energy revenues from the operation of Plant Franklin Unit 3 and a PPA relating to four units at Plant Dahlberg that began in June 2009. Operating revenues in 2008 were $1.31 billion, a $341.5 million (35.1%) increase from 2007. This increase was primarily due to increased short-term energy revenues from uncontracted generating units, increased energy revenues due to higher natural gas prices, and increased revenues from a full year of operations at Plant Oleander Unit 5. These increases were partially offset by decreased demand under existing PPAs due to less favorable weather in 2008 compared to 2007. The increase in fuel revenues was accompanied by an increase in related fuel costs and did not have a significant impact on net income. II-415 SoCo FOIA Response 002772 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Capacity revenues are an integral component of the Company’s PPAs with both affiliate and non-affiliate customers and generally represent the greatest contribution to net income. Energy under the PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges. Details of these PPA capacity and energy revenues are as follows: 2009 2010 2008 (in millions) Capacity revenues – Affiliates Non-affiliates Total Energy revenues – Affiliates Non-affiliates Total Total PPA revenues $ $ 190.6 257.4 448.0 46.1 399.9 446.0 894.0 $ $ 287.6 185.7 473.3 192.8 173.8 366.6 839.9 $ $ 279.2 165.2 444.4 263.6 249.0 512.6 957.0 Wholesale revenues that were not covered by PPAs totaled $228.2 million in 2010, which included $134.0 million of revenues from affiliated companies. Wholesale revenues that were not covered by PPAs totaled $98.9 million in 2009, which included $64.0 million of revenues from affiliated companies. Wholesale revenues that were not covered by PPAs totaled $349.2 million in 2008, which included $95.5 million of revenues from affiliated companies. These wholesale sales were made in accordance with the IIC, as approved by the FERC. These non-PPA wholesale revenues will vary from year to year depending on demand and the availability and cost of generating resources at each company that participates in the centralized operation and dispatch of the Southern Company system fleet of generating plants (power pool). Fuel and Purchased Power Expenses Fuel costs constitute the single largest expense for the Company. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s fuel and purchased power expenditures are as follows: 2009 2010 2008 (in millions) Fuel Purchased power-non-affiliates Purchased power-affiliates Total fuel and purchased power expenses $ $ 391.5 72.7 97.4 561.6 $ $ 232.5 79.3 64.6 376.4 $ $ 424.8 132.2 195.8 752.8 In 2010, total fuel and purchased power expenses increased by $185.2 million (49.2%) compared to 2009. Total fuel and purchased power expenses increased $77.3 million primarily due to an 8.7% increase in the average cost of natural gas and a 36.4% increase in the cost of purchased power and $107.9 million due to an increase in kilowatt-hours (KWH) generated and purchased. In 2009, total fuel and purchased power expenses decreased by $376.4 million (50.0%) compared to 2008. This decrease was driven by a 56.0% decrease in the average cost of natural gas and a 41.3% decrease in the average cost of purchased power. Additionally, purchased power volume decreased 25.2% primarily due to increased generation at the Company’s combined cycle units as a result of lower natural gas prices. These decreases were partially offset by a 31.2% increase in generation at the Company’s combined cycle units as a result of lower natural gas prices. In 2008, total fuel and purchased power expenses increased by $314.2 million (71.6%) compared to 2007. This increase was driven by a 58.9% increase in generation due to operations at Plant Franklin Unit 3, an 11.9% increase in the average cost of natural gas, and a 107.9% increase in the average cost of purchased power. II-416 SoCo FOIA Response 002773 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report In 2010, fuel expense increased by $159.1 million (68.4%) compared to 2009. Fuel expense increased $31.7 million primarily due to an 8.7% increase in the average cost of natural gas and $127.4 million due to an increase in KWHs generated. In 2009, fuel expense decreased by $192.3 million (45.3%) compared to 2008. This decrease was driven by a 56.0% decrease in the average cost of natural gas. This decrease was partially offset by a 31.2% increase in generation at the Company’s combined cycle units as a result of lower natural gas prices. In 2008, fuel expense increased by $186.1 million (78.0%) compared to 2007. This increase was driven by a 58.9% increase in generation primarily due to operations at Plant Franklin Unit 3 and an 11.9% increase in the average cost of natural gas. In 2010, purchased power expense increased $26.1 million (18.1%) compared to 2009. Purchased power expense increased $45.6 million due to an increase in the average cost of purchased power, partially offset by a $19.5 million decrease due to fewer KWHs purchased. In 2009, purchased power expense decreased $184.0 million (56.1%) compared to 2008, primarily due to a 41.3% decrease in the average cost of purchased power. Additionally, purchased power volume in 2009 decreased 25.2% due to increased generation at the Company’s combined cycle units as a result of lower natural gas prices. Purchased power expense increased $128.1 million (64.1%) in 2008 when compared to 2007, primarily due to a 107.9% increase in the average cost of purchased power. The Company’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is accompanied by an increase or decrease in related fuel revenues and does not have a significant impact on net income. The Company is responsible for the cost of fuel for units that are not covered under PPAs. Power from these units is sold into the market or sold to affiliates under the IIC. Purchased power expenses will vary depending on demand and the availability and cost of generating resources available throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by the Company, affiliate-owned generation, or external purchases. Other Operations and Maintenance Expenses In 2010, other operations and maintenance expenses increased $10.8 million (7.9%) compared to 2009. This increase was primarily due to $4.1 million of additional expense associated with the passage of healthcare legislation in March 2010 and $4.2 million related to generating plant outages and maintenance, mainly at Plants Stanton, Harris, and Franklin. See FUTURE EARNINGS POTENTIAL – “Legislation – Healthcare Reform” herein for additional information regarding healthcare legislation. In 2009, other operations and maintenance expenses decreased $11.1 million (7.5%) compared to 2008. This decrease was due primarily to transmission tariff penalties recognized in 2008, reduced transmission expenses due to a decrease in power sales into the market, and the timing of plant outages. In 2008, other operations and maintenance expenses increased $12.7 million (9.4%) compared to 2007. This increase was due primarily to the timing of plant maintenance activities, transmission tariff penalties, and additional administrative and general expenses as a result of costs incurred to implement the FERC compliance plan. See Note 3 to the financial statements under “FERC Matters” for additional information. Loss (Gain) on Sale of Property In December 2009, the Company recorded a loss of $5.0 million on the divestiture of DeSoto. In January 2008, the Company recorded a gain of $6.0 million on the sale of an undeveloped tract of land. Loss on IGCC Project In November 2007, the Company and the OUC mutually agreed to terminate the construction of the gasifier portion of the IGCC project, originally planned as a joint venture; however, the Company continued construction of the gas-fired combined cycle generating facility, owned solely by the OUC. The Company recorded a loss in the fourth quarter 2007 of $17.6 million related to the cancellation of the gasifier portion of the IGCC project. This loss consists of the write-off of construction costs of $14.0 million and an accrual for termination payments of $3.6 million. All termination payments were completed in 2008. II-417 SoCo FOIA Response 002774 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Depreciation and Amortization In 2010, depreciation and amortization increased $20.9 million (21.3%) compared to 2009. This increase was primarily related to a $6.7 million increase associated with the acquisition of West Georgia Generating Company LLC (West Georgia) and the divestiture of DeSoto in December 2009 which resulted in an increase in property, plant, and equipment of $120.2 million. The increase was also due to $7.5 million of equipment retirements and a $6.5 million increase in depreciation rates related primarily to increased starts and run-hours at the Company’s generating plants. In 2009, depreciation and amortization increased $9.6 million (10.9%) compared to 2008. This increase was primarily due to the completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented during 2009. In 2008, depreciation and amortization increased $14.5 million (19.7%) due to the completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented in January 2008. See ACCOUNTING POLICIES – “Depreciation” herein for additional information regarding the Company’s ongoing review of depreciation estimates. See also Note 1 to the financial statements under “Depreciation” for additional information. Interest Expense, Net of Amounts Capitalized In 2010, interest expense, net of amounts capitalized decreased $8.9 million (10.4%) compared to 2009. This decrease was primarily due to $10.5 million of additional capitalized interest associated with the construction of the Cleveland County combustion turbine generating plant and the Nacogdoches biomass plant, partially offset by $0.7 million associated with an increase in interest expense on commercial paper and $0.7 million associated with interest rate swaps on senior notes. In 2009, interest expense, net of amounts capitalized increased $1.8 million (2.1%) compared to 2008. This increase was primarily due to a $5.5 million decrease in capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008, partially offset by a $1.7 million decrease in short-term borrowing levels during 2009 and a decrease in amortization of interest rate derivatives of $2.1 million. In 2008, interest expense, net of amounts capitalized increased $4.0 million (5.1%) compared to 2007. This increase was primarily the result of a decrease in capitalized interest as a result of the completion of Plant Oleander Unit 5 in December 2007 and Plant Franklin Unit 3 in June 2008, partially offset by a decrease in short-term borrowing levels in 2008. Profit Recognized on Construction Contract Profit recognized on the construction contract with the OUC whereby the Company has provided engineering, procurement, and construction services to build a combined cycle unit for the OUC was $0.5 million in 2010 and $13.3 million in 2009. No profit or loss on this contract was recognized in 2008. Construction activities commenced in 2006 and were substantially completed in 2009. Other Income (Expense), Net The change in other income (expense), net for 2010 as compared to 2009 was not material. Other income (expense), net was an expense of $0.4 million in 2009 versus income of $7.6 million in 2008. This change was primarily due to a $6.4 million fee received in 2008 for participating in an asset auction. The Company was not the successful bidder in the asset auction. Other income (expense), net increased $4.3 million (131.1%) in 2008. This increase was primarily due to a $6.4 million fee received in 2008 for participating in an asset auction. The Company was not the successful bidder in the asset auction. II-418 SoCo FOIA Response 002775 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Income Taxes In 2010, income taxes decreased $8.9 million (10.4%) compared to 2009. This decrease was primarily due to $12.0 million associated with lower pre-tax earnings and $3.7 million of tax benefits associated with the construction of the Nacogdoches biomass plant. These decreases were partially offset by a $6.7 million increase in Alabama state taxes. Alabama’s state tax liability is reduced by a deduction for federal income taxes paid. Due to increased bonus depreciation and incentives associated with new plant construction, the federal tax liability was significantly reduced, resulting in a higher overall state tax expense. Also contributing to the increase in state taxes was the application of the resulting higher state tax rate to the deferred income tax balance. In 2009, income taxes decreased $7.3 million (7.8%) compared to 2008. This decrease was due to changes in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction, lower state income taxes, and tax benefits received under convertible investment tax credits (ITCs). Higher pre-tax earnings partially offset these decreases. See Note 5 to the financial statements for additional information. Income taxes increased $9.3 million (11.2%) in 2008 primarily due to higher pre-tax earnings and changes in the Section 199 production activities deduction. Effects of Inflation The Company is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on the Company’s results of operations has not been substantial in recent years. FUTURE EARNINGS POTENTIAL General The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s competitive wholesale business. The level of future earnings also depends on numerous factors including the Company’s ability to achieve sales growth while containing costs, regulatory matters, creditworthiness of customers, total generating capacity available in the Southeast, the successful remarketing of capacity as current contracts expire, and the Company’s ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. Recessionary conditions have lowered demand and have negatively impacted capacity revenues under the Company’s PPAs where the amounts purchased are based on demand. The Company is unable to predict whether demand under these PPAs will return to pre-recession levels. The timing and extent of the economic recovery is uncertain and will impact future earnings. Power Sales Agreements The Company’s sales are primarily through long-term PPAs. The Company is working to maintain and expand its share of the wholesale market. The Company expects that many areas of the market will need capacity in 2017. The Company’s PPAs consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated plant unit where all or a portion of the generation from that unit is reserved for that customer. The Company typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that the Company serve the customer’s capacity and energy requirements from a combination of the customer’s own generating units and from Company resources not dedicated to serve unit or block sales. The Company has rights to purchase power provided by the requirements customers’ resources when economically viable. II-419 SoCo FOIA Response 002776 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The Company has entered into the following PPAs over the past three years: Date MWs Plant Contract Term 2010 City of Seneca Georgia Electric Membership Corporation (EMCs) (a) June 2010 October 2010(a) 30 (h) 423 (h) Unassigned Unassigned 2009 Municipal Electric Authority of Georgia (MEAG Power) (b) Georgia Energy Cooperative, Inc. (GEC) (b) Austin Energy (c) Seminole Electric Cooperative, Inc. (Seminole) (d) December 2009 December 2009 October 2009 June 2009 157 (h) 151 100 509 West Georgia West Georgia Nacogdoches Oleander 12/09-4/29 6/10-5/30 6/12-5/32 1/16-5/21 2008 North Carolina Municipal Power Agency No. 1 (NCMPA1) North Carolina Electric Membership Corporation (NCEMC) NCEMC EnergyUnited Electric Membership Corporation (EnergyUnited) The Energy Authority, Inc. EMCs (g) Florida Municipal Power Agency (FMPA) (i) December 2008 November 2008 November 2008 November 2008 August 2008 July 2008 July 2008 180 180 180 (e) 100 151 360 (h) 85 Cleveland Cleveland Cleveland Purchased (f) Rowan Unassigned Stanton 1/12-12/31 1/12-12/36 1/12-12/36 1/12-12/21 1/11-12/14 1/10-12/34 (g) 10/13-9/23 (a) (b) (c) (d) (e) (f) (g) (h) (i) 7/10-6/15 01/15-12/27 (a) These agreements, signed in October and December 2010, are extensions of current agreements with 11 Georgia EMCs. Nine agreements were extended from 2015 through 2024, one agreement was extended from 2018 through 2027, and one agreement was extended from 2018 through 2024. Assumed contract through the West Georgia acquisition in 2009. Assumed contract through the Nacogdoches Power LLC acquisition in 2009. Commercial operation of Plant Nacogdoches is expected to begin in June 2012. This agreement is an extension of the current agreement with Seminole for Plant Oleander. Power purchases under this agreement will increase over the term of the agreement. 45 MWs will be sold from 2012 through 2016, 90 MWs will be sold from 2017 through 2018, and 180 MWs will be sold from 2019 through 2036. Power to serve this agreement will be purchased under a third party agreement for resale to EnergyUnited. The purchases will be resold at cost. These agreements are extensions of current agreements with 10 Georgia EMCs. Eight agreements were extended from 2010 through 2031and two agreements were extended from 2013 through 2034. Represents average annual capacity purchases. This agreement is an extension of the current agreement with FMPA for Plant Stanton. The Company has PPAs with some of Southern Company’s traditional operating companies and with other investor owned utilities, independent power producers, municipalities, and electric cooperatives. Although some of the Company’s PPAs are with the traditional operating companies, the Company’s generating facilities are not in the traditional operating companies’ regulated rate bases, and the Company is not able to seek recovery from the traditional operating companies’ ratepayers for construction, repair, environmental, or maintenance costs. The Company expects that the capacity payments in the PPAs will produce sufficient cash flows to cover costs, pay debt service, and provide an equity return. However, the Company’s overall profit will depend on numerous factors, including efficient operation of its generating facilities and demand under the Company’s PPAs. As a general matter, existing PPAs provide that the purchasers are responsible for either procuring the fuel or reimbursing the Company for the cost of fuel relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, the Company may be responsible for excess fuel costs. With respect to fuel transportation risk, most of the Company’s PPAs provide that the counterparties are responsible for transporting the fuel to the particular generating facility. Fixed and variable operation and maintenance costs will be recovered through capacity charges based on dollars-per-kilowatt year or energy charges based on dollars-per-MW hour. In general, the Company has long-term service contracts with General Electric and Siemens AG to reduce its exposure to certain operation and maintenance costs relating to such vendors’ applicable equipment. See Note 7 to the financial statements under “Long-Term Service Agreements” for additional information. II-420 SoCo FOIA Response 002777 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Many of the Company’s PPAs have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that Standard & Poor’s, a division of The McGraw Hill Companies, Inc. (S&P), or Moody’s Investors Service (Moody’s) downgrades the credit ratings of the counterparty to an unacceptable credit rating or if the counterparty is not rated or fails to maintain a minimum coverage ratio. The PPAs are expected to provide the Company with a stable source of revenue during their respective terms. The Company has entered into long-term power sales agreements for an average of 79% of its available capacity for the next five years and 68% of its available capacity for the next 10 years. Environmental Matters The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, such as requirements related to greenhouse gases or changes to existing statutes or regulations, could affect many areas of the Company’s operations. While the Company’s PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time. Because the Company’s units are newer gas-fired generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal-fired generating facilities or older gas-fired generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the availability of water withdrawal rights, uncertainties regarding aesthetic impacts such as increased light or noise, and concerns about potential adverse health impacts, can, however, increase the cost of siting and operating any type of future electric generating facility. The impact of such statutes and regulations on the Company cannot be determined at this time. Carbon Dioxide Litigation Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in a similar case. The ultimate outcome of this matter cannot be determined at this time. II-421 SoCo FOIA Response 002778 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the Kivalina case, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. Environmental Statutes and Regulations Air Quality Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO 2 ), which established a new one-hour standard, became effective on April 12, 2010. Although none of the areas in which the Company operates generating assets are expected to be designated as nonattainment for the NO 2 standard, based on current ambient air quality monitoring data, the new NO 2 standard could result in significant additional compliance and operational costs for units that require new source permitting. On April 29, 2010, the EPA issued a proposed Industrial Boiler (IB) Maximum Achievable Control Technology rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA issued the final rules on February 23, 2011 and, at the same time, issued a notice of intent to reconsider the final rules to allow for additional public review and comment. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time. Global Climate Issues Although the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas emissions, neither this legislation nor similar measures passed the U.S. Senate before the end of the 2010 session. Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are expected to continue to be considered in Congress. The financial and operational impacts of climate or energy legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on natural gas and biomass prices, and cost recovery through PPAs. II-422 SoCo FOIA Response 002779 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report While climate legislation has yet to be adopted, the EPA is moving forward with regulation of greenhouse gases under the Clean Air Act. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. In December 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, which began on January 2, 2011, applies to sources and projects that would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed settlement agreement to issue standards of performance for greenhouse gas emissions from new and modified fossil fuel fired electric generating units and greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012. All of the EPA’s final Clean Air Act rulemakings have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit; however, the court declined motions to stay the rules pending resolution of those challenges. As a result, the rules may impact the amount of time it takes to obtain PSD permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate outcome of these rules cannot be determined at this time and will depend on the content of the final rules and the outcome of any legal challenges. International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The most recent round of negotiations took place in December 2010. The outcome and impact of the international negotiations cannot be determined at this time. Although the outcome of federal, state, and international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through PPAs. Further, higher costs that are recovered through regulated rates at other utilities could contribute to an overall reduction in demand for electricity, which could negatively impact the Company’s results of operations, cash flows, and financial condition. In 2009, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 7 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2010 is approximately 9 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The Company continues to evaluate its future energy and emissions profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions, including the construction of the Nacogdoches biomass plant in Sacul, Texas. II-423 SoCo FOIA Response 002780 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Legislation Healthcare Reform On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, the Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in tax law must be recognized in the period enacted regardless of the effective date. The Company incurred a non-cash write-off of approximately $4 million to expense for the year ended December 31, 2010. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and related employee benefit plan costs. Any future impact on the Company’s financial statements cannot be determined at this time. Income Tax Matters Tax Method of Accounting for Repairs The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation assets with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $6 million for the Company. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time. Convertible Investment Tax Credits In February 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA included renewable energy incentives. The Company is receiving ITCs under the renewable energy incentives related to the Nacogdoches biomass facility which will have a material impact on cash flows and net income. Bonus Depreciation On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which could have a significant impact on the future cash flows of the Company. The application of the bonus depreciation provisions in these acts in 2010 provided approximately $4 million in increased cash flow. II-424 SoCo FOIA Response 002781 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Internal Revenue Code Section 199 Domestic Production Deduction The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code. The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010. For 2008 and 2009, a 6% deduction was available to the Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation there was no domestic production deduction available for 2010 and none is projected to be available for 2011. Construction Projects Cleveland County Units 1-4 In December 2008, the Company announced that it will build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to begin commercial operation in 2012. Costs incurred through December 31, 2010 were $175.8 million. The total estimated construction cost is expected to be between $350 million and $400 million, and is included in the capital program estimates described under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. Nacogdoches Biomass Plant In October 2009, the Company acquired all of the outstanding membership interests of Nacogdoches Power LLC (Nacogdoches) from American Renewables LLC, the original developer of the project. Nacogdoches is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in 2009 and the plant is expected to begin commercial operation in 2012. Costs incurred through December 31, 2010 were $249.8 million. The total estimated cost of the project is expected to be between $475 million and $500 million, and is included in the capital program estimates described under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. Other Matters From time to time, the Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property and other damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues. ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors. II-425 SoCo FOIA Response 002782 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Revenue Recognition The Company’s revenue recognition depends on appropriate classification and documentation of transactions in accordance with GAAP. In general, the Company’s power sale transactions can be classified in one of four categories: leases, non-derivatives or normal sale derivatives, cash flow hedges, and mark-to-market transactions. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” herein and Notes 1 and 9 to the financial statements. The Company’s revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract. Lease Transactions The Company considers the following factors to determine whether the sales contract is a lease:  Assessing whether specific property is explicitly or implicitly identified in the agreement;  Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and  Assessing whether the arrangement conveys to the purchaser the right to use the identified property. If the contract meets the above criteria for a lease, the Company performs further analysis as to whether the lease is classified as operating or capital. As none of the transactions transfer title of the underlying property to the counterparty, all of Company’s power sales contracts classified as leases are accounted for as operating leases. Non-Derivative and Normal Sale Derivative Transactions If the sales contract is not considered a lease, the Company further considers the following factors to determine proper transaction classification:  Assessing whether a sales contract meets the definition of a derivative; • Assessing whether a sales contract meets the definition of a capacity contract; • Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and • Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity). Contracts that do not meet the definition of a derivative or are designated as normal sales (i.e. capacity contracts which provide for the sale of electricity that involve physical delivery in quantities within the Company’s available generating capacity) are exempt from fair value accounting in accordance with GAAP. As a result, such transactions are accounted for as executory contracts. The related revenue is recognized on an accrual basis in amounts equal to the lesser of the cumulative levelized amount or the cumulative amount billable under the contract over the respective contract periods. Revenues are recorded on a gross or net basis in accordance with GAAP. Contracts recorded on the accrual basis represented the majority of the Company’s operating revenues for the years ended December 31, 2010, 2009, and 2008. Cash Flow Hedge Transactions The Company further considers the following in designating other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions: • Identifying the hedging instrument, the hedged transaction, and the nature of the risk being hedged; and • Assessing hedge effectiveness at inception and throughout the contract term. These contracts are marked to market through other comprehensive income over the life of the contract. Realized gains and losses are then recognized in revenues as incurred. II-426 SoCo FOIA Response 002783 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Mark-to-Market Transactions Contracts for sales and purchases of electricity, which meet the definition of a derivative and that either do not qualify or are not designated as normal sales or as cash flow hedges, are marked-to-market and recorded directly through net income. Impairment of Long Lived Assets and Intangibles The Company’s investments in long-lived assets are primarily generation assets, whether in service or under construction. The Company’s intangible assets consist of acquired PPAs that are amortized over the term of the PPAs and goodwill resulting from acquisitions. The Company evaluates the carrying value of these assets in accordance with accounting standards whenever indicators of potential impairment exist, or annually in the case of goodwill. Examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, and the inability to remarket generating capacity for an extended period. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, including the following: • Future demand for electricity based on projections of economic growth and estimates of available generating capacity; • Future power and natural gas prices, which have been quite volatile in recent years; and • Future operating costs. Acquisition Accounting The Company has been engaged in a strategy of acquiring assets. The Company has accounted for these acquisitions under the purchase method in accordance with GAAP. Accordingly, the Company has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price of each acquisition was allocated to the fair value of the identifiable assets and liabilities. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions after December 31, 2008 have been expensed as incurred. Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following: • Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters. • Changes in existing income tax regulations or changes in IRS or state revenue department interpretations of existing regulations. • Identification of sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party. • Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. • Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA. II-427 SoCo FOIA Response 002784 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Depreciation Depreciation of the original cost of assets is computed under the straight-line method and applies a composite depreciation rate based on the assets’ estimated useful lives determined by management. The primary assets in property, plant, and equipment are power plants, all of which have an estimated composite life ranging from 24 to 35 years. These lives reflect a weighted average of the significant components (retirement units) that make up the plants. Key judgments impacting the estimated lives of component parts include estimates of run-hours and starts which can impact the future utility of these components. The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized. Convertible Investment Tax Credits Under the ARRA, certain costs related to the Nacogdoches plant construction are eligible for ITCs or cash grants. The Company has elected to receive ITCs. A high degree of judgment is required in determining which construction expenditures qualify for ITCs. See Note 1 to the financial statements under “Convertible Income Tax Credits” for additional information. FINANCIAL CONDITION AND LIQUIDITY Overview The Company’s financial condition remained stable at December 31, 2010. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet its future capital and liquidity needs. See “Sources of Capital” herein for additional information on lines of credit. Net cash provided from operating activities totaled $327.1 million in 2010, compared to $318.1 million in 2009. This increase was mainly due to an increase in convertible ITCs. Net cash used for investing activities totaled $306.6 million in 2010, compared to $364.1 million in 2009. This decrease was primarily due to the Nacogdoches and West Georgia acquisitions in October 2009 and December 2009, respectively, partially offset by an increase in construction work in progress related to construction activities at Cleveland County and Nacogdoches. Net cash used for financing activities totaled $15.5 million in 2010, compared to $15.2 million of cash provided from financing activities in 2009. The increase in cash used is mainly due to a smaller increase in short-term borrowings in 2010 as compared to prior years. Net cash provided from operating activities totaled $318.1 million in 2009, increasing 20.4% from 2008. This increase was primarily due to a reduction in costs incurred on the OUC construction contract, receipt of convertible ITCs, and timing of tax payments. Net cash used for investing activities totaled $364.1 million in 2009, increasing 324.5% from 2008. This increase was primarily due to the Nacogdoches and West Georgia acquisitions. Gross property additions to utility plant of $137.1 million in 2009 were primarily related to the construction of the Cleveland County and Nacogdoches facilities. Net cash provided from financing activities was $15.2 million in 2009, compared to $140.6 million used in 2008. This change was primarily due to the issuance of short-term debt in 2009. Net cash provided from operating activities totaled $264.3 million in 2008, decreasing 16.2% from 2007. This decrease was primarily due to cash outflows for engineering, procurement, and construction services to build a combined cycle unit for the OUC. Net cash used for investing activities totaled $85.8 million in 2008, decreasing 53.4% from 2007. This decrease was primarily due to the completion of Plant Oleander Unit 5 in 2007 and the completion of Plant Franklin Unit 3 in 2008. Gross property additions to utility plant of $50.0 million in 2008 were primarily related to the completion of Plant Franklin Unit 3. Net cash used for financing activities was $140.6 million in 2008, decreasing 12.9% from 2007. This decrease was primarily due to reduced levels of short-term debt in 2008. Significant asset changes in the balance sheet during 2010 include an increase in construction work in progress related to Cleveland County and Nacogdoches construction activities. II-428 SoCo FOIA Response 002785 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Significant asset changes in the balance sheet during 2009 include increases related to the West Georgia and Nacogdoches acquisitions. Construction work in progress increased due to Cleveland County and Nacogdoches construction activities. Prepaid long-term service agreements increased due to the timing of outage activities. Additionally, prepaid income taxes decreased due to the timing of income tax payments. Cash decreased due to the West Georgia and Nacogdoches acquisitions and increased construction activity. Significant liability and stockholder’s equity changes in the balance sheet during 2010 include an increase in notes payable mainly related to Cleveland County and Nacogdoches construction activities and an increase in accumulated deferred income taxes primarily due to bonus depreciation. Significant liability and stockholder’s equity changes in the balance sheet during 2009 include the issuance of $118.9 million in notes payable, an increase in accounts payable related to construction projects, and a decrease in net billings in excess of cost due to the timing of scheduled payments and costs incurred with regard to the OUC construction contract. In 2009, the Company also paid $106.1 million in dividends to Southern Company. Sources of Capital The Company may use operating cash flows, external funds, or equity capital or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. The Company expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. The Company’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, at December 31, 2010, the Company had $400 million of committed credit arrangements with banks that expire in 2012. There were no borrowings under this facility outstanding at December 31, 2010. Proceeds from these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for the Company’s commercial paper program. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Company’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. During 2010, the Company had an average of $169 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $259 million. At December 31, 2010, the Company had $204 million of commercial paper outstanding. During 2009, the Company had an average of $7 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum. At December 31, 2009, the Company had $119 million of commercial paper outstanding. The maximum amount outstanding during 2009 was $119 million. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. Financing Activities In 2010 and 2009, the Company did not issue or redeem any long-term debt securities. Credit Rating Risk The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At December 31, 2010, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $360 million. At December 31, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.0 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market. II-429 SoCo FOIA Response 002786 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report In addition, through the acquisition of Plant Rowan, the Company assumed PPAs with Duke Energy and NCMPA1 that could require collateral, but not accelerated payment, in the event of a downgrade of the Company’s credit. The Duke Energy PPA defines the downgrade to be below BBB- or Baa3. The NCMPA1 PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade for both PPAs. Market Price Risk The Company is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, the Company takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis. At December 31, 2010, the Company had no variable long-term debt outstanding. Therefore, there would be no effect on annualized interest expense related to long-term debt if the Company sustained a 100 basis point change in interest rates. Since a significant portion of outstanding indebtedness bears interest at fixed rates, the Company is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot be determined at this time. Because energy from the Company’s facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company’s exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. The changes in fair value of energy-related derivative contracts for the years ended December 31 were as follows: 2009 2010 Changes Changes Fair Value (in millions) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes(a) Contracts outstanding at the end of the period, assets (liabilities), net (a) $ (3.5) 1.5 (1.5) $ (3.5) $ 3.4 (2.0) (4.9) $ (3.5) Current period changes also include the changes in fair value of new contracts entered into during the period, if any. For the year ended December 31, 2010, there was no change in the total fair value of the energy-related derivative contracts. For the year ended December 31, 2009, there was a $6.9 million decrease in the fair value positions of the energy-related derivative contracts, which is due to both volume and price changes in power and natural gas positions. II-430 SoCo FOIA Response 002787 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The net hedge positions at December 31, 2010 and December 31, 2009 and respective period end dates that support these changes were as follows: December 31, 2010 December 31, 2009 0.9 2.7 $(2.33) $ (0.36) 13.0 - 8.3 2.0 $0.11 $ 0.29 $- $ (0.04) Power (net sold) Megawatt hours (MWH) (in millions) Weighted average contract cost per MWH above (below) market prices (in dollars) Natural gas (net purchase) Commodity – million British thermal unit (mmBtu) Location basis – million mmBtu Commodity – weighted average contract cost per mmBtu above (below) market prices (in dollars) Location basis – weighted average contract cost per mmBtu above (below) market prices (in dollars) At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets (liabilities) as follows: Asset (Liability) Derivatives 2009 2010 (in millions) Cash flow hedges Not designated Total fair value $ (2.5) (1.0) $ (3.5) $ (1.0) (2.5) $ (3.5) Gains and losses on energy-related derivatives used by the Company to hedge anticipated purchases and sales are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Total net unrealized pre-tax gains (losses) recognized in the statements of income for the years ended December 31, 2010, 2009, and 2008 for energy-related derivative contracts that are not hedges were $(1.5) million, $(5.2) million, and $0.9 million, respectively. The Company uses over-the-counter contracts that are not exchange-traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 8 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2010 were as follows: Total Fair Value December 31, 2010 Fair Value Measurements Maturity Year 1 Years 2&3 Years 4&5 (in millions) Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period $ (3.5) $ (3.5) $ (3.6) $ (3.6) $ (0.3) $ (0.3) $ 0.4 $ 0.4 The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related derivative contracts. The Company only enters into agreements with counterparties that have investment grade credit ratings by S&P and Moody’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. See Note 1 to the financial statements under “Financial Instruments” and Note 9 to the financial statements for additional information. II-431 SoCo FOIA Response 002788 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized. Capital Requirements and Contractual Obligations The capital program of the Company is currently estimated to be $540 million for 2011, $144 million for 2012, and $37 million for 2013. These amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and the Company’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. The Company is currently constructing a four-unit combustion turbine generating plant in Cleveland County, North Carolina and a biomass generating facility in Sacul, Texas. See FUTURE EARNINGS POTENTIAL – “Construction Projects” herein for additional information. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 6, 7, and 9 to the financial statements for additional information. Contractual Obligations 2011 Long-term debt(a) – Principal Interest Energy-related derivative obligations(b) Operating leases Unrecognized tax benefits and interest(c) Purchase commitments(d) – Capital(e) Natural gas(f) Biomass fuel(g) Purchased power(h) Long-term service agreements(i) Total 20122013 20142015 After 2015 Uncertain Timing (c) Total (in millions) $ 74.3 5.8 0.5 - $ 575.0 $ 525.0 $ 200.0 112.6 76.7 267.7 0.4 1.0 0.9 22.3 - 539.6 338.2 7.8 48.8 $1,015.0 181.2 485.9 295.2 229.2 32.0 36.0 110.0 99.6 105.1 241.7 86.6 101.0 878.3 $1,574.3 $1,139.9 $1,949.2 $ 2.3 $ 1,300.0 531.3 6.2 24.7 2.3 $ 2.3 720.8 1,348.5 178.0 454.2 1,114.7 $5,680.7 (a) All amounts are reflected based on final maturity dates. The Company plans to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. (b) For additional information, see Notes 1 and 9 to the financial statements. (c) The timing related to the realization of $2.3 million in unrecognized tax benefits and corresponding interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Note 5 to the financial statements for additional information. The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $147.4 million, $136.7 million, and $147.7 million, respectively. (d) (e) The Company provides forecasted capital expenditures for a three-year period. Amounts represent estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. (f) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2010. (g) Biomass fuel commitments are based on minimum committed tonnage of wood waste purchases for Plant Nacogdoches. Plant Nacogdoches is expected to begin commercial operation in 2012. Amounts reflected include price escalation based on inflation indices. (h) Purchased power commitments of $71.5 million in 2012-2013, $74.4 million in 2014-2015, and $241.7 million after 2015 will be resold under a third party agreement to EnergyUnited. The purchases will be resold at cost. (i) Long-term service agreements include price escalation based on inflation indices. II-432 SoCo FOIA Response 002789 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company’s 2010 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning environmental regulations and expenditures, financing activities, impacts of the adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, impacts of revisions to depreciation estimates, start and completion of construction projects, filings with federal regulatory authorities, impacts of adoption of new accounting rules, plans and estimated costs for new generation resources, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: • • • • • • • • • • • • • • • • • • • • the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, mercury, carbon, soot, particulate matter, hazardous air pollutants, and other substances, financial reform legislation, and changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures; available sources and costs of fuels; effects of inflation; advances in technology; state and federal rate regulations; the ability to control costs and avoid cost overruns during the development and construction of facilities; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due and to perform as required; the ability to obtain new short- and long-term contracts with wholesale customers; the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings; the ability of the Company to obtain additional generating capacity at competitive prices; catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources; the effect of accounting pronouncements issued periodically by standard-setting bodies; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the Securities and Exchange Commission. The Company expressly disclaims any obligation to update any forward-looking statements. II-433 SoCo FOIA Response 002790 CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2010, 2009, and 2008 Southern Power Company and Subsidiary Companies 2010 Annual Report 2010 2009 2008 (in thousands) Operating Revenues: Wholesale revenues, non-affiliates Wholesale revenues, affiliates Other revenues Total operating revenues Operating Expenses: Fuel Purchased power, non-affiliates Purchased power, affiliates Other operations and maintenance Loss (gain) on sale of property Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Interest expense, net of amounts capitalized Profit recognized on construction contract Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Net Income $751,575 370,630 6,940 1,129,145 $394,366 544,415 7,870 946,651 $667,979 638,266 7,296 1,313,541 391,535 72,653 97,408 147,433 478 119,026 17,818 846,351 282,794 232,466 79,355 64,587 136,655 4,977 98,135 16,920 633,095 313,556 424,800 132,222 195,743 147,711 (6,015) 88,511 17,700 1,000,672 312,869 (76,111) 470 (372) (76,013) 206,781 76,759 $130,022 (84,963) 13,296 (374) (72,041) 241,515 85,663 $155,852 (83,212) 7,594 (75,618) 237,251 92,892 $144,359 The accompanying notes are an integral part of these financial statements. II-434 SoCo FOIA Response 002791 CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2010, 2009, and 2008 Southern Power Company and Subsidiary Companies 2010 Annual Report 2010 2009 2008 (in thousands) Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating activities -Depreciation and amortization, total Deferred income taxes Convertible investment tax credits received Deferred revenues Mark-to-market adjustments Accumulated billings on construction contract Accumulated costs on construction contract Profit recognized on construction contract Loss (gain) on sale of property Other, net Changes in certain current assets and liabilities --Receivables -Fossil fuel stock -Materials and supplies -Prepaid income taxes -Other current assets -Accounts payable -Accrued taxes -Accrued interest -Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Cash paid for acquisitions Sale of property Change in construction payables, net Payments pursuant to long-term service agreements Other investing activities Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds - capital contributions Payment of common stock dividends Net cash provided from (used for) financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Supplemental Cash Flow Information: Cash paid during the period for -Interest (net of $12,110, $1,624 and $7,075 capitalized, respectively) Income taxes (net of refunds and investment tax credits) Noncash value of business exchanged in West Georgia acquisition Noncash transactions - accrued property additions at year-end $130,022 $155,852 $144,359 132,802 33,981 26,400 (5,586) 1,492 401 (65) (470) 505 5,708 110,427 22,950 16,800 2,288 5,204 48,451 (46,765) (13,296) 4,977 5,630 102,783 70,338 (703) (925) 85,619 (110,096) (6,015) 4,851 (22,674) 2,604 443 4,784 (167) 655 15,928 53 305 327,121 (9,717) 2,738 (5,345) 16,296 (298) 2,043 88 7 (199) 318,131 (11,156) (2,640) 2,773 (21,338) 1,413 10,451 (1,622) (252) (3,575) 264,265 (299,602) 4,000 31,290 (41,598) (721) (306,631) (137,133) (194,156) 84 13,435 (46,120) (184) (364,074) (49,964) 5,073 (7,529) (31,725) (1,625) (85,770) 84,956 6,659 (107,100) (15,485) 5,005 7,152 $12,157 118,948 2,353 (106,100) 15,201 (30,742) 37,894 $ 7,152 (49,748) 3,642 (94,500) (140,606) 37,889 5 $ 37,894 $63,229 (6,246) 46,764 $ 73,064 30,220 70,839 15,474 $ 69,716 47,611 2,039 The accompanying notes are an integral part of these financial statements. II-435 SoCo FOIA Response 002792 CONSOLIDATED BALANCE SHEETS At December 31, 2010 and 2009 Southern Power Company and Subsidiary Companies 2010 Annual Report Assets 2009 2010 (in thousands) Current Assets: Cash and cash equivalents Receivables -Customer accounts receivable Other accounts receivable Affiliated companies Fossil fuel stock, at average cost Materials and supplies, at average cost Prepaid service agreements - current Prepaid income taxes Other prepaid expenses Assets from risk management activities Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Plant in service, net of depreciation Construction work in progress Total property, plant, and equipment Other Property and Investments: Goodwill Other intangible assets, net of amortization of $693 and $17 at December 31, 2010 and December 31, 2009, respectively Total other property and investments Deferred Charges and Other Assets: Prepaid long-term service agreements Other deferred charges and assets -- affiliated Other deferred charges and assets -- non-affiliated Total deferred charges and other assets Total Assets $12,157 $ 7,152 76,508 1,979 19,673 13,663 33,934 41,627 652 3,343 2,160 20 205,716 28,873 2,064 38,561 15,351 31,607 44,090 5,177 3,176 4,901 6,754 187,706 3,038,877 535,800 2,503,077 427,788 2,930,865 2,994,463 439,457 2,555,006 153,982 2,708,988 1,839 1,794 48,426 50,265 49,102 50,896 69,690 3,275 16,540 89,505 $3,276,351 74,513 3,540 17,410 95,463 $3,043,053 The accompanying notes are an integral part of these financial statements. II-436 SoCo FOIA Response 002793 CONSOLIDATED BALANCE SHEETS At December 31, 2010 and 2009 Southern Power Company and Subsidiary Companies 2010 Annual Report Liabilities and Stockholder's Equity 2010 2009 (in thousands) Current Liabilities: Notes payable Accounts payable -Affiliated Other Accrued taxes -Accrued income taxes Other accrued taxes Accrued interest Liabilities from risk management activities Billings in excess of cost on construction contract Other current liabilities Total current liabilities Long-Term Debt: Senior notes -6.25% due 2012 4.875% due 2015 6.375% due 2036 Unamortized debt discount Long-term debt Deferred Credits and Other Liabilities: Accumulated deferred income taxes Deferred convertible investment tax credits Deferred capacity revenues -- affiliated Other deferred credits and liabilities -- affiliated Other deferred credits and liabilities -- non-affiliated Total deferred credits and other liabilities Total Liabilities Common Stockholder's Equity: Common stock, par value $0.01 per share -Authorized - 1,000,000 shares Outstanding - 1,000 shares Paid-in capital Retained earnings Accumulated other comprehensive income (loss) Total common stockholder's equity Total Liabilities and Stockholder's Equity Commitments and Contingent Matters (See notes) $ 203,904 $ 118,948 69,656 45,248 58,493 31,128 5,562 2,775 29,976 5,773 305 363,199 1,449 2,576 29,923 8,119 297 26 250,959 575,000 525,000 200,000 (2,140) 1,297,860 575,000 525,000 200,000 (2,393) 1,297,607 277,440 54,395 30,533 4,635 16,204 383,207 2,044,266 238,293 16,800 36,369 5,651 2,252 299,365 1,847,931 871,121 374,983 (14,019) 1,232,085 $3,276,351 864,462 352,061 (21,401) 1,195,122 $3,043,053 The accompanying notes are an integral part of these financial statements. II-437 SoCo FOIA Response 002794 CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2010, 2009, and 2008 Southern Power Company and Subsidiary Companies 2010 Annual Report Number of Common Shares Issued Common Stock Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total (in thousands) Balance at December 31, 2007 Net income Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Other Balance at December 31, 2008 Net income Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2009 Net income Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2010 1 1 1 1 $$- $858,466 3,643 862,109 2,353 864,462 6,659 $871,121 $253,131 144,359 (94,500) (681) 302,309 155,852 (106,100) 352,061 130,022 (107,100) $374,983 $(33,710) 7,653 (26,057) 4,656 (21,401) 7,382 $(14,019) $1,077,887 144,359 3,643 7,653 (94,500) (681) 1,138,361 155,852 2,353 4,656 (106,100) 1,195,122 130,022 6,659 7,382 (107,100) $1,232,085 The accompanying notes are an integral part of these financial statements. II-438 SoCo FOIA Response 002795 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2010, 2009, and 2008 Southern Power Company and Subsidiary Companies 2010 Annual Report 2010 2009 2008 (in thousands) Net income Other comprehensive income (loss): Qualifying hedges: Changes in fair value, net of tax of $591, $(664), and $351, respectively Reclassification adjustment for amounts included in net income, net of tax of $3,894, $3,875, and $4,554, respectively Total other comprehensive income (loss) Comprehensive Income $130,022 938 6,444 7,382 $137,404 $155,852 $144,359 (1,044) 5,700 4,656 $160,508 529 7,124 7,653 $152,012 The accompanying notes are an integral part of these financial statements. II-439 SoCo FOIA Response 002796 NOTES TO FINANCIAL STATEMENTS Southern Power Company and Subsidiary Companies 2010 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Southern Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional operating companies, Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company (APC), Georgia Power Company (GPC), Gulf Power Company (Gulf Power), and Mississippi Power Company (MPC) – are vertically integrated utilities providing electric service in four Southeastern states. The Company constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC). The Company follows generally accepted accounting principles (GAAP). The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. The financial statements include the accounts of the Company and its wholly-owned subsidiaries, Southern Company – Florida LLC, Oleander Power Project, LP (Oleander), Southern Power Company – Orlando Gasification LLC (SPC-OG), and Nacogdoches Power LLC, which own, operate, and maintain the Company’s ownership interests in Plant Stanton Unit A and Plant Oleander, constructed the combined cycle for the Orlando Utilities Commission (OUC), and is constructing a biomass generating facility, respectively. All intercompany accounts and transactions have been eliminated in consolidation. Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations and Southern Company system fleet of generating units (power pool) transactions. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for these services from SCS amounted to approximately $103.4 million in 2010, $133.0 million in 2009, and $207.4 million in 2008. Approximately $89.2 million in 2010, $83.1 million in 2009, and $87.9 million in 2008 were operations and maintenance expenses; the remainder was recorded to construction work in progress, other assets, and billings in excess of cost on construction contract. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. Total billings for all power purchase agreements (PPAs) in effect with affiliates totaled $230.8 million, $485.1 million, and $539.6 million in 2010, 2009, and 2008, respectively. Included in these billings were $30.5 million and $36.4 million of “Deferred capacity revenues – affiliated” recorded on the balance sheets at December 31, 2010 and 2009, respectively. The Company and the traditional operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. The Company and the traditional operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. In January 2010, the Company sold turbine rotor assembly parts to Gulf Power for $6 million. In September 2010, the Company purchased turbine rotor assembly parts owned by GPC, Gulf Power, and MPC for approximately $4 million, $1 million, and $7 million, respectively. These affiliate transactions were made in accordance with FERC and state Public Service Commission (PSC) rules and guidelines. II-440 SoCo FOIA Response 002797 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report In 2009, there were no material transactions involving the sale of property to affiliated companies. In 2008, Gulf Power and APC sold turbine rotor assemblies to the Company for $9.4 million and $6.3 million, respectively. Additionally, the Company sold a turbine rotor assembly to APC for $8.2 million and sold a compressor assembly to GPC for $3.9 million. No gain or loss was recognized in the Company’s consolidated statements of income. These affiliate transactions were made in accordance with FERC and state PSC rules and guidelines. Acquisition Accounting The Company has been engaged in a strategy of acquiring assets. The Company has accounted for these acquisitions under the purchase method in accordance with GAAP. Accordingly, the Company has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price of each acquisition was allocated to the fair value of the identifiable assets and liabilities. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions have been expensed as incurred. Revenues The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 to the financial statements for further information. Energy is generally sold at market-based rates and the associated revenue is recognized as the energy is delivered. Transmission revenues and other fees are recognized as incurred as other operating revenues. Revenues are recorded on a gross basis for all full requirements PPAs. See “Financial Instruments” herein for additional information. Significant portions of the Company’s revenues have been derived from certain customers pursuant to PPAs. For the year ended December 31, 2010, GPC accounted for 17.7% of total revenues, Florida Power & Light accounted for 11.4%, and Progress Energy Carolina accounted for 8.2% of total revenues. For the year ended December 31, 2009, GPC accounted for 43.7% of total revenues, APC accounted for 6.6% of total revenues, and Sawnee Electric Membership Corporation accounted for 6.0% of total revenues. For the year ended December 31, 2008, GPC accounted for 36.5% of total revenues, Sawnee Electric Membership Corporation accounted for 6.1% of total revenues, and Flint Electric Membership Corporation accounted for 5.3% of total revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information. II-441 SoCo FOIA Response 002798 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Convertible Investment Tax Credits Under the American Recovery and Reinvestment Act of 2009, certain costs related to the Nacogdoches plant construction are eligible for investment tax credits (ITCs) or cash grants. The Company has elected to receive ITCs. The credits are recorded as a deferred credit, which will be amortized to income tax expense over the life of the asset, and the tax basis of the asset is reduced by 50% of the credits received, resulting in a deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period. This basis difference will reverse and be recorded to income tax expense over the useful life of the asset once placed in service. The credits received during the year are shown within operating activities in the consolidated statements of cash flows. Property, Plant, and Equipment The Company’s depreciable property, plant, and equipment consists entirely of generation assets. Property, plant, and equipment is stated at original cost. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, minor items of property, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred. Depreciation Depreciation of the original cost of assets is computed under the straight-line method and applies a composite depreciation rate based on the assets’ estimated useful lives determined by the Company. The primary assets in property, plant, and equipment are power plants, all of which have an estimated composite depreciable life ranging from 24-35 years. These lives reflect a composite of the significant components (retirement units) that make up the plants. The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. At December 31, 2010, the Company had no material liability for asset retirement obligations. Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets and intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company’s intangible assets consist of acquired PPAs that are amortized over the term of the PPA and goodwill resulting from acquisitions. The average term of these PPAs is 20 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. Impairment of goodwill is assessed on an annual basis. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is reevaluated when circumstances or events change. II-442 SoCo FOIA Response 002799 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The amortization expense for the PPAs is as follows: Amortization Expense (in millions) 2010 2011 2012 2013 2014 2015 and beyond Total $ $ 0.7 0.8 1.8 2.4 2.4 41.0 49.1 Deferred Project Development Costs The Company capitalizes project development costs once it is determined that it is probable that a specific site will be acquired and a power plant constructed. These costs include professional services, permits, and other costs directly related to the construction of a new project. These costs are generally transferred to construction work in progress upon commencement of construction. The total deferred project development costs were $9.6 million at December 31, 2010, $9.0 million at December 31, 2009, and $8.9 million at December 31, 2008. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average costs of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the cost of oil, natural gas, and emissions allowances. The Company maintains minimal oil levels for use at Plant Dahlberg, Plant Oleander, Plant Rowan, and Plant West Georgia. The Company has contracts in place for natural gas storage. These contracts help to ensure normal operations of the Company’s natural gas generating units. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 8 for additional information. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in other comprehensive income (OCI) until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. See Note 9 for additional information. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2010. II-443 SoCo FOIA Response 002800 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk. The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). See Note 8 for all other items recognized at fair value in the financial statements. Other Income and (Expense) Other income and (expense) includes non-operating revenues and expenses. Revenues are recognized when earned and expenses are recognized when incurred. The Company had a long-term contract for engineering, procurement, and construction services to build a combined cycle unit for the OUC. Construction activities commenced in 2006 and were substantially completed in 2009. Billings and costs are recognized using the percentage of completion method. The Company utilizes the cost-to-cost approach as this method is less subjective than relying on assessments of physical progress. The percentage of completion represents the percentage of the total costs incurred to the estimated total cost of the contract. Billings and costs are recognized on a net basis by applying this percentage to the total revenues and estimated costs of the contract and are recorded in other income and (expense) in the consolidated statements of income. Net profit recognized under the long-term construction contract for the OUC was $0.5 million in 2010 and $13.3 million in 2009. No profit or loss was recognized in 2008. In 2008, the Company received a fee of $6.4 million for participating in an asset auction. The Company was not the successful bidder in the asset auction. Interest related to the construction of new facilities is capitalized in accordance with GAAP. Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications of amounts included in net income. Variable Interest Entities Effective January 1, 2010, Southern Power adopted new accounting guidance which modified the consolidation model and expanded disclosures related to variable interest entities (VIE). The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Southern Power has certain wholly-owned subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. The adoption of this new accounting guidance did not result in the Company consolidating any VIEs that were not already consolidated under previous guidance, nor deconsolidating any VIEs. 2. ACQUISITIONS AND DIVESTITURES Nacogdoches Power LLC Acquisition In October 2009, the Company acquired all of the outstanding membership interests of Nacogdoches Power LLC (Nacogdoches) from American Renewables LLC, the original developer of the project. Nacogdoches is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 megawatts (MWs). The generating plant will be fueled from wood waste. Construction commenced in late 2009 and the plant is expected to begin commercial operation in 2012. The total estimated cost of the project is expected to be between $475 million and $500 million. The output of the plant is contracted under a PPA with Austin Energy that begins in 2012 and expires in 2032 or until a contractual limit of $2.3 billion is reached. This PPA will be accounted for as an operating lease. II-444 SoCo FOIA Response 002801 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The Company’s acquisition of the interests in Nacogdoches included cash consideration of approximately $50.1 million. The Nacogdoches acquisition is in accordance with the Company’s overall growth strategy. There are no contingent consideration arrangements and no significant assets or liabilities arising from contingencies. No goodwill was recorded as a result of this acquisition. An intangible asset related to the assumed PPA with Austin Energy was recognized. Due diligence and transition costs for Nacogdoches were expensed as incurred and were not material. The fair value of the consideration transferred and the fair value of each major class of assets and liabilities at the acquisition date was as follows: As of October 2009 (in millions) Construction work in progress Other assets Intangible assets Total fair value of the membership interests in Nacogdoches $16.2 0.1 33.8 $50.1 West Georgia Generating Company, LLC Acquisition In December 2009, the Company acquired all of the outstanding membership interests of West Georgia Generating Company, LLC (West Georgia) from Broadway Gen Funding, LLC (Broadway), an affiliate of LS Power. West Georgia was merged into the Company and the Company now owns a 669-MW nameplate capacity generating facility consisting of four combustion turbine natural gas generating units with oil back-up. The output from two units is contracted under PPAs with the Municipal Electric Authority of Georgia (MEAG Power) and the Georgia Energy Cooperative, Inc. (GEC). The MEAG Power agreement began in 2009 and expires in 2029. The GEC agreement began in 2010 and expires in 2030. The Company’s acquisition of the interests in West Georgia was pursuant to an agreement which included the transfer of all the outstanding membership interests of DeSoto County Generating Company LLC (DeSoto) from the Company to Broadway and the payment by the Company of $144.0 million in cash consideration. The carrying values of the major classes of assets disposed of were $2.0 million in fossil fuel stock, $1.2 million in materials and supplies, $72.1 million in property, plant, and equipment, and $0.8 million in other deferred assets. The transaction was treated as a like-kind exchange for income tax purposes. The West Georgia acquisition is in accordance with the Company’s overall growth strategy. There are no contingent consideration arrangements and no significant assets or liabilities arising from contingencies. The goodwill arising from the acquisition consists largely of synergies and economies of scale from combining the operations of the Company and West Georgia and is expected to be tax deductible. Due diligence and transition costs for West Georgia were expensed as incurred and were not material. The final fair value of the consideration transferred and the fair value of each major class of assets and liabilities at the acquisition date was as follows: As of December 2009 (in millions) Customer accounts receivable Fossil fuel stock Materials and supplies Property, plant, and equipment Other assets Goodwill Intangible assets (PPAs) Accounts payable Total fair value of the membership interests in West Georgia Fair value of DeSoto interests Cash consideration transferred $ 0.4 1.8 0.9 192.4 2.5 1.8 15.3 (0.3) 214.8 (70.8) $ 144.0 Revenues and expenses recognized by the Company for West Georgia operations after the closing date were not material. PPA amortization expense for 2009 was not material. II-445 SoCo FOIA Response 002802 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Pro Forma Information The following unaudited pro forma financial information gives effect to the Nacogdoches acquisition, the West Georgia acquisition, and the DeSoto divestiture as if they had occurred as of the beginning of the periods presented. The pro forma financial information is not intended to represent or be indicative of the consolidated results of operations or financial condition of the Company that would have been reported had the acquisitions and divestiture been completed as of the dates presented nor should the information be taken as representative of any future consolidated results of operations or financial condition of the Company. For the Twelve Months Ended December 31 2009 2008 (in millions) Pro forma revenues Pro forma net income $ 957.4 151.1 $1,353.3 146.6 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property and other damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. FERC Matters The majority of the Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a proceeding to examine certain aspects of the IIC, the operation of the power pool, and the Company’s compliance with various regulatory requirements. In 2006, the proceeding was resolved pursuant to the terms of an order on settlement issued by the FERC. In 2007, the FERC approved, with certain modifications, a compliance plan submitted by Southern Company in connection with the settlement order. In 2008, the FERC division of audits issued its final audit report pertaining to compliance implementation and related matters. On December 29, 2010, the FERC accepted the audit report finding the Company to be in full compliance with the terms of the settlement order and terminated the proceeding. This matter is now concluded. Income Tax Matters The Company submitted a change in the tax accounting method for repair costs associated with the Company’s generation assets with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $6 million for the Company. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. The ultimate outcome of this matter cannot be determined at this time. II-446 SoCo FOIA Response 002803 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Carbon Dioxide Litigation Kivalina Case In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in a similar case. The ultimate outcome of this matter cannot be determined at this time. Other Litigation Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the Kivalina case, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. 4. JOINT OWNERSHIP AGREEMENTS The Company is a 65% owner of Plant Stanton A, a combined-cycle project with a nameplate capacity of 630 MWs. The unit is coowned by the OUC (28%), Florida Municipal Power Agency (3.5%), and Kissimmee Utility Authority (3.5%). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2010, $155.9 million was recorded in plant in service with associated accumulated depreciation of $24.8 million. These amounts represent the Company’s share of the total plant assets and each owner is responsible for providing its own financing. The Company’s proportionate share of Plant Stanton A’s operating expense is included in the corresponding operating expenses in the statements of income. 5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined tax returns for the State of Georgia, the State of Alabama, and the State of Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. II-447 SoCo FOIA Response 002804 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Current and Deferred Income Taxes Details of income tax provisions are as follows: 2009 2010 2008 (in millions) Federal – Current Deferred $ State – Current Deferred Total $ 36.1 21.1 57.2 6.7 12.9 19.6 76.8 $ $ 55.0 19.3 74.3 7.7 3.7 11.4 85.7 $ $ 18.9 57.2 76.1 3.6 13.2 16.8 92.9 The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, were as follows: 2009 2010 (in millions) Deferred tax liabilities– Accelerated depreciation and other property basis differences Basis difference on asset transfers Other Total Deferred tax assets– Federal effect of state deferred taxes Net basis difference on convertible investment tax credits Basis differences on asset transfers Other comprehensive loss on interest rate swaps Levelized capacity revenues Other Total Total deferred tax liabilities, net Portion included in current income taxes Accumulated deferred income taxes $ 348.8 3.5 352.3 18.4 9.5 5.9 24.4 12.7 3.4 74.3 278.0 (0.6) $ 277.4 $ $ 303.9 3.9 307.8 13.7 2.9 6.7 28.1 15.2 1.7 68.3 239.5 (1.2) 238.3 Deferred tax liabilities are the result of property related timing differences. The transfer of the Plant McIntosh construction project to GPC in 2004 resulted in a deferred gain for federal income tax purposes. GPC is reimbursing the Company for the related tax liability balance of $3.5 million. Of this total, $0.3 million is included in the balance sheets in “Receivables – Affiliated companies” and the remainder is included in “Other deferred charges and assets – affiliated.” Deferred tax assets consist primarily of timing differences related to the recognition of capacity revenues and the deferred loss on interest rate swaps reflected in OCI. The transfer of Plants Dahlberg, Wansley, and Franklin to the Company from GPC in 2001 also resulted in a deferred gain for federal income tax purposes. The Company will reimburse GPC for the related tax asset of $5.9 million. Of this total, $1.3 million is included in the balance sheets in “Accounts payable – Affiliated” and the remainder is included in “Other deferred credits and liabilities – affiliated.” II-448 SoCo FOIA Response 002805 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013). The application of the bonus depreciation provisions in these acts in 2010 significantly increased deferred tax liabilities related to accelerated depreciation. Effective Tax Rate A reconciliation of the federal statutory rate to the effective income tax rate is as follows: Federal statutory rate State income tax, net of federal deduction ITC basis difference Other Effective income tax rate 2010 35% 6.2 (3.4) (0.7) 37.1 2009 35.0% 3.1 (1.2) (1.4) 35.5% 2008 35.0% 4.6 (0.4) 39.2% The Company’s effective tax rate increased primarily as a result of an increase in Alabama state taxes. Alabama’s state tax liability is reduced by a deduction for federal income taxes paid. Due to increased bonus depreciation and incentives associated with new plant construction, the federal tax liability was significantly reduced, resulting in a higher overall state tax expense. Also contributing to the increase in state taxes was the application of the resulting higher state tax rate to the deferred income tax balance. Convertible ITCs received in 2010 for the construction of Plant Nacogdoches were $26.4 million; the tax benefit of the basis difference reduced income tax expense by $6.9 million. See Note 1 under “Convertible Investment Tax Credits” for additional information. Convertible ITCs received in 2009 for the construction of Plant Nacogdoches were $16.8 million; the tax benefit of the basis difference reduced income tax expense by $2.9 million. Unrecognized Tax Benefits For 2010, the total amount of unrecognized tax benefits increased $2.2 million, resulting in a balance of $2.3 million as of December 31, 2010. Changes during the year in unrecognized tax benefits were as follows: 2010 2009 2008 (in millions) Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions from prior periods Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year $ 0.1 0.7 1.5 $ 2.3 $ 0.5 0.3 (0.7) $ 0.1 $ 1.4 0.3 0.1 (1.3) $ 0.5 The tax positions increase from current and prior periods relate primarily to the tax accounting method change for repairs and other miscellaneous uncertain tax positions. See Note 3 under “Income Tax Matters” for additional information. II-449 SoCo FOIA Response 002806 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The impact on the Company’s effective tax rate, if recognized, is as follows: 2010 2009 2008 (in millions) Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits $ 0.6 1.7 $ 2.3 $ 0.1 $ 0.1 $ 0.5 $ 0.5 The tax positions impacting the effective tax rate primarily relate to miscellaneous uncertain tax positions. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note 3 under “Income Tax Matters” for additional information. Accrued interest for unrecognized tax benefits was as follows: 2010 2009 2008 (in millions) Interest accrued at beginning of year Interest reclassified due to settlements Interest accrued during the year Balance at end of year $ $ - $ $ - $ 0.1 (0.1) $ - The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. The IRS has audited and closed all tax returns prior to 2007. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006. 6. FINANCING Senior Notes In 2010 and 2009, the Company did not issue or redeem any long-term debt securities. Long-term debt outstanding was $1.3 billion at December 31, 2010 and 2009. Bank Credit Arrangements The Company has a $400 million unsecured syndicated revolving credit facility (Facility) expiring in July 2012. The purpose of the Facility is to provide liquidity support to the Company’s commercial paper program and for other general corporate purposes. There were no borrowings outstanding under the Facility at December 31, 2010 and 2009. The Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/ 10 of 1%. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65%. The Facility also contains a cross default provision that would be triggered if the Company defaulted on other indebtedness above a specified threshold. As of December 31, 2010, the Company was in compliance with all such covenants. II-450 SoCo FOIA Response 002807 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The Company’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. During 2010, the Company had an average of $169 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $259 million. At December 31, 2010, the Company had $204 million of commercial paper outstanding. During 2009, the Company had an average of $7 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum. At December 31, 2009, the Company had $119 million of commercial paper outstanding. The maximum amount outstanding during 2009 was $119 million. Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. The Facility and the indenture related to certain series of the Company’s senior notes also contain certain limitations on the payment of common stock dividends. No dividends may be paid unless, as of the end of any calendar quarter, the Company’s projected cash flows from fixed priced capacity PPAs are at least 80% of total projected cash flows for the next 12 months or the Company’s debt to capitalization ratio is no greater than 60%. At December 31, 2010, the Company was in compliance with these ratios and had no other restrictions on its ability to pay dividends. 7. COMMITMENTS Expansion Program The capital program of the Company is currently estimated to be $540 million for 2011, $144 million for 2012, and $37 million for 2013. These amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and the Company’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. Long-Term Service Agreements The Company has entered into long-term service agreements (LTSAs) with General Electric and Siemens AG for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. In summary, the LTSAs provide that the vendors will perform all planned inspections and certain unplanned maintenance on the covered equipment, which includes the cost of all labor and materials. Scheduled payments to the vendors, which are subject to price escalation, are made at various intervals based on actual operating hours or number of gas turbine starts of the respective units. Total remaining payments to the vendors under these agreements are currently estimated at $1.1 billion over the remaining term of the agreements, which may range up to 23 years. However, the LTSAs contain various cancellation provisions at the Company’s and the applicable vendor’s option. In the event of cancellation prior to scheduled work being performed, the Company is entitled to a refund of amounts paid as calculated in accordance with termination provisions of the agreements. Payments made to the vendors prior to the performance of any planned inspections or unplanned maintenance are recorded as a prepayment in current assets or deferred charges and other assets on the balance sheets and are recorded as payments pursuant to longterm service agreements in the statements of cash flows. All work performed is capitalized or charged to expense as appropriate based on the nature of the work when performed; therefore, these charges are non-cash and are not reflected in the statements of cash flows. Fuel and Purchased Power Commitments SCS, as agent for the traditional operating companies and the Company, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities. In most cases, these contracts contain provisions for firm transportation costs, storage costs, minimum purchase levels, and other financial commitments. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on the New York Mercantile Exchange future prices at December 31, 2010. Also, the Company has entered into various long-term commitments for the purchase of biomass fuel for the biomass generating plant being constructed by the Company and for the purchase of electricity. II-451 SoCo FOIA Response 002808 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report Total estimated minimum long-term commitments at December 31, 2010 were as follows: Natural Gas Commitments Biomass Fuel Commitments Purchased Power Commitments(a) (in millions) 2011 2012 2013 2014 2015 2016 and beyond Total (a) $ $ 338.2 284.5 201.4 154.8 140.4 229.2 1,348.5 $ 14.5 17.5 17.8 18.2 110.0 178.0 $ $ $ 7.8 49.2 50.4 51.6 53.5 241.7 454.2 Represents contractual capacity payments. Additional commitments for fuel will be required to supply the Company’s future needs. The Company has entered into agreements to purchase 380 MWs of power from two counterparties. Approximately 280 MWs of the commitment obligations from one counterparty will be used to serve the Company’s requirements service customers. Another agreement for 100 MWs will be resold to EnergyUnited Electric Membership Corporation (EnergyUnited) at cost for the period 2012 through 2021. The purchase power commitments for the EnergyUnited agreement are $35.4 million in 2012, $36.1 million in 2013, $36.8 million in 2014, $37.6 million in 2015, and $241.7 million in 2016 and beyond. In addition, the Company has entered into an agreement to purchase power of up to 200 MWs at the discretion of the counterparty for the period 2011 through 2018. There is no contractual capacity payment required under this agreement. Additionally, for all amounts purchased under this arrangement, the Company will pay the counterparty an amount per MW which approximates the Company’s cost. Acting as an agent for all of Southern Company’s traditional operating companies and the Company, SCS may enter into various types of wholesale energy and natural gas contracts. Under these agreements, each of the traditional operating companies and the Company may be jointly and severally liable. The creditworthiness of the Company is currently inferior to the creditworthiness of the traditional operating companies; therefore, Southern Company has entered into keep-well agreements with each of the traditional operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of the Company as a contracting party under these agreements. Operating Leases The Company has operating lease agreements with various terms and expiration dates. Total operating lease expenses were $0.5 million, $0.5 million, and $0.5 million for 2010, 2009, and 2008, respectively. The majority of the lease expense amounts and committed future expenditures are with a joint owner of Plant Stanton Unit A. At December 31, 2010, estimated minimum lease payments for noncancelable operating leases were as follows: Operating Lease Commitments (in millions) 2011 2012 2013 2014 2015 2016 and beyond Total $ $ 0.5 0.5 0.5 0.5 0.4 22.3 24.7 II-452 SoCo FOIA Response 002809 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report 8. FAIR VALUE MEASUREMENTS Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.    Level 1 consists of observable market data in an active market for identical assets or liabilities. Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. The need to use unobservable inputs would typically apply to long-term energy-related derivative contracts and generally results from the nature of the energy industry, as each participant forecasts its own power supply and demand and those of other participants, which directly impact the valuation of each unique contract. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) As of December 31, 2010: Total (in millions) Assets: Energy-related derivatives Cash equivalents Total Liabilities: Energy-related derivatives $ 7.2 $7.2 $ 2.8 $ 2.8 $$- $ 2.8 7.2 $10.0 $ - $ 6.2 $- $ 6.2 Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and London Interbank Offered Rate interest rates. See Note 9 for additional information on how these derivatives are used. As of December 31, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: As of December 31, 2010: Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period None Daily Not applicable (in millions) Cash equivalents: Money market funds $7.2 II-453 SoCo FOIA Response 002810 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the Securities and Exchange Commission and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company’s investment in the money market funds. As of December 31, 2010 and 2009, other financial instruments for which the carrying amount did not equal fair value were as follows: Carrying Amount Fair Value (in millions) Long-term debt: 2010 2009 $1,298 $1,298 $1,378 $1,379 The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). 9. DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities. Energy-Related Derivatives The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. The Company has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. Energy-related derivative contracts are accounted for in one of two methods:   Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges, which are used to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. II-454 SoCo FOIA Response 002811 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report At December 31, 2010, the net volume of energy-related derivative contracts for power and natural gas positions for the Company, together with the longest hedge date over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Net Sold Megawatthours Power Longest Hedge Date Longest Non-Hedge Date 2011 2011 Net Purchased mmBtu* (in millions) 0.9 Gas Longest Hedge Date Longest Non-Hedge Date 2012 2015 (in millions) 13 *million British thermal units In addition to the volumes discussed in the table above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is immaterial. For the next 12-month period ending December 31, 2011, the Company expects to reclassify $1.0 million in losses from OCI to fuel expense with respect to cash flow hedges. Interest Rate Derivatives The Company also enters into interest rate derivatives from time to time to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges, where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. At December 31, 2010, there were no interest rate derivatives outstanding. The estimated pre-tax loss that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2011 is $11.5 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2016. Derivative Financial Statement Presentation and Amounts At December 31, 2010 and 2009, the fair value of energy-related derivatives was reflected in the balance sheets as follows: Asset Derivatives Derivative Category Balance Sheet Location Liability Derivatives 2010 2009 Balance Sheet Location (in millions) Derivatives designated as hedging instruments in cash flow hedges Energy-related derivatives: Assets from risk management activities Other deferred charges and assets – non-affiliated Total derivatives designated as hedging instruments in cash flow hedges Derivatives not designated as hedging instruments Energy-related derivatives: Assets from risk management activities Other deferred charges and assets – non-affiliated $ 0.1 $ 3.2 - - $ 0.1 $ 3.2 $ 2.1 $ 1.7 2010 2009 (in millions) Liabilities from risk management activities Other deferred credits and liabilities – non-affiliated Liabilities from risk management activities Other deferred credits and liabilities – non-affiliated $ 1.0 - $ 5.3 0.4 $ 1.0 $ 5.7 $ 4.8 $ 2.8 0.4 0.1 0.6 0.2 Total derivatives not designated as hedging instruments $ 2.7 $ 1.9 $ 5.2 $ 2.9 Total $ 2.8 $ 5.1 $ 6.2 $ 8.6 II-455 SoCo FOIA Response 002812 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report All derivative instruments are measured at fair value. See Note 8 for additional information. For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Derivative Category 2010 2009 2008 Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Amount Statements of Income 2009 2008 Location 2010 (in millions) (in millions) Energy-related derivatives Interest rate derivatives $1.5 - $(1.7) - $0.9 - Total $1.5 $(1.7 ) $0.9 Depreciation and amortization Interest expense, net of amounts capitalized $ 0.4 $ 0.4 $ 0.4 (10.8) $(10.4) (10.0) $ (9.6) (12.0) $(11.6) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2010, 2009, and 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was as follows: Derivatives not Designated as Hedging Instruments Derivative Category Unrealized Gain (Loss) Recognized in Income Amount 2009 Statements of Income Location 2010 2008 (in millions) Energy-related derivatives: Wholesale revenues, non-affiliates Fuel Purchased power, non-affiliates Total $(1.5) 0.7 (0.7) $(1.5) $ 5.3 (6.0) (4.5) $(5.2) $(1.9) 5.1 (2.3) $ 0.9 Contingent Features The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2010, the fair value of derivative liabilities with contingent features was $2.6 million. At December 31, 2010, the Company had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-riskrelated contingent features, at a rating below BBB- and/or Baa3, is $40.0 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. II-456 SoCo FOIA Response 002813 NOTES (continued) Southern Power Company and Subsidiary Companies 2010 Annual Report 10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2010 and 2009 is as follows: Quarter Ended Operating Revenues Operating Income Net Income (in thousands) March 2010 June 2010 September 2010 December 2010 $ 256,488 248,476 356,830 267,351 $ 43,928 59,131 111,925 67,810 $ 14,810 29,704 61,694 23,814 March 2009 June 2009 September 2009 December 2009 $ 231,517 230,598 283,369 201,168 $ 66,981 73,276 127,165 46,134 $ 27,916 31,054 67,280 29,602 The Company’s business is influenced by seasonal weather conditions. Fourth quarter 2009 net income includes profit recognized on the OUC construction contract of $10.6 million pretax and $6.5 million after tax. II-457 SoCo FOIA Response 002814 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2006-2010 Southern Power Company and Subsidiary Companies 2010 Annual Report Operating Revenues (in thousands): Wholesale - non-affiliates Wholesale - affiliates Total revenues from sales of electricity Other revenues Total Net Income (in thousands) Cash Dividends on Common Stock (in thousands) Return on Average Common Equity (percent) Total Assets (in thousands) Gross Property Additions/Plant Acquisitions (in thousands) Capitalization (in thousands): Common stock equity Long-term debt Total (excluding amounts due within one year) Capitalization Ratios (percent): Common stock equity Long-term debt Total (excluding amounts due within one year) Kilowatt-Hour Sales (in thousands): Wholesale - non-affiliates Wholesale - affiliates Total Average Revenue Per Kilowatt-Hour (cents) Plant Nameplate Capacity Ratings (year-end) (megawatts) Maximum Peak-Hour Demand (megawatts): Winter Summer Annual Load Factor (percent) Plant Availability (percent) Source of Energy Supply (percent): Gas Purchased power From non-affiliates From affiliates Total 2010 2009 2008 2007 2006 $751,575 370,630 1,122,205 6,940 $1,129,145 $130,022 $394,366 544,415 938,781 7,870 $946,651 $155,852 $667,979 638,266 1,306,245 7,296 $1,313,541 $144,359 $416,648 547,229 963,877 8,137 $972,014 $131,637 $279,384 491,762 771,146 5,902 $777,048 $124,469 $107,100 10.71 $3,276,351 $299,602 $ 106,100 13.36 $3,043,053 $331,289 $ 94,500 13.03 $2,813,140 $49,964 $ 89,800 12.52 $2,768,774 $139,198 $ $1,232,085 1,297,860 $2,529,945 $1,195,122 1,297,607 $2,492,729 $1,138,361 1,297,353 $2,435,714 $1,077,887 1,297,099 $2,374,986 $1,025,504 1,296,845 $2,322,349 48.7 51.3 100.0 47.9 52.1 100.0 46.7 53.3 100.0 45.4 54.6 100.0 44.2 55.8 100.0 13,285,465 10,494,339 23,779,804 4.72 7,880 7,513,569 12,293,585 19,807,154 4.74 7,880 7,573,713 9,402,020 16,975,733 7.69 7,555 6,985,592 10,766,003 17,751,595 5.43 6,896 5,093,527 8,493,441 13,586,968 5.68 6,733 3,295 3,543 54.0 94.0 3,224 3,308 52.6 96.7 3,042 3,538 50.0 96.0 2,815 3,717 48.2 96.7 2,780 2,869 53.6 98.3 88.8 84.4 75.6 70.4 68.3 5.5 5.7 100.0 7.9 7.7 100.0 11.3 13.1 100.0 8.8 20.8 100.0 9.6 22.1 100.0 77,700 13.16 $2,690,943 $465,026 II-458 SoCo FOIA Response 002815 From: Sent: To: Subject: Attachments: Friday, July 29, 201112:09 PM Robbins, Brittley K.; Madden, Diane R. Award: DEFC2606NT42391, Progress Report Period Ending: 6/30/2011 {42391PR_Q063011) 42391PR_Q063011.pdf Subject: Distribution of Progress Report ContracVGranVCooperative Agreement No. DEFC2606NT42391 with Southern Company Services Inc Period Ending 6/30/2011 The attached report has been submitted by the contractor/recipient and received into FITS. This is the formal distribution for the deliverable, since this is an electronic only award. Thank you, Susan Olson SoCo FOIA Response 002816 Demonstration of a Coal Based Transport Gasifier: 2011 Second Quarter Technical Status Report Period Covered by Report: 4/0 I /20 II - 6/30/20 I I Project Manager: Tim Pinkston Date of Report: July 22"d, 20 II Project: DE-FC26-06NT42391 Submitting Organization: Southern Company Services, Inc. 42 Inverness Center Parkway Bin B228 Birmingham, AL 35242 This progress report was prepared with the support of the U.S. Department of Energy, an agency of the United States Government, under Award Number DE-FC26-06NT42391. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. SoCo FOIA Response 002817 Project Management The following are major project milestones: • • • • • • Project is on schedule and on budget. 54% of the Certified Plant costs have been confirmed. Acquisition of the transmission right-of-way approximately 76% complete. The second I I SkY line rebuild project is 90% complete. Construction, engineering and detail design are progressing as scheduled. On March 4th, 20 II Mississippi Power and Denbury Onshore entered into an agreement in which Denbury will purchase 70% of the C02 captured from the project. On Aprill9, 201 I, Mississippi Power received notification from the IRS certifying the allocated Internal Revenue Code Section of 48A tax credits (Phase II) of $279 million to Mississippi Power. On May 19,201 I, Mississippi Power and Treetop Midstream Services, LLC (Treetop), entered into an agreement in which Treetop will purchase 30% of the C02 captured from the Kemper Project. Treetop is an affiliate ofTellus Operating Group, LLC and a subsidiary ofTenrgys, LLC. Permits and Approvals The permit and approval status is shown below: Description Status Submittal Aeeroval State Groundwater Test Well Permit MS-GW-16425 Approved 5/30/2007 6126/2007 State NPDES Stormwater Run-off Permit MSR104866 Approved 11/13/2007 3/12/2010 State PSD Air Permit 1380-00017 Approved 12/20/2007 3/12/2010 State Groundwater Production Well Permit MS-GW16425 MPSC Certificate Approved 5/21/2008 6/24/2008 Approved 1/16/2009 6/3/2010 Approved 11/19/2009 3/12/2010 State Permit to Operate Wastewater Disposal System wino Discharge Permit MSU009005 State Dam Safety Approval App. No. 09-041 Approved 12/1/2009 3/23/2010 State Dam Safety Approval App. No. 09-040 Approved 12/1/2009 3/23/2010 8/19/2010 DOE NEPA ROD (CCPI2) Approved 11/6/2009 State 401 Water Quality Certification Approved 10/27/2009 9/14/2010 USACE 404 Permit for Wetlands SAM-2009·01149-DMY Approved 10/27/2009 11/18/2010 Pending 6/11/2010 State Solid Waste Management Permit FAA Stack Permit Approved 2/8/2011 State Dam Safety - Make-up Reservoir NPDES Emergency Discharge Permit- Make-up reservoir NPDES Baseline Industrial Storm Water General Permit Application 10/3/2011 Application 10/3/2011 Application 4/1/2013 Title V Acid Rain Permit Application 2014 Title V Operating Permit Application 2014 3/14/11 Note: Dates in bold are actual dates, others are forecast dates 2 SoCo FOIA Response 002818 • The Mississippi Department of Environmental Quality (MDEQ) issued the final PSD permit on March 9, 20 I0. On April 2, 2010, Sierra Club filed a notice of appeal of the final air permit and request for an evidentiary hearing. The Harrison County Chancery Court affirmed the Commission's orders authorizing the construction of the Kemper Project. On March I, 20 II, the Sierra Club appealed the Chancery Court's decision to the Mississippi Supreme Court. Meanwhile, the Mississippi Department of Environmental Quality Permit Board held an evidentiary hearing on the Kemper Project Prevention of Significant Deterioration (PSD) air permit. The Board unanimously affirmed the existing PSD permit. On June 30, 20 II Sierra Club filed a form notice of appeal to challenge the MDEQ permit board's decision upholding the Kemper PSD permit in Chancery Court of Mississippi County. • On March I 01\ 20 II the Sierra Club filed suit against the Department of Energy regarding the Kemper Project' s NEPA review process, asking for a stay on the issuance ofCCPI2 funds and a stay to any related construction activities. Mississippi Power was granted intervenor status and pleadings were filed by DOE, Sierra Club and Mississippi Power. • In June 2010, an application to construct and operate a solid waste (gasification ash) management facility was submitted to the MDEQ. MDEQ issued notice to MPC on March 2, 2011 that the application was considered complete and that a draft permit will be issued shortly for review and comment. Engineering/Construction Detailed engineering started after the regulatory certification process was completed on May 26,2010. Currently, engineering and detail design are progressing as scheduled. A summary of the engineering tasks is listed below. • • • • • • • Engineering continued to issue equipment and material inquires, receive and evaluate bids, issue purchase orders, and approve contracts. Detailed design remained on schedule. Engineering held a Safety Integrity Level (SIL) Determination Review for the process. Engineering issued conduit and grounding drawings. Engineering continued to issue foundation and piling drawings. The second stage of review for the plant 3D model began, including extensive review of the gasifier structure, acid gas removal, sour water treatment, and compressor areas. Kickoff meetings for the following systems were held with the respective vendors: • Selexol Solvent Pumps. • Selexol Refrigeration System. • C02 and Natural Gas Pipeline. • Gasifier Control System Building. 3 SoCo FOIA Response 002819 • • • • • • • • • • Work is complete for the first two phases of major earthwork with the main plant area and construction laydown areas prepared. The third phase, in the reservoir area, progresses with approximately 285,000 cubic yards hauled to date. Work proceeds on the installation of the fire protection piping and area sumps. The concrete pour is complete for sumps in the gasifier, steam turbine, acid gas removal, wet sulfuric acid, and compressor areas. 5,174 Iinear feet of fire protection piping has been installed. Construction continued to install drainage ditches and concrete culverts. 37 storm drain inlets and 4,448 linear feet of storm drain piping has been installed to date. Construction continues to install the circulating water and closed loop cooling water piping. Approximately I 4,294 linear feet of circulating water piping is in place. Installation continued for the power duct banks. A total of I I 6,588 linear feet of duct bank has been installed to date. A total of 14,635 linear feet of electrical cable has been pulled to date. Auger cast piling installation continued. Installation is over 20% complete. Piling should be complete by March of 20 I 2. Caisson installation is approximately 28% complete. Concrete and underground work is underway with 6,200 cubic yards poured. The underground piping installation is 5% complete. The installation of the construction trailer offices is complete and occupied by Southern Company Construction Services. Procurement The following inquiry packages are in development stage: • WGS Startup Heater. The following inquiry packages have been issued for bids: • Anhydrous Ammonia Retlux Makeup Pump. • Condensate Makeup Pumps. • Static Mixers. • Mercury Adsorber Fill Material. • High Pressure Flare Knockout Drums. The following inquiry packages are in bid evaluation stage: • Various Instrumentation Packages. • Operations Training Simulator. • Water Analysis Building. • Auxiliary Boiler Makeup Water Pumps. • Ammonia and Sulfuric Acid Loading Stations. • Scrubber Water Pumps. • Intake Water Pumps. • Low Pressure Condensate Drum Vent Condenser. • Sample Stations. • Fuel Oil Forwarding Pumps. 4 SoCo FOIA Response 002820 Contract negotiations are underway for the following items: • Process Air Compressors. • Air Separation Unit Compressors. • Extraction Air Compressors. • Recycle Gas Compressors • C02 Dehydration Package. • Transport Air Dryers. • Wet Sulfuric Acid Process Equipment. • Ammonia Pumps. • C02 Compressors. • Quench/Scrubber Columns. • Wet Electrostatic Precipitator. • WSA Waste Heat Steam Generator. • Gasifier Bottoms Drain Pot Feeder. • Selexol Refrigeration Package. • WGS Catalyst. • C02 Recycle Compressor. • LP Vent Gas Compressor. • Transport Air Compressor. • Selexol High and Medium Pressure C02 Flash Drums. • Selexol Miscellaneous Heat Exchangers. • HRSG Feed Water Pumps. • COS Hydrolysis Catalyst. • Selexol Flash, Knockout, and Reflux Drums. • Gas Analyzer System and Shelters. • Coal Feeder Lock and Dispense Vessels. • Nitrogen Generator. • Low and Medium Pressure C02 Knockout Drums. • Freight and Personnel Elevators. • Flare System. • Gasifier Island Auxiliary Circulating Water Pumps. • Coal Drying System Filter Press. • Stack Gas and Cooling Air Blowers. • Cyclonic Baghouse. • Selexol Solvent Filtration Package. • Field Erected Tanks. • PCD Vessels. • Venturi Scrubbers. • Steam Slowdown Tanks. • Flash Gas Compressor. • Selexol Column Internals. • Water-Gas-Shift Reactors. • Water and Wastewater Treatment Package. • Sourwater Column Internals. 5 SoCo FOIA Response 002821 • • • • • • • • • • • • • • • • • Nitrogen Accumulators. WSA Combustor. Pyrite Discharge System. Wastewater Carbon Bed Filter. CCAD Vent Filter. WSA Stack. CCAD Steam Drum and Condenser. Sump Pumps. Combined Cycle Auxiliary Circulating Water Pumps. COS Hydrolysis Vessels. Low Pressure Condensate Pump. Fuel Oil Loading Package. Sewage Treatment Systems. CCAD Primary Cooler. CCAD Upper Secondary Cooler. Ash Vents. CCAD Lower Secondary Cooler. The following contracts have been signed by both parties: • Steam Turbine. • Gasifiers. • Gas Turbines. • Syngas Coolers. • Building Architectural Package. • HRSGs. • Auxiliary Boiler. • Condensate Pumps. • Fluidized Bed Dryers. • Air Heater and Ammonia Vaporizer. • Nitrogen Surge Drums. • Syngas and Ammonia Scrubbers. • Condenser/Vacuum Pumps. • Selexol Antifoam Injection Package. • Combined Cycle Circulating Water Pumps. • Wastewater Drum. • Process Condensate and Transport Air Compressor Knockout Drums. • Selexol Makeup Water Pumps. • Cooling Towers. • Cartridge Filters. • Wastewater Reflux Drums. • Crushed Coal Feeders. • Packinox Heat Exchangers. • PCD Fines Receivers. • Selexol Flash Gas Compressor Coolers. 6 SoCo FOIA Response 002822 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • Selexol Solvent Makeup Filter. Selexol Sump, Reflux, and Filtration Pumps. Coal Mills. Selexol Chillers. Flare Knockout Drum Pumps. Sourwater Separation Columns. Sourwater Pumps. Filtrate Pumps. Coal Feeder Storage Bins. Coal/Ash Silos. Gasifier Cooling Water Heat Exchangers. Flare Knockout Drums. Hydrogen Peroxide System. Tempered Water Heat Exchangers. Medium Pressure Steam Drum. Mercury Adsorbers. Selexol Regenerators, Concentrators, and C0 2 Absorbers. Plant DCS. Particulate Control Device Tubesheets. Fuel Gas Heat Exchanger. Combined Cycle Closed Loop Cooling Water Heat Exchanger. Selexol Sump and Water Break Drums. Fluidized Bed Discharge Feeders. Ash Moisturizer. PLD Vent Gas Drums. Light Hydrocarbon Drain Pots. Coal/Ash Pressure Let-Down Devices. Extraction Air and Recycle Gas Compressor Knockout Drums. Ammonia Product Drums. Hydrocarbon Drain Drum. Gasifier Island Closed Loop Cooling Water Pumps. Selexol H2S Absorbers. Surge Drum Agitator. Gasifier Island Circulating Water Pumps. High Pressure Makeup Water Pumps. Gasifier Startup Burners. WSA Combustion Air Blower. Selexol Solvent Pumps. Tempered Water Drums. Tempered Water Circulation Pump. Gas Cleanup Area Heat Exchangers. Transport Air Cooler. Gasifier Control Systems Buildings. Coal Mill Feed Fan. 7 SoCo FOIA Response 002823 • • • • • • • • • • • • • Coal Dryer Feed Gas Fan. Pyrite Bucket Elevator. Combined Cycle Closed Loop Cooling Water Pumps. WSA S02 Converter. WSA Acid Pumps. Caustic and Diesel Tanks. Oversized Pressure Vessels. Safety Instrumented System. Venturi Scrubber Pump-Around Coolers. Multiclone Discharge Drag Conveyors. Multiclone. Pyrite Screw Conveyors. SAT and GSU Transformers. 8 SoCo FOIA Response 002824 From: Sent To: Cc: Subject: Attachments: "Templeton, John D." Thursday, October 13, 2011 3:37 PM 'Cindy.J.House-Pearson@usace.army.mil'; Whyte, Cliff D.; Young ', 'Damon M SAM; Sanborn', 'Judd; 'KCarleton@choctaw.org'; Madden, Diane R.; (b) (4), (b) (6) 'olinwi lliams@choctawnation.com'; Lieb', 'Pamela Edwards; Hargis. Richard; (Stan_Thieling@deq.state.ms.us)', 'Stan Thieling; Pinkston, Tim E. Berry, Charles Rick (MPC) Kemper County IGCC Project - Annual Review of Programmatic Agreement PA Review 2011· 10-12v2.pdf AllAttached is the presentation from our net meeting yesterday. It was necessary to remove some of the graphics in order to reduce the file to a manageable size. If you have any questions, please let me know. John John Templeton Senior Environmental Specialist Mississippi Power Company PO Box 4079 Gulfport, MS 39502-4079 Ofc: 228-897-4332 Cell: (b) (6) jdtemple@southernco.com This electron.c message may con rain information chat is confidential or legally privileged Ills intended only for tile use of tile lndiVidual(s} and ent1ty named o~ recipients in the message If you ore nor on Intended recipient of !his message please notify the sender immedootely and de/ere the maleflol from any compuler Do not deliver, dislflbule. or copy 1h1s messog~. and do not disclose irs contenrs or toke any action In rehance on !he information il contains Thank you SoCo FOIA Response 002825 Yearly Review of Programmatic Agreememt Kemper County IGCC Project M 55 55 pp A October 201.?! POWER SOUTH [Trmf [h?HTi-?Il Alhamch 5- AltUr?rle-Cii?nt Fri-adv Company arid Southern CLianumny SoCo FOIA Response 002826 Project - Overview • Plant: 582MW • Technology: Integrated Gasification Combined Cycle • Fuel: Mississippi Lignite • MPC Investment: -$2.48 • C02 Capture: 65% • In-service: May 2014 • Water: Meridian Waste Water I< em per Co LJrlty ICCC Pmjcct M1ss1ss1~~\~ ........ "·-· ~ · · SoCo FOIA Response 002827 Infrastructure Transmission C02 Pipeline Natural Gas Pipeline Water Pipeline . =--cc:'"'" __ Plant Site -_,~=~Lr """"""' - - .....:tt4!11r ..lt!"' • JOTII * Mine Study Area SoCo FOIA Response 002828 Plant • Construction officially began June 2010 • Have moved almost 7 million tons of dirt • Approximately 300 employees and contractors on-site • On schedule to meet May 2014 Commercial Operations Date Ke··npcr Cour1ty IGCC ProJ·ect 1 MlsslsstPPt.A POW£R ........ ..... .- SoCo FOIA Response 002829 Jun-e 2010 I MISSISSIPPIA SoCo FOIA Response 002830 . .. . . ?k Projcci' ?'55'55=gglum In I SoCo FOIA Response 002831 SoCo FOIA Response 002832 - I. "3 j" .bv Linear Facilities • Land clearing activities started on the East Transmission Line/Treated Effluent Pipeline corridor in August 2011 • Clearing activities to start on West Transmission Line/C0 2 Pipeline corridor in next 2 weeks • Treated Effluent Pipeline construction to begin in November • C02 Pipeline and Transmission construction to begin 1 Q of 2012 I lr· • Cour~t''Y IC1CC Pm ,1ect M1ss1ss1PP1...\. POWER SoCo FOIA Response 002834 Activities under the PA • Cultural Resource Awareness Training • Goldman House Data Recovery • Phase II Investigations l<·•• m .oer Courty IGCC ProJ· Pet M1ss1sstPPI~ POWER • ••a• o•• <"-•o•• SoCo FOIA Response 002835 r c I I G I c project Cultural Resource Awareness Training (SHIPS Code 019073) OC1ober2011 - ! Monday, October 24, 2011 5:28 PM Mosser, Morgan H. Morton, Frank C. RE: NCCC Techline review nccc 101811 fcm.docx From: Sent: To: Cc: Subject: Attachments: Mike, Attached is marked up copy with our comments. Give us a call if any questions. Thanks, Doug Maxwell Southern Company Services, Inc. National Carbon Capture Center 8-824·5851 (Intercompany) (b) (6) (External) (205)-670-5843 (Fax) jdmaxwel@southernco.com This e-mail and any of its attachments may contain proprietary Southern Company and/or affiliate information that is privileged, confidential, or protected by copyright belonging to Southern Company and/or Its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Morgan Mosser [mallto:Morgan.Mosser@NETL.DOE.GOV] Sent: Thursday, October 20, 2011 9:04AM To: Morton, Frank C.; Maxwell, Doug Subject: Fwd: NCCC Techllne review Gents, Would you review and send me back any corrections Mike Morgan Mike Mosser Project Manager National Energy Technology laboratory PO Box 880 Morgantown, WV 26507-0880 w - 304-285-4723 F- 304-285-4638 morgan.mosser@netl.doe.gov SoCo FOIA Response 002850 (b) (4), (b) (6) 10/18/201111:38 AM>>> Mike: As promised, attached is a first draft of the NCCC Tech line as a starting point for your review. Please email any changes to me and I'll be glad to incorporate them into a revised draft that I will return to you. At that point, you can send it up your supervisory chain for further review. Once all changes have come to me, I'll include those and email a final draft to (b) (4), (b) (6) for coordination with HO. I thank you in advance for your help with this Techline. (b) (4), (b) (6) Contractor (b) (4), (b) (6) 2 SoCo FOIA Response 002851 DOE Drafl Techline 10/ 18111 DOE-Sponsorrtll'rojed Bolsters Nation's Clean Coal Technology l'rogrum Stlccessjlll Cata~t·st Tests l11crease Poll'er Prodllcliotl, Reduce CO:Z Capture Cost Washington, DC- Tests recent!) conducted at the U.S. Department of Energ} 's (DOE) National Carbon Capture Center (NCCC) demonstrated that certain commercially manufactured catalysts can produce measurcable increases in po\\er generation as well as significant cost sa~ ings over the life of a gasification plant. Researchers at the PO" ~r S)'St~AlS ()~· ~lef'm~llt Feeilil~. ·~l!i~te~k.! NCCC in Wilsonville, Ala_. conducted water-gas shill (WGS) ental) st tests and achie\·ed an important milestone, namely that steam-to-gas (carbon monoxide) ratios can be reduced. Reducing the r.llio increased the net power output of an integrated gasification combined cycle (IGCC) plant and reduced the cost of electricit) associated with carbon dioxide (CO:) capture. The DOE-sponsored NCCC is a state-of-the-an t~st facility dedicated to the advancement of clean coal technology. It addresses the nation's need for cost-effective, commerciall) viable CO: capture options for nue gas from pulverized coal power plants and synthesis gas from coal ga.~i fication plants. T he tests indicated that a steam-to-CO ratio reduction ofO. I corresponded to a 4-rncgawan increase in power generation in a 500-megawatt IGCC plant. An acceptable steam-to-CO decrease of+-i>J .!! a lim's on IGC'C clam Jn generatL'II an additional40 meganalls of power. Researchers estimate that these findings can produce operational savings of more than S200 million over the entire lifespan of a plan~ The NCCC is implementing these finding at a commerciaiiGCC plant now under construction in Kemper Count), Miss. The plant\\ ill showct\SC a transport gasifier technology developed at the llSD~. Researchers had to address the problem that carbon in coal-derived synthesis gas exists primaril) as CO and CO:, along with a small amount of methane. The presence of CO during the combustion of S) nthesis gas in a gas turbine limits the efficiency of CO: remO\al because the CO \\ill be converted to COz during the combustion process. Therefore, to ma.ximize COz capture, the S) nthesis gas can be passed over a WGS catalyst in the presence of water to convert the CO to COz before the CO! removal step. f eo.-ted [Jl): T... "doc,.a~e"l • dl~....,.. bolwHn l.6 ond l2 .6, or 5rl other wotds, •1.a* Commented [fl): The use of' stelm-to-m ratla ell.&rather than the conwntJoMI ratio of 2.6 do~s .ttowforthe Jtneratlon on •n addttJonal 40 MW OYtf tM 40 yu.r Ufe of aSOO MW "'"' O.ttrmlAin& the value of tfut .tOMW to bt: 5200 MM UMd Jb tpKiftc: Soutt.rn Company values frDm 2001. I rKDmmtnd ""1Un1 the u\Ma esUmate mareaeneral bvDOEeu$matlnllfMi valutof ttt. 40 MW s.avlncs u.Sn1 st.Nbrd DOE •numptlons and nponln1 the savlnas as a 00£ c:ah:ul~_t~n- WGS reactors arc widely used in chemical manufacturing where steam-to-CO ratios as high as 2.6 arc acceptable in convening CO to C02. In power plant applications where high CO to COz conversion is not required to achieve acceptable levels of COl capture, incomplete conversion of CO is acceptable. However. if COl capture is imponant. then lower steam-to-CO ratios become significant. Researchers performed the tests with several commercially available WGS catalysts and arc providing the results to manufacturers to assist them in spccif} ing future WGS S)Stcms for IGCC SoCo FOIA Response 002852 plants that incorporate C02 capture. They nrc also planning further tests with commercially available and newly formulated was catalysts. DOE's National Energy Technology Laboratory, in cooperation with Southern Company Services, established the NCCC to bolster national efforts to reduce greenhouse gas emissions by developing cost·effecti\·e technologies to capture the COz produced by fossil-fueled power plants. An ultimate goal is to lower the cost of C02 capture technologies and provide affordable, reliable, and clean coal-based power generation to secure tile nation's energy future. ·End ofTechLinc· For more information, contact: Jenny 1-lakun, FE Office of Communication, 2021586-5616 SoCo FOIA Response 002853 From: Sent To: Subject: Attachments: Olson, Susan C. (CONTR) Friday, October 28, 2011 2:04 PM Robbins, Brittley K.; Madden, Diane R. Award: DEFC2606NT42391, Progress Report Period Ending: 9/30/2011 (42391PR_Q093011) 42391PR_Q0930ll.pdf Subject: Distribution of Progress Report Contract/Grant/Cooperative Agreement No. DEFC2606NT42391 with Southern Company Services Inc Period Ending 9/30/2011 The attached report has been submitted by the contractor/recipient and received into FITS. This is the formal distribution for the deliverable, since this is an electronic only award. Thank you, Susan Olson SoCo FOIA Response 002854 Demonstration of a Coal Based Transport Gasifier: 2011 Third Quarter Technical Status Report Period Covered by Report: 7/0 1120 II - 9/30/20 II Project Manager: Tim Pinkston Date of Report: October 271h, 20 II Project: DE-FC26-06NT42391 Submitting Organization: Southern Company Services, Inc. 42 Inverness Center Parkway Bin B228 Birmingham, AL 35242 This progress report was prepared with the support of the U.S. Department of Energy, an agency of the United States Government, under Award Number DE-FC26-06NT42391. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. SoCo FOIA Response 002855 Project Management The following are major project milestones: • • • Project is on schedule and on budget. 59% of the Certified Plant costs have been confirmed. Acquisition of the transmission right·Of·way approximately 78% complete. The second 115kV line rebuild project is complete. Construction, engineering and detail design are progressing as scheduled. Permits and Approvals The permit and approval status is shown below: Description Status Submittal State Groundwater Test Well Permit MS-GW-16425 Approved 5/30/2007 6/26/2007 State NPDES Stormwater Run-off Permit MSR104866 Approved 11/13/2007 3/12/2010 Stale PSD Air Permil1380-00017 State Groundwater Production Well Permit MS-GW16425 Approved 12/20/2007 3/12/2010 Approved 5/21/2008 6/24/2008 MPSC Certificate Approved 1/16/2009 6/3/2010 Stale Permit to Operate Wastewater Disposal System wino Discharge Permit MSU009005 Approved 11/19/2009 3/12/2010 Stale Dam Safety Approval App. No. 09-041 Approved 12/1/2009 3/23/2010 Stale Dam Safety Approval App. No. 09-040 Approved 12/1/2009 3/23/2010 DOE NEPA ROD (CCPI2) Approved 11/6/2009 8/19/2010 Stale 401 Water Quality Certification Approved 10/27/2009 9/14/2010 USACE 404 Permit for Wetlands SAM-2009-01149-DMY Approved 10/27/2009 11/1 B/201 0 Pending 6/11/2010 State Solid Waste Management Permit • Approval FAA Stack Permit Approved 2/8/2011 3/14/11 State Dam Safety - Make-up Reservoir Approved 6/3/2011 8/12/2011 8/9/2011 Slate Dam Safety - Retention Pond B NPDES Emergency Discharge Permit - Make-up reservoir NPDES Baseline Industrial Storm Water General Permit Approved 6/1/2011 Application 1/17/2012 Application 4/1/2013 Tille V Acid Rain Permit Application 5/1/2012 Title V Operating Permit Note: Dates in bold are actual dates, others are forecast dates Application 5/1/2015 The Mississippi Department of Environmental Quality (MDEQ) issued the final PSD permit on March 9, 2010. On April2, 2010, Sierra Club filed a notice of appeal ofthe final air permit and request for an evidentiary hearing. The Harrison County Chancery Court affirmed the Commission's orders authorizing the construction of the Kemper Project. On March I, 20 I I, the Sierra Club appealed the Chancery Court's decision to the Mississippi Supreme Court. Meanwhile, the Mississippi Department of Environmental Quality Permit Board held an evidentiary hearing on the Kemper Project Prevention of Significant Deterioration (PSD) air permit. The Board 2 SoCo FOIA Response 002856 unanimously affirmed the existing PSD permit. On June 30,2011 Sierra Club filed a formal notice of appeal to challenge the MDEQ permit board's decision upholding the Kemper PSD permit in Chancery Court of Mississippi County. • Mississippi Power submitted a permit update to the USACE, with copies to MDEQ and DOE, notifying them of minor changes in the scope of permit and the wetlands mitigation as a result of final engineering and design. Responses were received from MDEQ and the USACE on July 22 and July 26, 2011, respectively. Both agencies agreed to the proposed changes to the permit. • The Dam Safety Branch of MDEQ issued Approvals to Construct the dams associated with the Treated Effluent Reservoir and a revised design for Retention Pond B. Engineering/Construction Detailed engineering started after the regulatory certification process was completed on May 26, 20 I 0. Currently, engineering and detail design are progressing as scheduled. A summary of the engineering tasks is listed below. • • • • • • • • • • • • • • • Engineering continued to issue equipment and material inquires, receive and evaluate bids, issue purchase orders, and approve contracts. Detailed design remained on schedule. Engineering issued equipment plans for the mechanical shop and warehouse. Engineering issued conduit and grounding drawings. Engineering continued to issue foundation drawings. Engineering continued to issue isometrics. Engineering issued vessel external clip details. The second stage of review for the plant 3D model continued, including extensive review of the C02 Compression, flare, sulfuric acid storage, WSA, and combined eye le areas. Kickoff meetings for the following systems were held with the respective vendors: • Selexol Flash Gas Compressor. • Low and Medium Voltage Switchgear. • Selexol Refrigeration Package. Work is complete for the first three phases of major earthwork. A total of 4,500,000 cubic yards has been placed. Work proceeds on the installation of the fire protection piping and area sumps. All area sumps are nearly complete with 22,579 cubic yards of concrete poured. II ,098 linear feet of fire protection piping has been installed. Construction continued to install drainage ditches and concrete culverts. 136 storm drain inlets and 12,534 linear feet of storm drain piping has been installed to date. Construction continues to install the circulating water and closed loop cooling water piping. Approximately 14,294 linear feet of circulating water piping is in place. Installation continued for the power duct banks. A total of 338, 118 linear feet of duct bank conduit has been installed to date. A total of 14,635 Iinear feet of electrical cable has been pulled to date. 3 SoCo FOIA Response 002857 • • • • Auger cast piling installation continued. Installation is over 44% complete. Piling should be complete by March of2012. Caisson installation is approximately 76% complete and is schedule to be complete by November 20 I I. Concrete work continues with 20, 130 cubic yards poured. The underground piping installation is 29% complete. Procurement The following inquiry packages are in development stage: • WGS Startup Heater. The following inquiry packages have been issued for bids: • Reclaim Sump Pumps. • Ash Cooler Booster Pumps. • Ash Sediment Pond Pumps. • Electrical Buildings. The following inquiry packages are in bid evaluation stage: • Various Instrumentation Packages. • Operations Training Simulator. • Water Analysis Building. • Ammonia and Sulfuric Acid Loading Stations. • Mercury Adsorber Fill Material. Contract negotiations are underway for the following items: • Process Air Compressors. • Air Separation Unit Compressors. • Extraction Air Compressors. • Recycle Gas Compressors. • Wet Sulfuric Acid Process Equipment. • C02 Compressors. • Quench/Scrubber Columns. • Wet Electrostatic Precipitator. • Selexol Refrigeration Package. • WGS Catalyst. • C02 Recycle Compressor. • LP Vent Gas Compressor. • Transport Air Compressor. • Selexol High and Medium Pressure C02 Flash Drums. • Selexol Miscellaneous Heat Exchangers. • HRSG Feed Water Pumps. • COS Hydrolysis Catalyst. • Selexol Flash, Knockout, and Reflux Drums. • Freight and Personnel Elevators. 4 SoCo FOIA Response 002858 • • • • • • • • • • • • • • • • • • • • • • • • Flare System. Coal Drying System Filter Press. Cyclonic Baghouse. Selexol Solvent Filtration Package. Field Erected Tanks. PCD Vessels. Venturi Scrubbers. Flash Gas Compressor. Selexol Column Internals. Water and Wastewater Treatment Package. Sourwater Column Internals. WSA Combustor. Wastewater Carbon Bed Filter. Combined Cycle Auxiliary Circulating Water Pumps. CCAD Primary Cooler. CCAD Upper Secondary Cooler. Fuel Oil Forwarding Pumps. Condensate Makeup Pumps. Intake Water Pumps. Sample Stations. High Pressure Flare Knockout Drums. Instrument Air Compressors. Anhydrous Ammonia Reflux Makeup Pump. Static Mixers. The following contracts have been signed by both parties: • Steam Turbine. • Gasifiers. • Gas Turbines. • Syngas Coolers. • Building Architectural Package. • HRSGs. • Auxiliary Boiler. • Condensate Pumps. • Fluidized Bed Dryers. • Air Heater and Ammonia Vaporizer. • Nitrogen Surge Drums. • Syngas and Ammonia Scrubbers. • Condenser/Vacuum Pumps. • Selexol Antifoam Injection Package. • Combined Cycle Circulating Water Pumps. • Wastewater Drum. • Process Condensate and Transport Air Compressor Knockout Drums. • Selexol Makeup Water Pumps. 5 SoCo FOIA Response 002859 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • Cooling Towers. Cartridge Filters. Wastewater Reflux Drums. Crushed Coal Feeders. Packinox Heat Exchangers. PCD Fines Receivers. Selexol Flash Gas Compressor Coolers. Selexol Solvent Makeup Filter. Selexol Sump, Reflux, and Filtration Pumps. Coal Mills. Selexol Chillers. Flare Knockout Drum Pumps. Sourwater Separation Columns. Sourwater Pumps. Filtrate Pumps. Coal Feeder Storage Bins. Coal/Ash Silos. Gasifier Cooling Water Heat Exchangers. Flare Knockout Drums. Hydrogen Peroxide System. Tempered Water Heat Exchangers. Medium Pressure Steam Drum. Mercury Adsorbers. Selexol Regenerators, Concentrators, and C02 Absorbers. Plant DCS. Particulate Control Device Tubesheets. Fuel Gas Heat Exchanger. Combined Cycle Closed Loop Cooling Water Heat Exchanger. Selexol Sump and Water Break Drums. Fluidized Bed Discharge Feeders. Ash Moisturizer. PLD Vent Gas Drums. Light Hydrocarbon Drain Pots. Coal/Ash Pressure Let-Down Devices. Extraction Air and Recycle Gas Compressor Knockout Drums. Ammonia Product Drums. Hydrocarbon Drain Drum. Gasifier Island Closed Loop Cooling Water Pumps. Selexol H2S Absorbers. Surge Drum Agitator. Gasifier Island Circulating Water Pumps. High Pressure Makeup Water Pumps. Gasifier Startup Burners. WSA Combustion Air Blower. 6 SoCo FOIA Response 002860 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • Selexol Solvent Pumps. Tempered Water Drums. Tempered Water Circulation Pump. Gas Cleanup Area Heat Exchangers. Gasifier Control Systems Buildings. Coal Mill Feed Fan. Coal Dryer Feed Gas Fan. Combined Cycle Closed Loop Cooling Water Pumps. WSA Acid Pumps. Caustic and Diesel Tanks. Oversized Pressure Vessels. Safety Instrumented System. Pyrite Bucket Elevator. WSA S02 Converter. Venturi Scrubber Pump-Around Coolers. Multiclone Discharge Drag Conveyors. Multiclone. Pyrite Screw Conveyors. Nitrogen Accumulators. Low and Medium Pressure C02 Knockout Drums. Gasifier Island Auxiliary Circulating Water Pumps. Pyrite Discharge System. CCAD Steam Drum and Condenser. Sump Pumps. Nitrogen Generator. Auxiliary Boiler Makeup Water Pumps. Sewage Treatment Systems. Steam Blowdown Tanks. CCAD Vent Filter. Gas Analyzer System and Shelters. Coal Feeder Lock and Dispense Vessels. COz Dehydration Package. Transport Air Dryers. WSA Waste Heat Steam Generator. Gasifier Bottoms Drain Pot Feeder. Stack Gas and Cooling Air Blowers. WSA Stack. Fuel Oil Loading Package. Low Pressure Condensate Pump. CCAD Lower Secondary Cooler. Low Pressure Condensate Drum Vent Condenser. Ash Vents. Water-Gas-Shift Reactors. COS Hydrolysis Vessels. 7 SoCo FOIA Response 002861 • • • Ammonia Pumps. Scrubber Water Pumps. SAT and GSU Transformers. 8 SoCo FOIA Response 002862 From: Sent: To: Subject: Attachments: "Templeton, John D." Friday, November 11, 201111:10 AM Whyte, Cliff D.; Madden, Diane R.; Hargis, Richard Kemper • T&E Pre-Construction Survey West Corridor Biological Assessment transmittal 2011-11-ll.pdf; West Corridor Biological Assessement (PAC) 2011-10-19.pdf Hello allCondition G(f) of Kemper's 404 permit requires us to conduct pre-construction surveys for the presence of threatened/endangered species. The West Corridor (Plant site to Heidelberg) was surveyed last month prior to beginning clearing operations for the West Transmission line and the C02 pipeline. I submitted the assessment report to the USACE today, with copies to the USFWS and MDEQ. Attached, please find copies of the transmittal letter and report for your review and records. I will be happy to send hard copies if you need them. As always, hope things are going well with you and please let me know if you have any questions. JT John Templeton Senior Environmental Specialist Mississippi Power Company PO Box 4079 Gulfport, MS 39502-4079 Ofc: 228-897-4332 Cell: (b) (6) jdtemple@southernco.com This electronic message may conta:n informat.on that I> conftdential or legally privileged II Is Intended only f !Ir the vse of the lndividual(s) and entity named as recipients in the message If yuu are not an mlended recipi~nt of this message, please notify the sender Immediately and delete the material from any computer Do not deliver, distribute or copy lh~ me·!Sage, and do not dtsclcse its contents or take any action in rel Friday, December 02, 2011 8:39 AM Godfrey, Amanda R.; Martin, Curtis T.; Meeks, Dan; Jones, David L (Procurement); Wilson, Henry Kyser (Hal); Floyd, Jeff (Supply Chain); Rushing, Jessica lee; Pyle, Jerry lee; Burnett, John Wesley; Carr, Kerrie L; Handy, Marquisha; Amick, Mitchell J.; Hentz, Nancy; Hammock, Paul Steven; Edwards, Ric T.; Owen, Steve; Allen, William R. III URGENT MESSAGE- DO NOT DELETE- MPC KEMPER CO. ORDERS 2011-12-02 letter Kemper Overweight Permits.pdf Importance: High From: Sent: Cc: ATIENTION: SUPPLIERS OF EQUIPMENT FOR THE KEMPER CO. PROJECT FOR MISSISSIPPI POWER COMPANY If you are providing any equipment for the Kemper Co. project for which you will have to obtain transportation permits in order to deliver your items, please see the attached letter. Please contact your Southern Company Supply Chain buyer if you have any questions regarding this information. Jennifer Cox Southern Company Services Supply Chain Management ph: 205.992.5835 email: jfcox@southernco.com NOTICE: This e-mail and any of its attachments may contain proprietary Southern Company and/or affiliate information that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates. This e-mail is intended solely for the use of the individual or entity for which it is intended. If you are not the intended recipient of this e-mail, any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. SoCo FOIA Response 002888 2992 West Beach Boulevard PO Box4079 Gulfport, Mississippi 39502-4079 MISSISSIPPI « \ POWER A SOUTHERN COMPANY December 2, 2011 RE: Kemper County IGCC Project- Overweight Permits In an effort to expedite the superload permit approval process for the Kemper County IGCC Project, we are notifying you that the Mississippi Department of Transportation (MDOT) is utilizing (b) (4) as a third party engineer to perform bridge inspection and roadway analysis to determine suitable load configurations and routes for presentation to MDOT for approval. There are two preferred access routes to the site for overweight equipment: (1) via barge to the Columbus, MS area and then over highways to the Kemper project site, and (2) via rail access to Meridian, MS and then over highways to the Kemper project site. Depending on the origin, load dimension and weight, MDOT may consider other routes. MOOT has the final approval of all permits. Due to extent of overweighVoversize deliveries for this project, please contact, or have your transporter contact, the state as soon as possible to begin working on any necessary transportation permits. Contacts are as follows: 1. Willie Huff- MDOT 601-359-1701 -whuff@MOOT.state.ms.us Cc: Tommy Thames- MOOT 601-359-1538- tthames@mdot.state.ms.us 2. (b) (4), (b) (6) Use of the same third party engineer will help ensure a lower cost to you for permit review and approval and help with getting reviews completed in an expedited manner. If you have any questions regarding this correspondence, please call your Southern Company Supply Chain Buyer. Sincerely yours, Southern Company Supply Chain Buyer SoCo FOIA Response 002889 From: Sent: To: Cc: Subject: Attachments: "Maxwell, Doug" Monday, December 19, 20111:35 PM Mosser, Morgan H. Morton, Frank C.; Yongue, Ruth Ann; Laird, Roxann F. FW: NCCC Techline review nccc v2 1214ll.docx Mike, This looks good. The only two comments we have are 1) that it may sound better to the public to say "cost savings of over $275 million" rather than "additional revenue of more than $275 million", and 2) instead of "The NCCC is implementing these finding at a commerciaiiGCC plant ... ", it should read " These findings are being implemented at a commercial plant ...". I've marked up the attached to show the changes by the two above comments. Let me know when DOE decides to issue this Techline and we will proceed with posting our technical update on this matter to our website at the same time. Thanks, Doug Maxwell Southern Company Services, Inc. National Carbon Capture Center 8·824· 5851 (Int ercompany) (External) (b) (6) (205)-670-5843 (Fax) jdmaxwel@southernco.com This e·mail and any of its attachments may contain proprietary Southern Company and/or affiliate information that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates This e·mall is intended solely for the use of the individual or entity for which it is intended. If you are not the Intended recipient of this e-mail, any dissemination, distribution, copying, or action taken In relation to the contents of and attachments to this e-mail is contrary to the rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immediately by return e-mail and permanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Morgan Mosser [mallto:Morgan.Mosser@NETL.DOE.GOV] sent: Thursday, December 15, 2011 8:39 AM To: Maxwell, Doug Cc: Morton, Frank C. Subject: RE: NCCC Techllne review See attached, any further comments? Morgan Mike Mosser Project Manager National Energy Technology Laboratory PO Box 880 Morgantown, WV 26507·0880 SoCo FOIA Response 002890 w - 304-285-4723 F- 304-285-4638 morgan.mosser@netl.doe.gov >>>"Maxwell, Doug" 10/24/2011 6:27PM>>> Mike, Attached is marked up copy with our comments. Give us a call if any questions. Thanks, Doug Maxwell Southern Company Services, Inc. National Carbon Capture Center 8-824-5851 (Intercompany) (External) (b) (6) (205)-670·5843 (Fax) jdmaxwel@southernco.com This e-mail and any of iU attachments may contain proprietary Southern Company and/or affiliate information that is privileged, confidential, or protected by copyright belonging to Southern Company and/or its affiliates This e·mail ls Intended solely for the use of the individual or entity for which It Is Intended. If you are not the intended recipient of this e· mail, any dissemination, distribution, copying, o r action taken in relation to the contents of and attachments to this e-mail is contrary to t he rights of Southern Company and/or its affiliates and is prohibited. If you are not the intended recipient of this e-mail, please notify the sender immed•ately by return e-mail and p ermanently delete the original and any copy or printout of this e-mail and any attachments. Thank you. From: Morgan Mosser [mallto:Morgan.Mosser@NETLDOE.GOV} Sent: Thursday, October 20, 2011 9:04AM To: Morton, Frank C.; Maxwell, Doug Subject: Fwd: NCCC Techline review Gents, Would you review and send me back any corrections Mike Morgan Mike Mosser Project Manager National Energy Technology Laboratory PO Box 880 Morgantown, WV 26507-0880 w- 304·285-4723 F • 304-285-4638 morgan.mosser@netl.doe.gov (b) (4), (b) (6) 10/18/201111:38 AM >>> Mike: As promised, attached is a first draft of the NCCC Techline as a starting point for your review. Please email any changes to me and I'll be glad to incorporate them into a revised draft that I will return to you. At that point, you can send it up your supervisory chain for further review. 2 SoCo FOIA Response 002891 Once all changes have come to me, I'll include those and email a final draft to (b) (4), (b) (6) for coordination with HQ. I thank you in advance for your help with this Techline. (b) (4), (b) (6) Contractor (b) (4), (b) (6) 3 SoCo FOIA Response 002892 DOE Draft Techline 12/1411 I DOE~Sponsored Project Bolsters Nation's Clean Coal Technology Program Successful Catalyst Tests Increase Power Production, Reduce C02 Capture Cost Washington, DC-Tests recently conducted at the U.S. Department of Energy' s (DOE) National Carbon Capture Center (NCCC) demonstrated that certain commercially manufactured catalysts can produce measureable increases in power generation as well as significant cost savings over the life of a gasification plant. Researchers at the NCCC in Wilsonville, Ala., conducted water~gas shift (WGS) catalyst tests and achieved an important milestone, namely that steam-to-gas (carbon monoxide) ratios can be reduced. Reducing the ratio increased the net power output of an integrated gasification combined cycle (IGCC) plant and reduced the cost of electricity associated with carbon dioxide (COz) capture. The DOE-sponsored NCCC is a state-of-the-art test facility dedicated to the advancement of clean coal technology. It addresses the nation's need for cost-effective, commercially viable C02 capture options for flue gas from pulverized coal power plants and synthesis gas from coal gasification plants. The tests indicated that a steam-to-CO ratio reduction of 0.1 corresponded to a 4-megawatt increase in power generation in a 500-megawatt IGCC plant. An acceptable steam-to-CO decrease of 1.0 generated an additional 40 megawatts of power. Researchers estimate these findings can result in adEfu.ioR-al Fe\'etHfecost savings of more than $275 million over a 30-year plant Iife at current estimated IGCC power costs of about $33 per megawatt hour. The ~JCCC is imJ)IemeRtiAg tThese findings are being implemented at a commerciallGCC plant now under construction in Kemper County, Miss. The plant will showcase a transport gasifier technology developed at the NCCC. Researchers had to address the problem that carbon in coal-derived synthesis gas exists primarily as CO and COz, along with a small amount of methane. The presence of CO during the combustion of synthesis gas in a gas turbine limits the efficiency of COz removal because the CO will be converted to COz during the combustion process. Therefore, to maximize C02 capture, the synthesis gas can be passed over a WGS catalyst in the presence of water to convert the CO to C02 before the COz removal step. WGS reactors are widely used in chemical manufacturing where steam-to-CO ratios as high as 2.6 are acceptable in converting CO to C02. In power plant applications where high CO to C02 conversion is not required to achieve acceptable levels of C02 capture, incomplete conversion of CO is acceptable. However, ifCOz capture is important, then lower steam-to-CO ratios become significant. SoCo FOIA Response 002893 Researchers performed the tests with several commercially available WGS catalysts and are providing the results to manufacturers to assist them in specifying future WGS systems for IGCC plants that incorporate C02 capture. They are also planning further tests with commercially available and newly formulated WGS catalysts. DOE's National Energy Technology Laboratory, in cooperation with Southern Company Services, established the NCCC to bolster national efforts to reduce greenhouse gas emissions by developing cost-effective technologies to capture the C02 produced by fossil-fueled power plants. An ultimate goal is to lower the cost of C02 capture technologies and provide affordable, reliable, and clean coal-based power generation to secure the nation's energy future. -End ofTechLineFor more information, contact: Jenny Hakun, FE Office of Communication, 202/586-5616 SoCo FOIA Response 002894