20150811-8000 FERC PDF (Unofficial) 08/11/2015 THIS FILING IS Item 1: An Initial (Original) Submission OR X Form 1 Approved OMB No.1902-0021 (Expires 11/30/2016) Resubmission No. ____ Form 1-F Approved OMB No.1902-0029 (Expires 11/30/2016) Form 3-Q Approved OMB No.1902-0205 (Expires 11/30/2016) FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature Exact Legal Name of Respondent (Company) Year/Period of Report Arizona Public Service Company End of FERC FORM No.1/3-Q (REV. 02-04) 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q GENERAL INFORMATION I. Purpose FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms. II. Who Must Submit Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400). Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following: (1) one million megawatt hours of total annual sales, (2) 100 megawatt hours of annual sales for resale, (3) 500 megawatt hours of annual power exchanges delivered, or (4) 500 megawatt hours of annual wheeling for others (deliveries plus losses). III. What and Where to Submit (a) Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report for your files. Any electronic submission must be created by using the forms submission software provided free by the Commission at its web site: http://www.ferc.gov/docs-filing/eforms/form-1/elec-subm-soft.asp. The software is used to submit the electronic filing to the Commission via the Internet. (b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings. (c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at: Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 (d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above. FERC FORM 1 & 3-Q (ED. 03-07) i 20150811-8000 FERC PDF (Unofficial) 08/11/2015 The CPA Certification Statement should: a) Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and b) Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific qualifications.) Reference Schedules Comparative Balance Sheet Statement of Income Statement of Retained Earnings Statement of Cash Flows Notes to Financial Statements e) Pages 110-113 114-117 118-119 120-121 122-123 The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported. for the year ended on which we have “In connection with our regular examination of the financial statements of , we have also reviewed schedules reported separately under date of of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances. Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist. (f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. To further that effort, new selections, “Annual Report to Stockholders,” and “CPA Certification Statement” have been added to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on the Commission’s website at http://www.ferc.gov/help/how-to.asp. (g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from http://www.ferc.gov/docs-filing/eforms/form-1/form-1.pdf and http://www.ferc.gov/docs-filing/eforms.asp#3Q-gas . IV. When to Submit: FERC Forms 1 and 3-Q must be filed by the following schedule: FERC FORM 1 & 3-Q (ED. 03-07) ii 20150811-8000 FERC PDF (Unofficial) 08/11/2015 a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400). V. Where to Send Comments on Public Reporting Burden. The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 150 hours per response. Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)). FERC FORM 1 & 3-Q (ED. 03-07) iii 20150811-8000 FERC PDF (Unofficial) 08/11/2015 GENERAL INSTRUCTIONS I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA. II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts. III Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact. IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3. V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below). VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses. VII For any resubmissions, submit the electronic filing using the form submission software only. Please explain the reason for the resubmission in a footnote to the data field. VIII. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized. IX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used. Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows: FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent. FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the FERC FORM 1 & 3-Q (ED. 03-07) iv 20150811-8000 FERC PDF (Unofficial) 08/11/2015 termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract. OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract. SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year. NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry. AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. DEFINITIONS I. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization. II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made. FERC FORM 1 & 3-Q (ED. 03-07) v 20150811-8000 FERC PDF (Unofficial) 08/11/2015 EXCERPTS FROM THE LAW Federal Power Act, 16 U.S.C. § 791a-825r Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with: (3) ’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined; (4) 'Person' means an individual or a corporation; (5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof; (7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ...... (11) "project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit; "Sec. 4. The Commission is hereby authorized and empowered (a) To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act." "Sec. 304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports salt be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10 FERC FORM 1 & 3-Q (ED. 03-07) vi 20150811-8000 FERC PDF (Unofficial) 08/11/2015 "Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..." General Penalties The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a). FERC FORM 1 & 3-Q (ED. 03-07) vii FERC FORM NO. 20150811-8000 FERC PDF (Unofficial) 08/11/2015 1/3-Q: REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER IDENTIFICATION 01 Exact Legal Name of Respondent Arizona Public Service Company 02 Year/Period of Report 2014/Q4 End of 03 Previous Name and Date of Change (if name changed during year) / / 04 Address of Principal Office at End of Period (Street, City, State, Zip Code) 400 North 5th Street, Phoenix, AZ 85004 05 Name of Contact Person Jeffrey B. Guldner 06 Title of Contact Person SVP Public Policy 07 Address of Contact Person (Street, City, State, Zip Code) 400 North 5th Street, Phoenix, AZ 85004 08 Telephone of Contact Person,Including 09 This Report Is Area Code (1) An Original (602) 250-2952 (2) X A Resubmission 10 Date of Report (Mo, Da, Yr) 04/15/2015 ANNUAL CORPORATE OFFICER CERTIFICATION The undersigned officer certifies that: I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts. 01 Name 03 Signature 04 Date Signed Denise R. Danner (Mo, Da, Yr) 02 Title Denise R. Danner VP, Controller & Chief Acct Officer 04/15/2015 Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction. FERC FORM No.1/3-Q (REV. 02-04) Page 1 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission LIST OF SCHEDULES (Electric Utility) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA". Line No. Title of Schedule Reference Page No. (b) (a) 1 General Information 101 2 Control Over Respondent 102 3 Corporations Controlled by Respondent 103 4 Officers 104 5 Directors 105 6 Information on Formula Rates 106(a)(b) 7 Important Changes During the Year 108-109 8 Comparative Balance Sheet 110-113 9 Statement of Income for the Year 114-117 10 Statement of Retained Earnings for the Year 118-119 11 Statement of Cash Flows 120-121 12 Notes to Financial Statements 122-123 13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b) 14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201 15 Nuclear Fuel Materials 202-203 16 Electric Plant in Service 204-207 17 Electric Plant Leased to Others 213 18 Electric Plant Held for Future Use 214 19 Construction Work in Progress-Electric 216 20 Accumulated Provision for Depreciation of Electric Utility Plant 219 21 Investment of Subsidiary Companies 224-225 22 Materials and Supplies 227 23 Allowances 228(ab)-229(ab) 24 Extraordinary Property Losses 230 25 Unrecovered Plant and Regulatory Study Costs 230 26 Transmission Service and Generation Interconnection Study Costs 231 27 Other Regulatory Assets 232 28 Miscellaneous Deferred Debits 233 29 Accumulated Deferred Income Taxes 234 30 Capital Stock 250-251 31 Other Paid-in Capital 253 32 Capital Stock Expense 254 33 Long-Term Debt 256-257 34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261 35 Taxes Accrued, Prepaid and Charged During the Year 262-263 36 Accumulated Deferred Investment Tax Credits 266-267 FERC FORM NO. 1 (ED. 12-96) Page 2 Remarks (c) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission LIST OF SCHEDULES (Electric Utility) (continued) Year/Period of Report 2014/Q4 End of Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA". Line No. Title of Schedule Reference Page No. (b) (a) 37 Other Deferred Credits (c) 269 38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273 39 Accumulated Deferred Income Taxes-Other Property 274-275 40 Accumulated Deferred Income Taxes-Other 276-277 41 Other Regulatory Liabilities 278 42 Electric Operating Revenues 300-301 43 Regional Transmission Service Revenues (Account 457.1) 302 44 Sales of Electricity by Rate Schedules 304 45 Sales for Resale 310-311 46 Electric Operation and Maintenance Expenses 320-323 47 Purchased Power 326-327 48 Transmission of Electricity for Others 328-330 49 Transmission of Electricity by ISO/RTOs 331 50 Transmission of Electricity by Others 332 51 Miscellaneous General Expenses-Electric 335 52 Depreciation and Amortization of Electric Plant 336-337 53 Regulatory Commission Expenses 350-351 54 Research, Development and Demonstration Activities 352-353 55 Distribution of Salaries and Wages 354-355 56 Common Utility Plant and Expenses 356 57 Amounts included in ISO/RTO Settlement Statements 397 58 Purchase and Sale of Ancillary Services 398 59 Monthly Transmission System Peak Load 400 60 Monthly ISO/RTO Transmission System Peak Load 400a 61 Electric Energy Account 401 62 Monthly Peaks and Output 401 63 Steam Electric Generating Plant Statistics 402-403 64 Hydroelectric Generating Plant Statistics 406-407 65 Pumped Storage Generating Plant Statistics 408-409 66 Generating Plant Statistics Pages 410-411 FERC FORM NO. 1 (ED. 12-96) Remarks Page 3 Revised Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission LIST OF SCHEDULES (Electric Utility) (continued) Year/Period of Report 2014/Q4 End of Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA". Line No. Title of Schedule Reference Page No. (b) (a) 67 Transmission Line Statistics Pages 422-423 68 Transmission Lines Added During the Year 424-425 69 Substations 426-427 70 Transactions with Associated (Affiliated) Companies 429 71 Footnote Data 450 Stockholders' Reports Check appropriate box: X Two copies will be submitted No annual report to stockholders is prepared FERC FORM NO. 1 (ED. 12-96) Page 4 Remarks (c) 20150811-8000 08/11/2015 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 GENERAL INFORMATION 1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept. James R. Hatfield, Executive Vice President & Chief Financial Officer, 400 N. 5th Street, Phoenix, AZ 85004 2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized. Arizona - February 6, 1920 3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased. Not Applicable 4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated. State of Arizona - Class A Electric Utility 5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements? (1) (2) X Yes...Enter the date when such independent accountant was initially engaged: No FERC FORM No.1 (ED. 12-87) PAGE 101 20150811-8000 08/11/2015 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 CONTROL OVER RESPONDENT 1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the repondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust. All of the outstanding shares of common stock of the Company are owned by Pinnacle West Capital Corporation (formerly AZP Group Inc.) which became the Company's corporate parent effective April 29, 1985 pursuant to a corporate restructuring. The corporate restructuring did not affect any of its outstanding debt securities, all of which remain obligations of the Company. See Pinnacle West Capital Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, as filed with the Securities and Exchange Commission. FERC FORM NO. 1 (ED. 12-96) Page 102 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission CORPORATIONS CONTROLLED BY RESPONDENT 1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. 2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. 3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions 1. See the Uniform System of Accounts for a definition of control. 2. Direct control is that which is exercised without interposition of an intermediary. 3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. 4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party. Line No. Name of Company Controlled Kind of Business (a) (b) 1 Bixco, Inc. Percent Voting Stock Owned (c) Inactive 100 3 APS Foundation, Inc. A non-profit corporation N/A 4 which makes distributions 5 to charitable organizations Footnote Ref. (d) 2 6 7 Axiom Power Solutions, Inc. Inactive 100 Inactive 100 8 9 PWENewco, Inc. 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 FERC FORM NO. 1 (ED. 12-96) Page 103 (1) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 103 Line No.: 3 Column: d (1) The APS Foundation is an Arizona non-profit corporation. The APS Foundation has no stockholders or members, and all voting power is held by the Board of Directors. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission OFFICERS Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. 2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made. Line No. President & Chief Executive Officer (b) Donald E. Brandt Salary for Year (c) 1,240,000 Executive Vice President & Chief Operating Officer Mark A. Schiavoni 563,958 Executive Vice President & Chief Nuclear Officer Randall K. Edington 960,511 Executive Vice President & General Counsel David P. Falck 522,000 Executive Vice President & Chief Financial Officer James R. Hatfield 570,000 Senior Vice President, Site Operations Robert S. Bement 395,000 13 Senior Vice President, Transmission, Distribution & Daniel T. Froetscher 320,625 14 Customers Senior Vice President, Public Policy Jeffrey B. Guldner 364,000 Vice President, Controller & Chief Accounting Officer Denise R. Danner 311,000 Vice President, Transmission and Distribution Operations Patrick Dinkel 273,938 Vice President, Communications John S. Hatfield 279,000 Vice President, Resource Management Tammy D. McLeod 272,383 Vice President & Treasurer Lee R. Nickloy 276,000 Vice President, Human Resources & Ethics Cindy Redding 281,000 1 Title Name of Officer (a) 2 3 4 5 6 7 8 9 10 11 12 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 FERC FORM NO. 1 (ED. 12-96) Page 104 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 104 Line No.: 1 Column: c This amount represents the officer’s total salary, and (for purposes of this report) has not been adjusted to reflect an allocation of the officer’s total salary to any affiliated company where the person also serves as an officer. Schedule Page: 104 Line No.: 3 Column: a Appointed Executive Vice President & Chief Operating Officer on June 18, 2014 (formerly Executive Vice President, Operations). Schedule Page: 104 Line No.: 7 Column: c This amount represents the officer’s total salary, and (for purposes of this report) has not been adjusted to reflect an allocation of the officer’s total salary to any affiliated company where the person also serves as an officer. Schedule Page: 104 Line No.: 9 Column: c This amount represents the officer’s total salary, and (for purposes of this report) has not been adjusted to reflect an allocation of the officer’s total salary to any affiliated company where the person also serves as an officer. Schedule Page: 104 Line No.: 13 Column: a Appointed Senior Vice President, Transmission Distribution & Customers on February 19, 2014 (formerly Vice President, Energy Delivery). Schedule Page: 104 Line No.: 16 Column: a Appointed Senior Vice President, Public Policy on February 19, 2014 (formerly Senior Vice President, Customers & Regulation). Schedule Page: 104 Line No.: 18 Column: c This amount represents the officer’s total salary, and (for purposes of this report) has not been adjusted to reflect an allocation of the officer’s total salary to any affiliated company where the person also serves as an officer. Schedule Page: 104 Line No.: 20 Column: a Appointed Vice President, Transmission & Distribution Operations on February 19, 2014 (formerly Vice President, Resource Management). Schedule Page: 104 Line No.: 24 Column: a Appointed Vice President, Resource Management on February 19, 2014 (formerly Vice President, Chief Customer Officer). Schedule Page: 104 Line No.: 26 Column: c This amount represents the officer’s total salary, and (for purposes of this report) has not been adjusted to reflect an allocation of the officer’s total salary to any affiliated company where the person also serves as an officer. Schedule Page: 104 Line No.: 28 Column: a Designated as Section 16 Officer on May 21, 2014. Ms. Redding left the company, effective December 31, 2014. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission DIRECTORS Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated titles of the directors who are officers of the respondent. 2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk. Line No. Name (and Title) of Director (a) 1 Donald E. Brandt, Chairman, President and CEO Principal Business Address (b) Phoenix, Arizona 2 3 Susan Clark-Johnson Paradise Valley, Arizona 4 5 Denis A. Cortese Fountain Hills, Arizona 6 7 Richard P. Fox Carefree, Arizona 8 9 Michael L. Gallagher Phoenix, Arizona 10 11 Roy A. Herberger, Jr. Phoenix, Arizona 12 13 Dale E. Klein Austin, Texas 14 15 Humberto S. Lopez Tucson, Arizona 16 17 Kathryn L. Munro La Jolla, California 18 19 Bruce J. Nordstrom Flagstaff, Arizona 20 21 David P. Wagener New York, New York 22 23 Note: Currently there is no Executive 24 Committee of the Board of Directors 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 FERC FORM NO. 1 (ED. 12-95) Page 105 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) (1)08/11/2015 An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission INFORMATION ON FORMULA RATES FERC Rate Schedule/Tariff Number FERC Proceeding Does the respondent have formula rates? Year/Period of Report End of 2014/Q4 X Yes No 1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate. Line No. FERC Rate Schedule or Tariff Number FERC Proceeding 1 FERC Electric Tariff, Volume 2 ER11-3638 2 FERC Electric Tariff, Volume 5 ER09-1402 3 FERC Electric Rate Schedule No. 182 ER11-3926 4 WestConnect Point-to-Point Regional Transmission ER13-1296 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 FERC FORM NO. 1 (NEW. 12-08) Page 106 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 106 Line No.: 4 Column: a The WestConnect Tariff does not have any direct FERC Form No. 1 inputs however the relevant input to the WestConnect Tariff is APS's FERC Electric Tariff Volume 2 which does have FERC Form No. 1 inputs. Out of an abundance of caution, APS included the WestConnect Tariff on page 106 of the FERC Form No. 1. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) (1)08/11/2015 An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 INFORMATION ON FORMULA RATES FERC Rate Schedule/Tariff Number FERC Proceeding Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)? X Yes No 2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website Line No. Accession No. 1 20140514-5161 Document Date \ Filed Date Docket No. Description 05/14/2014 ER11-3638 See Footnote FERC Electric Tariff, Volume 2 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 FERC FORM NO. 1 (NEW. 12-08) Formula Rate FERC Rate Schedule Number or Tariff Number Page 106a 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 1061 Line No.: 1 Column: d Informational Filing - Annual Update of Formula Transmission Service Rates - Arizona Public Service Company under ER11-3638. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) (1)08/11/2015 An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 INFORMATION ON FORMULA RATES Formula Rate Variances 1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. 2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. 3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. 4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote. Line No. Page No(s). Schedule Column 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 FERC FORM NO. 1 (NEW. 12-08) Page 106b Line No Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) (1) 08/11/2015 An Original Arizona Public Service Company (2) X A Resubmission Date of Report 04/15/2015 Year/Period of Report 2014/Q4 End of IMPORTANT CHANGES DURING THE QUARTER/YEAR Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears. 1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact. 2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization. 3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission. 4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization. 5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc. 6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee. 7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments. 8. State the estimated annual effect and nature of any important wage scale changes during the year. 9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year. 10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest. 11. (Reserved.) 12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page. 13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period. 14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio. PAGE 108 INTENTIONALLY LEFT BLANK SEE PAGE 109 FOR REQUIRED INFORMATION. FERC FORM NO. 1 (ED. 12-96) Page 108 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 1. The Town of Cave Creek franchise became effective January 4, 2014. The City of Globe franchise was approved by voters on November 4, 2014 and became effective August 22, 2014. The Apache County franchise became effective December 18, 2014. As with all of Arizona Public Service Company’s (“APS”) municipal franchises, the referenced franchises include a 2% franchise fee, which is collected from the customers in the same way that transaction privilege tax (sales tax) is collected, and are renewed for terms of 25 years. County franchises do not include the collection and payment of franchise fees. 2. None. 3. None. 4. None. 5. No important extension or reduction of the transmission or distribution system occurred in 2014 for APS. Only our normal company growth patterns were experienced. 6. Lines of Credit and Short-Term Borrowings The table below presents the credit facilities and the amounts available and outstanding as of December 31, 2014 (dollars in millions): Credit Facility Expiration APS Revolving Credit Facility APS Revolving Credit Facility Total (a) Amount Committed May 2019 April 2018 $ 500 500 1,000 Unused Amount (a) $ 500 353 853 Commitment Fees 0.125% 0.125% At December 31, 2014, APS had $147 million of outstanding commercial paper. Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $853 million. APS maintains committed revolving credit facilities in order to enhance liquidity and provide credit support for its commercial paper programs. On May 9, 2014, APS refinanced its $500 million revolving credit facility that would have matured in November 2016, with a new $500 million facility that matures in May 2019. At December 31, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million credit facility that matures in May 2019 (see above). APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. FERC FORM NO. 1 (ED. 12-96) Page 109.1 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2014, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $147 million at December 31, 2014. Long-Term Debt All of APS’s debt is unsecured. The following table presents the components of long-term debt on the Comparative Balance Sheet outstanding at December 31, 2014 (dollars in thousands): APS Pollution Control Bonds: Variable Fixed Total Pollution Control Bonds Senior unsecured notes Unamortized discount Unamortized premium Total Long-Term Debt (a) (b) Maturity Interest December 31, Dates (a) Rates 2014 2029-2038 2024-2034 (b) $ 0.45%-5.75% 2015-2044 3.35%-8.75% 156,405 249,300 405,705 2,875,000 (9,206) 4,866 3,276,365 $ This schedule does not reflect the timing of redemptions that may occur prior to maturities. The weighted-average rate for the variable rate pollution control bonds was 0.03%-0.27% at December 31, 2014. The following table shows principal payments due on APS’s total long-term debt (dollars in millions): Year APS 2015 $ 357 2017 32 2018 32 2019 500 Thereafter 1,989 Total FERC FORM NO. 1 (ED. 12-96) 370 2016 $ Page 109.2 3,280 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Credit Facilities and Debt Issuances On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024. On January 15, 2014, both of these series of bonds were canceled and refinanced. On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044. The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used in 2013 to re-acquire the two series of tax-exempt indebtedness. On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E, due 2029 in connection with the mandatory tender provisions for this indebtedness. On May 14, 2014, APS remarketed all $36 million of the 2009 Series A Bonds. We expect to remarket or refinance all $64 million of the 2009 Series D Bonds and 2009 Series E Bonds within the next twelve months. On May 30, 2014, APS purchased all $38 million of the Navajo County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034, and on June 1, 2014, APS purchased a total of $64 million of the Navajo 2009 Series B Bonds and 2009 Series C Bonds, in each case, in connection with the mandatory tender provisions for this indebtedness. On September 23, 2014, APS remarketed all $38 million of the 2009 Series A Bonds. On October 1, 2014, APS remarketed all $32 million of the 2009 Series C Bonds. We expect to remarket or refinance all $32 million of the 2009 Series B Bonds within the next twelve months. On June 1, 2014, APS remarketed all $13 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034. On June 18, 2014, APS issued $250 million of 3.35% unsecured senior notes that mature on June 15, 2024. The net proceeds from the sale were used along with other funds to repay at maturity APS’s $300 million aggregate principal amount of 5.80% senior notes due June 30, 2014. On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures. FERC FORM NO. 1 (ED. 12-96) Page 109.3 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Contractual Obligations The following table summarizes APS's contractual requirements as of December 31, 2014 (dollars in millions): 20162017 2015 20182019 Thereafter Total Long-term debt payments, including interest (b) $ 536 $ 685 $ 788 $ 3,653 $ 5,662 Short-term debt payments, including interest (b) 147 — — — 147 618 1,223 1,146 7,994 10,981 46 84 84 448 662 105 154 47 222 528 1 32 37 281 351 17 5 5 63 90 64 57 53 314 488 Fuel and purchased power commitments (c) Renewable energy credits (d) Purchase obligations (e) Coal reclamation Nuclear decommissioning funding requirements Operating lease payments Total contractual commitments (a) (b) (c) (d) (e) $ 1,534 $ 2,240 $ 2,160 $ 12,975 $ 18,909 The long-term debt matures at various dates through 2044 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2014. The short-term debt represents commercial paper borrowings at APS. Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. These amounts include commitments incurred from acquiring SCE’s interest in Four Corners and APS assuming an additional 7% in the 2016 Coal Supply Agreement. Contracts to purchase renewable energy credits in compliance with the RES. These contractual obligations include commitments for capital expenditures and other obligations. This table excludes $45 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. This table also excludes estimated minimum pension contributions of zero for 2015, 2016 and 2017, respectively. Financial Assurances APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2014, approximately $109 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of FERC FORM NO. 1 (ED. 12-96) Page 109.4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) such debt obligations. These letters of credit will expire in 2015, 2016, and 2017. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback. These letters of credit will expire on December 31, 2015, and totaled approximately $23 million at December 31, 2014. Additionally, APS has issued letters of credit to support collateral obligations under a natural gas tolling contract entered into with a third party. At December 31, 2014, that letter of credit totaled $5 million and will expire in 2015. Authorizations On February 6, 2013, the ACC issued a financing order (Decision No. 73659) in which it, subject to specified parameters and procedures, (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017. APS’s issuances of short-term debt are authorized by the ACC in its Decision No. 73659 and/or by Arizona Revised Statutes Section 40-302.D and the issuances of long-term debt are authorized by the ACC in its Decision No. 73659. 7. None. 8. The union and non-union annualized wage scale increases during 2014 through December 31, 2014 were as follows: Type of Cost Number of Increases Annualized Costs a. Union Negotiated 1,521 b. Non-Union Base Salary Increases 3,754 10,479,450 c. Special Increases 633 1,919,174 d. Total Promotions 765 6,673 $ $ 2,624,688 5,008,614 20,031,926 COMMENTS: a. The Palo Verde Nuclear Generating Station (“Palo Verde”) security officers changed their collective bargaining representative from the Security, Police and Fire Professionals of America to the United Security Professionals of America (“USPA”). On June 1, 2014, the USPA ratified a three-year contract. The USPA wage adjustment effective June 1, 2014, was 1.65%. The negotiated union contract for the International Brotherhood of Electrical Workers union wage adjustment effective April 1, 2014 was 2.25%. b. The overall non-union employee merit budget was 3.0%. Actual merit adjustments ranged from 0% to 8.1% based upon an employee’s performance and their pay position within the salary range. Merit pay awards were added FERC FORM NO. 1 (ED. 12-96) Page 109.5 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) to base pay. c. Salary adjustments to base pay were awarded to non-union employees throughout the year in special instances. d. Promotions were awarded to non-union employees due to changes in job functions or grade level changes. 9. Legal Proceedings I. LITIGATION & ENVIRONMENTAL MATTERS UPDATE Environmental Matters Climate Change Legislative Initiatives. There have been no recent attempts by Congress to pass legislation that would regulate greenhouse gas (“GHG”) emissions, and it is unclear if and when the 114th Congress will consider a climate change bill. In the event climate change legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is enacted and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed GHG emissions; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“CO2”) equivalent emitted. In addition to federal legislative initiatives, state-specific initiatives may also impact our business. While Arizona has no pending legislation and no proposed agency rule regulating GHGs in Arizona, the California legislature enacted AB 32 and SB 1368 in 2006 to address GHG emissions. In October 2011, the California Air Resources Board approved final regulations that established a state-wide cap on GHG emissions beginning on January 1, 2013 and established a GHG allowance trading program under that cap. The first phase of the program, which applies to, among other entities, importers of electricity, commenced on January 1, 2013. Under the program, entities selling electricity into California, including APS, must hold carbon allowances to cover GHG emissions associated with electricity sales into California from outside the state. APS is authorized to recover the cost of these carbon allowances through the PSA. Regulatory Initiatives. In 2009, EPA determined that GHG emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that GHGs fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, EPA has the authority to regulate GHG emissions of new motor vehicles under the Clean Air Act. As a result of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new GHG emission thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. “New Source Review,” or “NSR,” is a pre-construction permitting program under the Clean Air Act that requires analysis of pollution controls prior to building a new stationary source or making major modifications to an existing stationary source. The tailoring rule became applicable to power plants in January 2011 FERC FORM NO. 1 (ED. 12-96) Page 109.6 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) and, as a result, APS will generally be required to consider the impact of GHG emissions as part of its traditional NSR analysis for new sources and major modifications to existing plants. Consistent with President Obama’s June 2013 Climate Action Plan addressing his plans to reduce GHG emissions in the United States, pursuant to its endangerment finding and its authority under Section 111(b) of the Clean Air Act, on September 20, 2013, EPA issued a proposed rule, which would establish New Source Performance Standards (“NSPS”) for new fossil-fired power plants. Subsequently, on June 2, 2014, EPA issued two additional proposed rules to regulate GHG emissions from modified and reconstructed electric generating units ("EGUs") pursuant to Section 111(b) of the Clean Air Act and existing fossil fuel-fired power plants pursuant to Clean Air Act Section 111(d). On January 7, 2015, EPA announced that its carbon pollution standards for new, modified and reconstructed, and existing power plants would be finalized in summer 2015. EPA’s proposed rule applicable to modified and reconstructed power plants would require fossil fuel-fired EGUs undergoing modification or reconstruction to meet CO2 performance standards based on a combination of best operating practices and equipment upgrades. The rule would also require existing EGUs that are modified or reconstructed after becoming subject to state or federal standards of performance for existing power plants under Section 111(d) of the Clean Air Act to continue to meet those requirements. We cannot currently predict the shape of any final rules or standards for modified and reconstructed fossil-fired EGUs or assess how they might potentially impact the Company. With respect to existing power plants, EPA’s proposed “Clean Power Plan” rule proposes state-specific goals or targets to achieve reductions in CO2 emissions from existing EGUs measured from a 2012 baseline. EPA’s proposed emission rates would not apply directly to specific units, but must be met on a state-wide basis. As proposed, each state’s goal is an emissions rate, which is a single number for the future carbon intensity of that state. The proposed rule provides guidelines to states to help develop their plans for meeting the interim (2020-2029) and final (2030 and beyond) emission rates set forth in the proposal. States would be required to submit their plans to EPA by summer 2016, although states may be eligible for one- or two-year extensions, provided they submit detailed explanations that contain specified information required by EPA in advance of the applicable due date. EPA’s proposal for Arizona would result in in-state coal-fired generation (with the exception of coal-fired generation located in Indian country) shifting to natural gas combined cycle and renewable generation. Such a substantial change in APS’s generation portfolio could require additional capital investments and increased operating costs, and thus have a significant financial impact on the Company. APS will continue to monitor these standards as they are developed. As for sources in Indian country (which are not subject to state plans), on October 28, 2014, EPA issued a supplemental rule proposing carbon dioxide emission rates for U.S. territories and areas of Indian country with existing fossil fuel-fired EGUs, as well as guidelines for plans to achieve those rates. The supplemental proposal applies to Four Corners and the Navajo Plant, both of which are located on the Navajo Nation. With respect to these two plants, EPA applied the four building blocks described in its June 2, 2014 Clean Air Act Section 111(d) proposal to establish interim and final goals, expressed as CO2 emission rates. If finalized as proposed, it is unlikely the rule would require additional emission reductions as a result of the plants’ past and future actions to comply with the Best Available Retrofit Technology (“BART”) requirements of EPA’s Clean Air Visibility Rule. (See “EPA Environmental Regulation - Regional Haze Rules” discussion below.) Company Response to Climate Change Initiatives. We have undertaken a number of initiatives to address emission concerns, including renewable energy procurement and development, promotion of programs and rates that FERC FORM NO. 1 (ED. 12-96) Page 109.7 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) promote energy conservation, renewable energy use, and energy efficiency. APS currently has a diverse portfolio of renewable resources, including solar, wind, geothermal, biogas, and biomass, and we expect the percentage of renewable energy in our resource portfolio to increase over the coming years. APS prepares an inventory of GHG emissions from its operations. This inventory is reported to EPA under the EPA GHG Reporting Program and is voluntarily communicated to the public in Pinnacle West’s annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com). The report provides information related to the Company and its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report. EPA Environmental Regulation Regional Haze Rules. In 1999, EPA announced regional haze rules to reduce visibility impairment in national parks and wilderness areas. The rules require states (or, for sources located on tribal land, EPA) to determine what pollution control technologies constitute the BART for certain older major stationary sources, including fossil-fired power plants. EPA subsequently issued the Clean Air Visibility Rule, which provides guidelines on how to perform a BART analysis. The Four Corners and Navajo Plant participants’ obligations to comply with EPA’s final BART determinations (and Cholla’s obligations to comply with ADEQ’s and EPA’s determinations), coupled with the financial impact of potential future climate change legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants. Cholla. In 2007, ADEQ required APS to perform a BART analysis for Cholla pursuant to the Clean Air Visibility Rule. APS completed the BART analysis for Cholla and submitted its BART recommendations to ADEQ in early 2008. The recommendations include the installation of certain pollution control equipment that APS believes constitutes BART. ADEQ reviewed APS’s recommendations and submitted its proposed BART State Implementation Plan (“SIP”) for Cholla and other sources in Arizona in early 2011. On December 5, 2012, EPA issued a final BART rule applicable to Cholla. EPA approved ADEQ’s BART emissions limits for sulfur dioxide (“SO2”) and emissions of particulate matter (“PM”), but added a SO2 removal efficiency requirement of 95%. In addition, EPA disapproved ADEQ’s BART determinations for oxides of nitrogen (“NOx”) and promulgated a Federal Implementation Plan ("FIP") establishing a new, more stringent “bubbled” NOx emission rate applicable to the two BART-eligible Cholla units owned by APS and the other BART-eligible unit owned by PacifiCorp. In order to comply with this new rate, APS will be required to install SCR control technology on all three of the BART-eligible Cholla units. APS’s total costs for these post-combustion NOx controls would be approximately $200 million. Under the FIP, APS has five years from December 2012 to complete installation of the equipment and achieve the BART emission limit for NOx. APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014, and the court scheduled oral argument for March 9, 2015. FERC FORM NO. 1 (ED. 12-96) Page 109.8 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment to reduce regional haze is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost-effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA’s BART FIP. Because APS’s proposal involves state and federal rule-making processes, APS is unable to predict when or whether it may ultimately be approved. Four Corners. On August 6, 2012, EPA issued its final BART determination for Four Corners, which requires APS to install and operate SCR control technology on Units 4 and 5 by July 31, 2018. (APS retired Four Corners Units 1-3 on December 30, 2013.) APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be at least $350 million. APS expects to incur certain of these costs during the 2015 through 2017 timeframe, which are included in our capital expenditure estimates. For PM emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBtu and a 20 percent opacity limit, both of which are achievable through operation of Four Corners' existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20 percent opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations. Navajo Plant. On January 18, 2013, EPA issued a proposed BART rule for the Navajo Plant, which would require installation of SCR technology in order to achieve a new, more stringent plant-wide NOx emission limit. In addition, EPA proposed a “better than BART” alternative and solicited comment on other options that could set longer time frames for installing pollution controls if the Navajo Plant can achieve additional emission reductions. On July 26, 2013, a group of stakeholders, including SRP, the operating agent for the Navajo Plant, submitted to EPA two suggested alternatives to BART, which would achieve greater NOx emission reductions and result in greater reasonable progress toward the national visibility goal than EPA’s proposed BART determination. On July 28, 2014, EPA issued a final Navajo Plant BART rule approving the alternative stakeholder plan. Depending on which alternate operating scenario the Navajo Plant participants ultimately select, the required NOx emission reductions could be achieved by either closing one of the three 750 MW units at the plant or curtailing energy production across all three units, such that the emission reductions are commensurate with the closure of approximately one of the Navajo Plant units. APS estimates that its share of costs for upgrades at the Navajo Plant could be up to approximately $200 million. In October 2014, a coalition of environmental groups, an Indian tribe, and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA’s final BART rule for the Navajo Plant. We cannot predict the outcome of this petition. Mercury and other Hazardous Air Pollutants. On December 16, 2011, EPA issued the final Mercury and Air Toxics Standards (“MATS”) rule, which established maximum achievable control technology (“MACT”) standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired power plants. Generally, plants will have three years after the effective date of the rule to achieve compliance. In the case of Cholla and Four Corners, APS will have until April 16, 2016, or a total of four years after the MATS rule’s effective date, to comply with the new MACT standards because the respective permitting authorities granted APS’s requests for one-year compliance date extensions. Similarly, SRP will have until April 16, 2016 to comply with MATS at the Navajo Plant, as a result of a one-year extension granted by EPA and the Navajo Nation EPA. The MATS rule will require APS to install additional pollution control equipment. APS has installed certain of the equipment necessary to meet the anticipated standards. APS estimates that the cost for the remaining FERC FORM NO. 1 (ED. 12-96) Page 109.9 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) equipment necessary to meet these standards is approximately $130 million for Cholla, which would be avoided if EPA approves APS’s compromise proposal discussed under “Regional Haze Rules - Cholla” above. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules. Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of coal combustion residuals (“CCR”), such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million. APS expects to incur certain of these costs during the 2015-2017 timeframe. The amount for Cholla contemplates the closure of Unit 2 in 2016. (See “EPA Environmental Regulation - Regional Haze Rules - Cholla” discussion above.) The Navajo Plant currently disposes of CCR in a dry landfill storage area. At this time, SRP, the operating agent for the Navajo Plant, is analyzing the operations that would be covered by the rule and any resulting compliance costs. Effluent Limitation Guidelines. On April 19, 2013, EPA proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired EGUs. EPA’s proposal offers numerous options (four of which are “preferred alternatives”) that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning wastes operations. The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in waste streams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. We cannot currently predict the shape of EPA’s final rule or whether this action will have a material adverse impact on our financial position, results of operations, or cash flows. EPA is currently subject to a consent decree deadline to finalize the revised guidelines by September 30, 2015. FERC FORM NO. 1 (ED. 12-96) Page 109.10 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Ozone National Ambient Air Quality Standards. On December 17, 2014, EPA published a proposal to revise the primary ground-level ozone national ambient air quality standards (“NAAQS”) currently set at a level of 75 parts per billion (“ppb”). The rule would set a new, more stringent primary standard (intended to protect human health) within the range of 65 to 70 ppb and revise the secondary standard (intended to protect human welfare) to within the same range. In addition, EPA is soliciting comment on alternative standard levels below 65 ppb, and as low as 60 ppb. EPA is accepting public comment on the proposed new ranges for the standards until March 17, 2015, and is under a court-ordered deadline of October 1, 2015 to finalize the rule. As ozone standards become more stringent, our fossil generation units may come under increasing pressure to reduce emissions of nitrogen oxides and volatile organic compounds and to generate emission offsets for new projects or facility expansions located in ozone nonattainment areas. At this time, APS is unable to predict what impact the adoption of these standards may have on its financial position, results of operations, or cash flows. New Source Review. On April 6, 2009, APS received a request from EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. This request is part of a national enforcement initiative that EPA has undertaken under the Clean Air Act. EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the Clean Air Act. Other electric utilities have received and responded to similar Section 114 requests, and several of them have been the subject of notices of violation and lawsuits filed by EPA. APS responded to EPA’s request in August 2009 and is currently unable to predict any resulting actions the EPA may take, including any potential litigation. Clean Air Act Citizen Lawsuit. On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss. We are unable to predict the outcome of this matter. Superfund-Related Matters. The Comprehensive Environmental Response Compensation and Liability Act (“Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot FERC FORM NO. 1 (ED. 12-96) Page 109.11 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) be reasonably estimated. On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. We are unable to predict the outcome of this matter; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Manufactured Gas Plant Sites. Certain properties which APS now owns or which were previously owned by it or its corporate predecessors were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations or cash flows. Navajo Nation Environmental Issues Four Corners and the Navajo Plant are located on the Navajo Reservation and are held under easements granted by the federal government, as well as leases from the Navajo Nation. In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the Navajo Nation Pesticide Act (collectively, the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners and the Navajo Plant. On October 17, 1995, the Four Corners participants and the Navajo Plant participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Plant. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement. In April 2000, the Navajo Nation Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations. On July 12, 2000, the Four Corners participants and the Navajo Plant participants each filed a petition with the Navajo Supreme Court for review of these regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter. On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Plant, and the Navajo Nation executed a Voluntary Compliance Agreement to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter. Water Supply Assured supplies of water are important for APS’s generating plants. At the present time, APS has adequate water to meet its needs. However, the Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the FERC FORM NO. 1 (ED. 12-96) Page 109.12 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) watershed that supplies the area. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of the plant. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners. Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions, which, in addition to future supply conditions, have the potential to impact APS’s operations. San Juan River Adjudication. Both groundwater and surface water in areas important to APS’s operations have been the subject of inquiries, claims, and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss. In addition, APS is a party to a water contract that allows the company to secure water for Four Corners in the event of a water shortage and is a party to a shortage sharing agreement, which provides for the apportionment of water supplies to Four Corners in the event of a water shortage in the San Juan River Basin. Gila River Adjudication. A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Arizona Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’s rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Several of APS’s other power plants are also located within the geographic area subject to the summons. APS’s claims dispute the court’s jurisdiction over APS’s groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Arizona Supreme Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’s water rights claims has been set in this matter. Little Colorado River Adjudication. APS has filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’s claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’s water rights claims has been set in this matter. Although the above matters remain subject to further evaluation, APS does not expect that the described FERC FORM NO. 1 (ED. 12-96) Page 109.13 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) litigation will have a material adverse impact on its financial position, results of operations, or cash flows. Palo Verde Nuclear Generating Station Spent Nuclear Fuel and Waste Disposal On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the DOE in the United States Court of Federal Claims. The lawsuit seeks to recover damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the NWPA. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on current income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016. Southwest Power Outage Regulatory. On September 8, 2011 at approximately 3:30 PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service. Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected. Service to all affected APS customers was restored by 9:15 PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25 AM on September 9. FERC and NERC conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) with their analysis and conclusions as to the causes of the events. The report included recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination. The Joint Report did not address potential reliability violations or an assessment of responsibility of the parties involved. On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS. FERC Staff alleged that each of the named entities violated varying numbers of NERC Reliability Standards. APS was alleged to have violated seven Reliability Standard Requirements. The allegations of violations were preliminary determinations by FERC Staff and did not constitute findings by FERC itself that any violations had occurred. On July 7, 2014, FERC approved a Stipulation and Consent Agreement among FERC’s Office of Enforcement, NERC and APS which resolves all civil and administrative disputes within the jurisdiction of FERC FERC FORM NO. 1 (ED. 12-96) Page 109.14 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) concerning the September 8 event, including FERC’s and NERC’s investigations. In the settlement, APS neither admitted nor denied alleged violations of four Reliability Standard Requirements. APS agreed to pay a civil penalty of $3.25 million, of which $2 million is to be paid in equal parts to the Department of the Treasury and NERC and $1.25 million will be credited as a partial civil penalty offset in exchange for APS completing certain reliability enhancements. Litigation. On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013. On January 13, 2014, the plaintiffs appealed the lower court’s decision. The appeal is now fully briefed and pending before the Ninth Circuit Court of Appeals. We are unable to predict the outcome of this matter. New Mexico Tax Matter On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”). APS’s share of the Assessment is approximately $12 million. For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. We cannot predict the timing or outcome of this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. II. REGULATORY MATTERS Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications. Settlement Agreement The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million. APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The 2012 Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate FERC FORM NO. 1 (ED. 12-96) Page 109.15 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) relief, or any other party to the 2012 Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the 2012 Settlement Agreement. Other key provisions of the 2012 Settlement Agreement include the following: An authorized return on common equity of 10.0%; A capital structure comprised of 46.1% debt and 53.9% common equity; A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012; Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows: Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and Deferral of 100% in all years if Arizona property tax rates decrease; A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, see "Four Corners" below); Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation; Modifications to the Environmental Improvement Surcharge to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually; Modifications to the PSA, including the elimination of the 90/10 sharing provision; A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2009 Settlement Agreement discussed below; Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date; Modification of the TCA to streamline the process for future transmission-related rate changes; and Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS. The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent FERC FORM NO. 1 (ED. 12-96) Page 109.16 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms. Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million. In a final order dated January 7, 2014, the ACC approved the requested budget. Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules are expected to become effective in the second quarter of 2015. In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case. On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million. Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a DSM Plan for review by and approval of the ACC. On June 1, 2012, APS filed its 2013 DSM Plan. In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that FERC FORM NO. 1 (ED. 12-96) Page 109.17 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) included a proposed budget for 2013 of $87.6 million. On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan. The ACC approved a budget of $68.9 million for each of 2013 and 2014. The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules. On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Utility Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rule making has not been initiated and there has been no additional action on the draft to date. PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following: APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate; an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC; the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point); the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC. FERC FORM NO. 1 (ED. 12-96) Page 109.18 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2014 and 2013 (dollars in millions): Year Ended December 31, 2014 Beginning balance Deferred fuel and purchased power costs – current period Amounts charged to customers Ending balance $ $ 2013 21 $ 27 (41) 7 $ 73 (21) (31) 21 The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year. This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh. Any uncollected (overcollected) deferrals during the 2015 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016. Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2014. Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The LFCR adjustment has a year-over-year cap FERC FORM NO. 1 (ED. 12-96) Page 109.19 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques. APS filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012. APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014. The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million effective March 1, 2015. Deregulation On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. A series of workshops in this docket were held in 2014 and another is currently scheduled for February 26, 2015. Net Metering On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules. On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid. ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift. The ACC also required APS to file its next rate case in June 2015, the earliest date contemplated in the 2012 Settlement Agreement. In May 2014, the ACC began conducting a series of workshops to, among other things, evaluate the role and FERC FORM NO. 1 (ED. 12-96) Page 109.20 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) value of the electric grid as it relates to rooftop solar and other issues regarding net metering. On July 22, 2014, the ACC Commissioners voted to reopen the December 2013 net metering decision for the limited purpose of deciding whether to eliminate the requirement that APS file its next rate case in June 2015. The vote included a request that parties comment in the docket about their thoughts on removing the filing date requirement and on the process for the broader discussion regarding rate design. On August 12, 2014, the ACC Commissioners voted to lift the requirement that APS file its next general rate case by June 2015. On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket. Four Corners On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis. This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates. The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $77 million as of December 31, 2014 and is being amortized in rates over 10 years. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement” that, upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group. However, this alternative arrangement was not approved by FERC. In late March 2014, APS and SCE filed requests for rehearing with FERC. Both requests for rehearing were denied on August 14, 2014. Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control. As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement. If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter if it proceeds to arbitration. If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations. FERC FORM NO. 1 (ED. 12-96) Page 109.21 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Cholla After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Cholla Unit 2 by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case. If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($128 million as of December 31, 2014), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted. 10. None. 11. (RESERVED) 12. N/A 13. Board and Officer Elections, Retirements, Resignations and Changes During 2014: Directors – Richard P. Fox joined the Board of Directors on February 19, 2014. David P. Wagener joined the Board of Directors on February 19, 2014. Officers – Stacy Aguayo-Derstine, formerly General Manager, Regulatory Affairs & Compliance, became Vice President, Customer Service and Chief Customer Officer on February 19, 2014. Jessica Pacheco, formerly Director, Government Affairs, became Vice President, State & Local Affairs on February 19, 2014. Pat Dinkel, formerly Vice President, Resource Management, became Vice President, Transmission and Distribution Operations on February 19, 2014. Daniel Froetscher, formerly Vice President, Energy Delivery, became Senior Vice President, Transmission, Distribution & Customers on February 19, 2014. Jeff Guldner, formerly Senior Vice President Customers & Regulation, became Senior Vice President, Public Policy on February 19, 2014. Tammy McLeod, formerly Vice President and Chief Customer Officer, became Vice President, Resource FERC FORM NO. 1 (ED. 12-96) Page 109.22 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Management on February 19, 2014. Cindy Redding, formerly Vice President, Human Resources, APS became Vice President, Human Resources, APS and PNW on May 21, 2014. Mark Schiavoni, formerly Executive Vice President, Operations, APS became Executive Vice President and Chief Operating Officer, APS on June 18, 2014. Cindy Berger, Vice President and Chief Information Officer, resigned July 31, 2014. Bryan Kearney, became Vice President and Chief Information Officer, APS, August 29, 2014. Cindy Redding, Vice President, Human Resources, PNW and APS, left the company, effective December, 2014. Donna Easterly, formerly Director, T&D Construction, APS, became Vice President, Chief Procurement Officer on November 17, 2014. Barbara Gomez, formerly Vice President, Chief Procurement Officer, APS, became Vice President, Human Resources, APS, on November 17, 2014. 14. N/A FERC FORM NO. 1 (ED. 12-96) Page 109.23 Name of RespondentFERC PDF (Unofficial) This Report Is: 20150811-8000 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report 04/15/2015 End of 2014/Q4 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 Ref. Page No. (b) Title of Account (a) UTILITY PLANT Utility Plant (101-106, 114) Construction Work in Progress (107) TOTAL Utility Plant (Enter Total of lines 2 and 3) (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) Net Utility Plant (Enter Total of line 4 less 5) Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) Nuclear Fuel Materials and Assemblies-Stock Account (120.2) Nuclear Fuel Assemblies in Reactor (120.3) Spent Nuclear Fuel (120.4) Nuclear Fuel Under Capital Leases (120.6) (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) Net Nuclear Fuel (Enter Total of lines 7-11 less 12) Net Utility Plant (Enter Total of lines 6 and 13) Utility Plant Adjustments (116) Gas Stored Underground - Noncurrent (117) OTHER PROPERTY AND INVESTMENTS Nonutility Property (121) (Less) Accum. Prov. for Depr. and Amort. (122) Investments in Associated Companies (123) Investment in Subsidiary Companies (123.1) (For Cost of Account 123.1, See Footnote Page 224, line 42) Noncurrent Portion of Allowances Other Investments (124) Sinking Funds (125) Depreciation Fund (126) Amortization Fund - Federal (127) Other Special Funds (128) Special Funds (Non Major Only) (129) Long-Term Portion of Derivative Assets (175) Long-Term Portion of Derivative Assets – Hedges (176) TOTAL Other Property and Investments (Lines 18-21 and 23-31) CURRENT AND ACCRUED ASSETS Cash and Working Funds (Non-major Only) (130) Cash (131) Special Deposits (132-134) Working Fund (135) Temporary Cash Investments (136) Notes Receivable (141) Customer Accounts Receivable (142) Other Accounts Receivable (143) (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) Notes Receivable from Associated Companies (145) Accounts Receivable from Assoc. Companies (146) Fuel Stock (151) Fuel Stock Expenses Undistributed (152) Residuals (Elec) and Extracted Products (153) Plant Materials and Operating Supplies (154) Merchandise (155) Other Materials and Supplies (156) Nuclear Materials Held for Sale (157) Allowances (158.1 and 158.2) FERC FORM NO. 1 (REV. 12-03) Page 110 200-201 200-201 200-201 202-203 202-203 224-225 228-229 227 227 227 227 227 227 202-203/227 228-229 Current Year End of Quarter/Year Balance (c) Prior Year End Balance 12/31 (d) 16,362,625,127 591,741,133 16,954,366,260 6,173,810,334 10,780,555,926 91,065,520 0 268,754,495 0 0 143,553,701 216,266,314 10,996,822,240 0 0 15,792,701,335 486,826,889 16,279,528,224 6,066,369,873 10,213,158,351 94,542,538 0 270,613,867 0 0 146,057,247 219,099,158 10,432,257,509 0 0 5,464,063 1,553,033 0 0 5,585,301 1,711,543 0 0 0 0 0 713,865,964 0 149,570,873 0 24,809,980 0 892,157,847 0 0 0 642,007,189 0 310,070 0 25,363,966 0 671,554,983 0 4,169,751 0 269,525 75,780 924,992 213,576,551 84,033,993 3,094,461 0 100,543 32,263,222 0 0 219,554,841 0 0 0 4,833,925 0 3,434,053 0 268,275 22,960 924,992 212,193,934 86,860,647 3,203,065 0 0 36,597,494 0 0 221,487,770 0 0 0 1,430,190 Name of RespondentFERC PDF (Unofficial) This Report Is: 20150811-8000 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)(Continued) Line No. 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 Title of Account (a) (Less) Noncurrent Portion of Allowances Stores Expense Undistributed (163) Gas Stored Underground - Current (164.1) Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) Prepayments (165) Advances for Gas (166-167) Interest and Dividends Receivable (171) Rents Receivable (172) Accrued Utility Revenues (173) Miscellaneous Current and Accrued Assets (174) Derivative Instrument Assets (175) (Less) Long-Term Portion of Derivative Instrument Assets (175) Derivative Instrument Assets - Hedges (176) (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 Total Current and Accrued Assets (Lines 34 through 66) DEFERRED DEBITS Unamortized Debt Expenses (181) Extraordinary Property Losses (182.1) Unrecovered Plant and Regulatory Study Costs (182.2) Other Regulatory Assets (182.3) Prelim. Survey and Investigation Charges (Electric) (183) Preliminary Natural Gas Survey and Investigation Charges 183.1) Other Preliminary Survey and Investigation Charges (183.2) Clearing Accounts (184) Temporary Facilities (185) Miscellaneous Deferred Debits (186) Def. Losses from Disposition of Utility Plt. (187) Research, Devel. and Demonstration Expend. (188) Unamortized Loss on Reaquired Debt (189) Accumulated Deferred Income Taxes (190) Unrecovered Purchased Gas Costs (191) Total Deferred Debits (lines 69 through 83) TOTAL ASSETS (lines 14-16, 32, 67, and 84) FERC FORM NO. 1 (REV. 12-03) Page 111 Ref. Page No. (b) 227 230a 230b 232 233 352-353 234 Current Year End of Quarter/Year Balance (c) Prior Year End Balance 12/31 (d) 0 -666,160 0 0 32,841,380 0 0 0 100,532,928 78,019,463 53,372,804 24,809,980 0 0 795,999,097 0 194,192 0 0 166,819,177 0 0 0 96,795,553 50,138,722 49,951,095 25,363,966 0 0 898,552,023 24,641,862 0 0 1,147,084,875 6,170,684 0 0 311,939 0 121,840,013 0 0 17,845,003 851,497,364 0 2,169,391,740 14,854,370,924 21,860,302 0 0 760,685,480 6,162,563 0 0 177,025 0 108,864,622 0 0 18,207,479 736,088,965 0 1,652,046,436 13,654,410,951 Name of RespondentFERC PDF (Unofficial) This Report is: 20150811-8000 08/11/2015 (1) An Original Arizona Public Service Company (2) x A Resubmission Date of Report (mo, da, yr) Year/Period of Report 04/15/2015 end of 2014/Q4 COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 Ref. Page No. (b) Title of Account (a) PROPRIETARY CAPITAL Common Stock Issued (201) Preferred Stock Issued (204) Capital Stock Subscribed (202, 205) Stock Liability for Conversion (203, 206) Premium on Capital Stock (207) Other Paid-In Capital (208-211) Installments Received on Capital Stock (212) (Less) Discount on Capital Stock (213) (Less) Capital Stock Expense (214) Retained Earnings (215, 215.1, 216) Unappropriated Undistributed Subsidiary Earnings (216.1) (Less) Reaquired Capital Stock (217) Noncorporate Proprietorship (Non-major only) (218) Accumulated Other Comprehensive Income (219) Total Proprietary Capital (lines 2 through 15) LONG-TERM DEBT Bonds (221) (Less) Reaquired Bonds (222) Advances from Associated Companies (223) Other Long-Term Debt (224) Unamortized Premium on Long-Term Debt (225) (Less) Unamortized Discount on Long-Term Debt-Debit (226) Total Long-Term Debt (lines 18 through 23) OTHER NONCURRENT LIABILITIES Obligations Under Capital Leases - Noncurrent (227) Accumulated Provision for Property Insurance (228.1) Accumulated Provision for Injuries and Damages (228.2) Accumulated Provision for Pensions and Benefits (228.3) Accumulated Miscellaneous Operating Provisions (228.4) Accumulated Provision for Rate Refunds (229) Long-Term Portion of Derivative Instrument Liabilities Long-Term Portion of Derivative Instrument Liabilities - Hedges Asset Retirement Obligations (230) Total Other Noncurrent Liabilities (lines 26 through 34) CURRENT AND ACCRUED LIABILITIES Notes Payable (231) Accounts Payable (232) Notes Payable to Associated Companies (233) Accounts Payable to Associated Companies (234) Customer Deposits (235) Taxes Accrued (236) Interest Accrued (237) Dividends Declared (238) Matured Long-Term Debt (239) FERC FORM NO. 1 (rev. 12-03) Page 112 250-251 250-251 253 252 254 254b 118-119 118-119 250-251 122(a)(b) 256-257 256-257 256-257 256-257 262-263 Current Year End of Quarter/Year Balance (c) Prior Year End Balance 12/31 (d) 178,162,368 0 0 0 2,398,807,686 18,400,365 0 0 37,511,652 1,968,719,143 0 0 0 -48,332,631 4,478,245,279 178,162,367 0 0 0 2,398,807,686 18,400,365 0 0 37,511,652 1,804,398,273 0 0 0 -53,372,420 4,308,884,619 405,705,000 0 0 2,902,577,791 4,866,574 9,206,464 3,303,942,901 501,705,000 0 0 2,701,160,250 5,046,818 8,732,214 3,199,179,854 193,313,000 0 873,663 467,078,279 0 359,288 80,257,408 2,732,932 390,749,875 1,135,364,445 0 0 3,959,659 511,752,635 0 449,958 68,396,015 3,727,064 346,728,858 935,014,189 147,400,000 289,929,529 0 92,873,341 72,306,606 142,296,215 53,343,674 0 0 153,125,000 281,209,063 0 65,802,221 76,100,770 132,509,537 43,480,287 0 0 Name of RespondentFERC PDF (Unofficial) This Report is: 20150811-8000 08/11/2015 (1) An Original Arizona Public Service Company (2) x A Resubmission Date of Report (mo, da, yr) 04/15/2015 Year/Period of Report end of 2014/Q4 (continued) COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS) Line No. 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 Ref. Page No. (b) Title of Account (a) Matured Interest (240) Tax Collections Payable (241) Miscellaneous Current and Accrued Liabilities (242) Obligations Under Capital Leases-Current (243) Derivative Instrument Liabilities (244) (Less) Long-Term Portion of Derivative Instrument Liabilities Derivative Instrument Liabilities - Hedges (245) (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges Total Current and Accrued Liabilities (lines 37 through 53) DEFERRED CREDITS Customer Advances for Construction (252) Accumulated Deferred Investment Tax Credits (255) Deferred Gains from Disposition of Utility Plant (256) Other Deferred Credits (253) Other Regulatory Liabilities (254) Unamortized Gain on Reaquired Debt (257) Accum. Deferred Income Taxes-Accel. Amort.(281) Accum. Deferred Income Taxes-Other Property (282) Accum. Deferred Income Taxes-Other (283) Total Deferred Credits (lines 56 through 64) TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) FERC FORM NO. 1 (rev. 12-03) Page 113 266-267 269 278 272-277 Current Year End of Quarter/Year Balance (c) Prior Year End Balance 12/31 (d) 0 422 147,671,684 21,497,000 164,873,458 80,257,408 4,178,126 2,732,932 1,053,379,715 0 27,468 134,990,364 0 117,899,543 68,396,015 4,763,025 3,727,064 937,784,199 123,052,363 178,607,210 4,586,550 276,477,009 899,167,049 371,685 0 2,877,990,083 523,186,635 4,883,438,584 14,854,370,924 114,480,403 152,360,982 9,160,343 299,143,458 579,972,326 414,988 0 2,804,996,655 313,018,935 4,273,548,090 13,654,410,951 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission STATEMENT OF INCOME Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of Quarterly 1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. 2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. 3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. 4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. 5. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable 5. Do not report fourth quarter data in columns (e) and (f) 6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. 7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Line No. Title of Account (a) (Ref.) Page No. (b) Total Current Year to Date Balance for Quarter/Year (c) Total Prior Year to Date Balance for Quarter/Year (d) 1 UTILITY OPERATING INCOME 300-301 3,522,222,472 3,484,980,000 4 Operation Expenses (401) 320-323 1,865,748,372 1,840,918,347 5 Maintenance Expenses (402) 320-323 241,133,018 205,013,800 6 Depreciation Expense (403) 336-337 367,155,333 364,365,935 7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337 -923,459 13,735,530 8 Amort. & Depl. of Utility Plant (404-405) 336-337 71,678,968 73,809,369 9 Amort. of Utility Plant Acq. Adj. (406) 336-337 453,060 2 Operating Revenues (400) 3 Operating Expenses 55,045 10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 55,045 11 Amort. of Conversion Expenses (407) 278,697 12 Regulatory Debits (407.3) 31,942,337 37,203,441 14 Taxes Other Than Income Taxes (408.1) 262-263 198,164,185 188,826,131 15 Income Taxes - Federal (409.1) 262-263 39,109,116 3,245,463 13 (Less) Regulatory Credits (407.4) 15,398,957 12,961,071 17 Provision for Deferred Income Taxes (410.1) 234, 272-277 1,152,367,603 1,246,330,031 18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 960,800,421 1,001,413,891 4,573,793 4,573,793 16 - Other (409.1) 19 Investment Tax Credit Adj. - Net (411.4) 262-263 266 20 (Less) Gains from Disp. of Utility Plant (411.6) 21 Losses from Disp. of Utility Plant (411.7) 53,143 145,409 393,324 281,309 25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 2,953,642,525 2,906,205,497 26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 568,579,947 578,774,503 22 (Less) Gains from Disposition of Allowances (411.8) 23 Losses from Disposition of Allowances (411.9) 24 Accretion Expense (411.10) FERC FORM NO. 1/3-Q (REV. 02-04) Page 114 Current 3 Months Ended Quarterly Only No 4th Quarter (e) Prior 3 Months Ended Quarterly Only No 4th Quarter (f) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission STATEMENT OF INCOME FOR THE YEAR (Continued) 9. Use page 122 for important notes regarding the statement of income for any account thereof. 10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. 11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income, and expense accounts. 12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122. 13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. 14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. 15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule. ELECTRIC UTILITY Current Year to Date Previous Year to Date (in dollars) (in dollars) (g) (h) GAS UTILITY Current Year to Date Previous Year to Date (in dollars) (in dollars) (j) (i) OTHER UTILITY Current Year to Date Previous Year to Date (in dollars) (in dollars) (k) (l) Line No. 1 3,522,222,472 3,484,980,000 1,865,748,372 1,840,918,347 4 241,133,018 205,013,800 5 367,155,333 364,365,935 6 -923,459 13,735,530 7 71,678,968 73,809,369 8 2 3 453,060 55,045 9 55,045 10 11 278,697 12 31,942,337 37,203,441 13 198,164,185 188,826,131 14 39,109,116 3,245,463 15 15,398,957 12,961,071 16 1,152,367,603 1,246,330,031 17 960,800,421 1,001,413,891 18 4,573,793 4,573,793 53,143 145,409 22 393,324 281,309 23 2,953,642,525 2,906,205,497 25 568,579,947 578,774,503 26 19 20 21 24 FERC FORM NO. 1 (ED. 12-96) Page 115 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission STATEMENT OF INCOME FOR THE YEAR (continued) Line No. TOTAL Title of Account (a) 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 Date of Report (Mo, Da, Yr) 04/15/2015 Net Utility Operating Income (Carried forward from page 114) Other Income and Deductions Other Income Nonutilty Operating Income Revenues From Merchandising, Jobbing and Contract Work (415) (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) Revenues From Nonutility Operations (417) (Less) Expenses of Nonutility Operations (417.1) Nonoperating Rental Income (418) Equity in Earnings of Subsidiary Companies (418.1) Interest and Dividend Income (419) Allowance for Other Funds Used During Construction (419.1) Miscellaneous Nonoperating Income (421) Gain on Disposition of Property (421.1) TOTAL Other Income (Enter Total of lines 31 thru 40) Other Income Deductions Loss on Disposition of Property (421.2) Miscellaneous Amortization (425) Donations (426.1) Life Insurance (426.2) Penalties (426.3) Exp. for Certain Civic, Political & Related Activities (426.4) Other Deductions (426.5) TOTAL Other Income Deductions (Total of lines 43 thru 49) Taxes Applic. to Other Income and Deductions Taxes Other Than Income Taxes (408.2) Income Taxes-Federal (409.2) Income Taxes-Other (409.2) Provision for Deferred Inc. Taxes (410.2) (Less) Provision for Deferred Income Taxes-Cr. (411.2) Investment Tax Credit Adj.-Net (411.5) (Less) Investment Tax Credits (420) TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) Net Other Income and Deductions (Total of lines 41, 50, 59) Interest Charges Interest on Long-Term Debt (427) Amort. of Debt Disc. and Expense (428) Amortization of Loss on Reaquired Debt (428.1) (Less) Amort. of Premium on Debt-Credit (429) (Less) Amortization of Gain on Reaquired Debt-Credit (429.1) Interest on Debt to Assoc. Companies (430) Other Interest Expense (431) (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) Net Interest Charges (Total of lines 62 thru 69) Income Before Extraordinary Items (Total of lines 27, 60 and 70) Extraordinary Items Extraordinary Income (434) (Less) Extraordinary Deductions (435) Net Extraordinary Items (Total of line 73 less line 74) Income Taxes-Federal and Other (409.3) Extraordinary Items After Taxes (line 75 less line 76) Net Income (Total of line 71 and 77) FERC FORM NO. 1/3-Q (REV. 02-04) (Ref.) Page No. (b) Current Year (c) Previous Year (d) 568,579,947 578,774,503 947,281 915,724 1,500 23,504 75,419 1,650,649 1,543,572 1,500 32,197 -13,827 688,652 30,789,970 98,193,348 1,196,300 130,953,242 1,233,974 25,580,709 97,736,853 1,023,778 125,637,867 615,446 4,992,387 1,998,442 2,273,592 -2,492,000 2,883,694 104,534,926 107,540,508 21,024 3,536,631 104,981,817 115,805,451 708,811 646,451 199,519 268,954 2,844,230 783,986 -5,123,683 -978,731 264,020 1,710,509 5,946,124 -6,966,619 30,379,353 4,219,845 -10,984,762 20,817,178 183,271,589 2,955,733 1,435,287 180,243 43,303 183,092,440 2,870,178 1,353,951 135,183 43,303 5,756,428 15,457,061 177,738,430 421,220,870 2,346,420 14,861,472 174,623,031 424,968,650 421,220,870 424,968,650 119 262-263 262-263 262-263 234, 272-277 234, 272-277 262-263 Page 117 Year/Period of Report 2014/Q4 End of Current 3 Months Ended Quarterly Only No 4th Quarter (e) Prior 3 Months Ended Quarterly Only No 4th Quarter (f) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of X A Resubmission STATEMENT OF RETAINED EARNINGS 1. Do not report Lines 49-53 on the quarterly version. 2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated undistributed subsidiary earnings for the year. 3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 - 439 inclusive). Show the contra primary account affected in column (b) 4. State the purpose and amount of each reservation or appropriation of retained earnings. 5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items in that order. 6. Show dividends for each class and series of capital stock. 7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings. 8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. 9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 Contra Primary Account Affected (b) Item (a) Line No. UNAPPROPRIATED RETAINED EARNINGS (Account 216) Balance-Beginning of Period Changes Adjustments to Retained Earnings (Account 439) Current Quarter/Year Year to Date Balance Previous Quarter/Year Year to Date Balance (c) (d) 1,804,398,273 1,624,229,623 421,220,870 424,968,650 -256,900,000 ( 244,800,000) -256,900,000 ( 244,800,000) 1,968,719,143 1,804,398,273 TOTAL Credits to Retained Earnings (Acct. 439) TOTAL Debits to Retained Earnings (Acct. 439) Balance Transferred from Income (Account 433 less Account 418.1) Appropriations of Retained Earnings (Acct. 436) TOTAL Appropriations of Retained Earnings (Acct. 436) Dividends Declared-Preferred Stock (Account 437) TOTAL Dividends Declared-Preferred Stock (Acct. 437) Dividends Declared-Common Stock (Account 438) 234 TOTAL Dividends Declared-Common Stock (Acct. 438) Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings Balance - End of Period (Total 1,9,15,16,22,29,36,37) APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 FERC FORM NO. 1/3-Q (REV. 02-04) Page 118 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of X A Resubmission STATEMENT OF RETAINED EARNINGS 1. Do not report Lines 49-53 on the quarterly version. 2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated undistributed subsidiary earnings for the year. 3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 - 439 inclusive). Show the contra primary account affected in column (b) 4. State the purpose and amount of each reservation or appropriation of retained earnings. 5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items in that order. 6. Show dividends for each class and series of capital stock. 7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings. 8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. 9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123. Line No. Contra Primary Account Affected (b) Item (a) 41 42 43 44 45 TOTAL Appropriated Retained Earnings (Account 215) APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1) 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1) 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly 49 Balance-Beginning of Year (Debit or Credit) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 Write off Investment in Sub 53 Balance-End of Year (Total lines 49 thru 52) FERC FORM NO. 1/3-Q (REV. 02-04) Page 119 Current Quarter/Year Year to Date Balance Previous Quarter/Year Year to Date Balance (c) (d) 1,968,719,143 1,804,398,273 7,746 ( 7,746) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission STATEMENT OF CASH FLOWS Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost. Line No. Description (See Instruction No. 1 for Explanation of Codes) (a) Current Year to Date Quarter/Year (b) Previous Year to Date Quarter/Year (c) 1 Net Cash Flow from Operating Activities: 2 Net Income (Line 78(c) on page 117) 421,220,870 424,968,650 4 Depreciation and Depletion 366,231,874 378,102,464 5 Amortization of UTL PLT; ACQ; ADJ; Prop Loss; Reg Study; Nuclear Fuel 119,652,444 113,274,674 3 Noncash Charges (Credits) to Income: 6 7 Deferred Fuel and Purchased Power 8 Deferred Income Taxes (Net) 13,829,926 52,875,203 164,038,909 242,354,156 9 Investment Tax Credit Adjustment (Net) 26,246,228 52,541,890 10 Net (Increase) Decrease in Receivables -56,202,973 -48,502,189 7,127,553 -10,447,810 11 Net (Increase) Decrease in Inventory 12 Net (Increase) Decrease in Allowances Inventory -3,403,735 -1,430,190 13 Net Increase (Decrease) in Payables and Accrued Expenses 21,416,488 36,655,168 -74,694,494 -94,291,367 15 Net Increase (Decrease) in Other Regulatory Liabilities 14 Net (Increase) Decrease in Other Regulatory Assets 66,971,000 68,247,716 16 (Less) Allowance for Other Funds Used During Construction 30,789,970 25,580,709 105,711,689 -99,966,276 28,538,220 -23,677,542 -97,657,825 85,506,002 1,078,236,204 1,150,629,840 -844,836,115 -983,838,703 -76,296,155 -13,885,779 15,457,061 14,861,471 20,325,000 41,090,000 -916,264,331 -971,495,953 356,194,667 446,025,217 17 (Less) Undistributed Earnings from Subsidiary Companies 18 Other (provide details in footnote): 19 Other Current Assets 20 Other Current Liabilities 21 Other Long Term Assets/Liabilities Net 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 23 24 Cash Flows from Investment Activities: 25 Construction and Acquisition of Plant (including land): 26 Gross Additions to Utility Plant (less nuclear fuel) 27 Gross Additions to Nuclear Fuel 28 Gross Additions to Common Utility Plant 29 Gross Additions to Nonutility Plant 30 (Less) Allowance for Other Funds Used During Construction 31 Other (provide details in footnote): 32 Contributions in Aid of Construction 33 34 Cash Outflows for Plant (Total of lines 26 thru 33) 35 36 Acquisition of Other Noncurrent Assets (d) 37 Proceeds from Disposal of Noncurrent Assets (d) 38 39 Investments in and Advances to Assoc. and Subsidiary Companies 40 Contributions and Advances from Assoc. and Subsidiary Companies 41 Disposition of Investments in (and Advances to) 42 Associated and Subsidiary Companies 43 Proceeds from Nuclear Decommissioning Trust and Sales 44 Purchase of Investment Securities (a) 45 Proceeds from Sales of Investment Securities (a) FERC FORM NO. 1 (ED. 12-96) Page 120 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission STATEMENT OF CASH FLOWS Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost. Line No. Description (See Instruction No. 1 for Explanation of Codes) (a) Current Year to Date Quarter/Year (b) Previous Year to Date Quarter/Year (c) 46 Loans Made or Purchased 47 Collections on Loans 48 Investment in Nuclear Decommissioning Trust and Sales -373,443,610 -463,274,160 11,048,052 -18,597,999 346,784 -2,067,938 -922,118,438 -1,009,410,833 606,126,000 136,307,000 49 Net (Increase) Decrease in Receivables 50 Net (Increase ) Decrease in Inventory 51 Net (Increase) Decrease in Allowances Held for Speculation 52 Net Increase (Decrease) in Payables and Accrued Expenses 53 Other (provide details in footnote): 54 Investments and Other Assets 55 56 Net Cash Provided by (Used in) Investing Activities 57 Total of lines 34 thru 55) 58 59 Cash Flows from Financing Activities: 60 Proceeds from Issuance of: 61 Long-Term Debt (b) 62 Preferred Stock 63 Common Stock 64 Other (provide details in footnote): 65 66 Net Increase in Short-Term Debt (c) 60,950,000 67 Other (provide details in footnote): 68 69 70 Cash Provided by Outside Sources (Total 61 thru 69) 606,126,000 197,257,000 -502,129,000 -96,150,000 71 72 Payments for Retirement of: 73 Long-term Debt (b) 74 Preferred Stock 75 Common Stock 76 Other (provide details in footnote): 77 78 Net Decrease in Short-Term Debt (c) -5,725,000 79 80 Dividends on Preferred Stock 81 Dividends on Common Stock -253,600,000 -242,100,000 -155,328,000 -140,993,000 789,766 226,007 3,725,288 3,499,281 4,515,054 3,725,288 82 Net Cash Provided by (Used in) Financing Activities 83 (Total of lines 70 thru 81) 84 85 Net Increase (Decrease) in Cash and Cash Equivalents 86 (Total of lines 22,57 and 83) 87 88 Cash and Cash Equivalents at Beginning of Period 89 90 Cash and Cash Equivalents at End of period FERC FORM NO. 1 (ED. 12-96) Page 121 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 120 Line No.: 19 Risk Management Prepaids Column: b $ $ Schedule Page: 120 Line No.: 19 Risk Management Prepaids Purchase of SCE Inventory Retirement of Units 1-3 inventory Schedule Page: 120 Line No.: 20 Accrued Taxes Employee Benefits Palo Verde Sale Leaseback Exchange SCE Right of Way Carbon Allowance Tolling Agreements Interest Accrued Customer Deposits Risk Management Payroll Accrual Other Column: c $ 33,107,030 (134,671,716) 6,067,410 (4,469,000) $ (99,966,276) Column: b $ $ Schedule Page: 120 Line No.: 20 Accrued Taxes Employee Benefits Palo Verde Sale Leaseback Exchange SCE Right of Way Carbon Allowance Crisis Bill Assistance Tolling Agreements Interest Accrued Customer Deposits FERC Risk Management Payroll Accrual Other Line No.: 21 Utility Plant FERC FORM NO. 1 (ED. 12-87) 9,787,678 9,502,694 (4,634) 1,484,640 2,279,271 3,408,027 1,511,300 9,863,387 (3,794,164) (75,000) (2,761,795) (2,663,184) 28,538,220 Column: c $ $ Schedule Page: 120 (28,266,108) 133,977,797 105,711,689 6,453,257 (3,436,114) (43,583) 190,559 1,442,326 1,460,372 (1,000,000) 1,305,600 (5,261,261) (3,587,736) (4,818,118) (17,945,000) (57,956) 1,620,112 (23,677,542) Column: b $ (37,590,372) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Nuclear Decommissioning Trust Tolling Agreements Risk Management High Lonesome Wind Ranch Tax Credit Superfund Information Systems Maintenance Line of Credit Customer Advances for Construction Rouse Lease Palo Verde Water Supply Palo Verde Sale/Leaseback Deferred Fuel MTM Coal Reclamation Post-Employment Benefits Depreciation Fund Regulatory Asset Amortization OPEB Transmission Termination Agreement Other $ Schedule Page: 120 Line No.: 21 Utility Plant Nuclear Decommissioning Trust Tolling Agreements Risk Management Banked Energy Prepaid Insurance Transmission Debits SCE Right of Way Superfund Information Systems Maintenance Line of Credit Customer Advances for Construction Rouse Lease Palo Verde Water Supply Palo Verde Sale/Leaseback Deferred Fuel MTM Coal Reclamation Post-Employment Benefits Depreciation Fund Regulatory Asset Amortization Tax Receivable Other Column: c $ $ FERC FORM NO. 1 (ED. 12-87) 17,248,943 (6,701,732) 64,010,940 (1,083,722) (176,453) (2,495,797) 201,002 10,095,245 (3,769,372) 219,765 (4,747,579) (63,672,305) (9,161,037) (32,930,945) (71,858,774) 30,234,588 28,194,507 6,000,000 (19,674,727) (97,657,825) (30,019,519) 17,248,943 (3,264,032) (4,735,228) 3,855,372 889,551 345,366 (6,305,223) (381,596) 470,862 1,032,232 7,537,161 (3,692,289) (1,962,896) (4,747,579) 6,208,680 88,593,408 (17,037,433) (71,381,765) 35,784,777 65,498,000 1,569,210 85,506,002 Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 120 Line No.: 54 Post-Employment Benefits Other Column: b $ $ Schedule Page: 120 Line No.: 54 Post-Employment Benefits Other Column: c $ $ FERC FORM NO. 1 (ED. 12-87) 385,367 (38,583) 346,784 (1,762,694) (305,244) (2,067,938) Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) (1) 08/11/2015 An Original Arizona Public Service Company (2) X A Resubmission Date of Report 04/15/2015 Year/Period of Report End of 2014/Q4 NOTES TO FINANCIAL STATEMENTS 1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement. 2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock. 3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof. 4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts. 5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions. 6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein. 7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted. 8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred. 9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein. PAGE 122 INTENTIONALLY LEFT BLANK SEE PAGE 123 FOR REQUIRED INFORMATION. FERC FORM NO. 1 (ED. 12-96) Page 122 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 1. Other Comprehensive Basis of Accounting The accompanying financial statements were prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America. These differences include items, such as reporting certain derivatives in the income statement and balance sheet on a gross basis, reporting cost of removal in accumulated provision for depreciation, not separately reporting current accounts for deferred income taxes or long term debt, requiring deferred tax assets and liabilities to be shown gross on the balance sheet, classifying guidance on accounting for uncertainty in income tax liabilities on temporary differences as deferred income tax liabilities, including intangible assets in net utility plant, reclassification of certain risk management assets and liabilities, the non-consolidation of certain variable interest entities on the Comparative Balance Sheet, including prior year financial data for informational purposes only, including certain differences related to capital leases, and certain other items. APS’s notes to financial statements have been combined with Pinnacle West Capital Corporation’s financial statements and are prepared with generally accepted accounting principles, accordingly certain footnotes are not reflective of APS’s financial statements contained herein. 2. Summary of Significant Accounting Policies Nature of Operations APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. Accounting Records and Use of Estimates Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulatory Accounting APS is regulated by the Arizona Corporation Commission and the Federal Energy Regulatory Commission. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers. Management continually assesses whether our regulatory assets are probable of future recovery by FERC FORM NO. 1 (ED. 12-88) Page 123.1 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. See Note 4 for additional information. Electric Revenues We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes. Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on APS’s Comparative Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We report these book-outs on a gross basis, presenting both revenues and fuel and purchased power costs. For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 Settlement Agreement (see Note 4). Effective July 1, 2012, as a result of the 2012 Settlement Agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues. Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed. Allowance for Doubtful Accounts The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment. Property, Plant and Equipment Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes: FERC FORM NO. 1 (ED. 12-88) Page 123.2 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) material and labor; contractor costs; capitalized leases; construction overhead costs (where applicable); and allowance for funds used during construction. We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12. APS records a regulatory liability for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance. We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2014 were as follows: Fossil plant — 19 years; Nuclear plant — 28 years; Other generation — 25 years; Transmission — 38 years; Distribution — 33 years; and Other — 7 years. Pursuant to an ACC order, we deferred operating costs in 2013 and 2014 related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. See Note 4 for further discussion. These costs were deferred on the regulatory credits line and will be amortized on the regulatory debits line of the Comparative Statements of Income. For the years 2012 through 2014, the depreciation rates ranged from a low of 0.30% to a high of 12.08%. The weighted-average rate was 2.77% for 2014, 3.00% for 2013, and 2.71% for 2012. Allowance for Funds Used During Construction AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Comparative Statements of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation. AFUDC was calculated by using a composite rate of 8.47% for 2014, 8.56% for 2013, and 8.60% for 2012. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service. FERC FORM NO. 1 (ED. 12-88) Page 123.3 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Materials and Supplies APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered. Fair Value Measurements We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 7). Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. See Note 13 for additional information about fair value measurements. Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Comparative Statements of Income, but does not impact our financial condition, net income or cash flows. We account for our derivative contracts in accordance with derivatives and hedging guidance, which FERC FORM NO. 1 (ED. 12-88) Page 123.4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported gross on the balance sheet. See Note 15 for additional information about our derivative instruments. Loss Contingencies and Environmental Liabilities APS is involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, APS records a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred. Retirement Plans and Other Benefits Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. Pinnacle West also sponsors another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 8 for additional information on pension and other postretirement benefits. Nuclear Fuel APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense. APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through August 2014, at which point the DOE suspended the fee. In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred claims and an offsetting regulatory liability through the settlement period ending December of 2016. See Note 11 for information on spent nuclear fuel disposal costs. Income Taxes Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes. Pinnacle West Capital Corporation files the federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. FERC FORM NO. 1 (ED. 12-88) Page 123.5 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Cash and Cash Equivalents We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. The following table summarizes supplemental APS cash flow information for each of the last two years (dollars in thousands): Year ended December 31, 2014 Cash paid (received) during the period for: Income taxes, net of refunds Interest, net of amounts capitalized Significant non-cash investing and financing activities: Accrued capital expenditures Dividends declared but not paid Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 4) 2013 $ (86,054) $ 173,436 7,524 180,757 $ 44,712 $ 65,800 33,184 62,500 — 145,609 Intangible Assets We have no goodwill recorded and have separately disclosed other intangible assets, primarily software. The intangible assets are amortized over their finite useful lives. Amortization expense was $53 million in 2014, and $53 million in 2013. Estimated amortization expense on existing intangible assets over the next five years is $42 million in 2015, $32 million in 2016, $21 million in 2017, $9 million in 2018, and $3 million in 2019. At December 31, 2014, the weighted-average remaining amortization period for intangible assets was 6 years. Investments Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 17 for more information on these investments. Preferred Stock At December 31, 2014, APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding. Subsequent Events Management evaluates events or transactions that occur after the balance sheet date, but before the financial statements are issued or available to be issued for potential recognition or disclosures in the financial statements as required by GAAP. We have evaluated subsequent events for recognition in the financial statements through February 20, 2015, which is the date the financial statements, prepared in accordance with accounting principles generally accepted in the United States of America, were issued. Management updated such evaluation for disclosure purposes through April 15, 2015. The accompanying statements contain all adjustments and disclosures necessary for fair presentation. FERC FORM NO. 1 (ED. 12-88) Page 123.6 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 3. New Accounting Standards In May 2014, new revenue recognition guidance was issued. This guidance provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The new guidance is effective for us on January 1, 2017, and may be adopted using full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We are currently evaluating this new guidance and the impacts it may have on our financial statements. 4. Regulatory Matters Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications. Settlement Agreement The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million. APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The 2012 Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the 2012 Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the 2012 Settlement Agreement. Other key provisions of the 2012 Settlement Agreement include the following: An authorized return on common equity of 10.0%; A capital structure comprised of 46.1% debt and 53.9% common equity; A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012; Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows: Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and FERC FORM NO. 1 (ED. 12-88) Page 123.7 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) subsequent years if Arizona property tax rates increase; and Deferral of 100% in all years if Arizona property tax rates decrease; A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, see "Four Corners" below); Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation; Modifications to the Environmental Improvement Surcharge to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually; Modifications to the PSA, including the elimination of the 90/10 sharing provision; A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2009 Settlement Agreement discussed below; Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date; Modification of the TCA to streamline the process for future transmission-related rate changes; and Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS. The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms. Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and FERC FORM NO. 1 (ED. 12-88) Page 123.8 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) requesting a 2014 RES budget of approximately $143 million. In a final order dated January 7, 2014, the ACC approved the requested budget. Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules are expected to become effective in the second quarter of 2015. In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case. On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the budget to approximately $152 million. Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a DSM Plan for review by and approval of the ACC. On June 1, 2012, APS filed its 2013 DSM Plan. In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million. On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan. The ACC approved a budget of $68.9 million for each of 2013 and 2014. The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules. On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible FERC FORM NO. 1 (ED. 12-88) Page 123.9 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) amendments to Arizona’s Electric Utility Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rule making has not been initiated and there has been no additional action on the draft to date. PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following: APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate; an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC; the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point); the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC. The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2014 and 2013 (dollars in millions): Year Ended December 31, 2014 Beginning balance Deferred fuel and purchased power costs - current period Amounts charged to customers Ending balance $ $ 2013 21 $ 27 (41) 7 $ 73 (21) (31) 21 The PSA rate for the PSA year beginning February 1, 2015 is $0.000887 per kWh, as compared to $0.001557 per kWh for the prior year. This new rate is comprised of a forward component of $0.001131 per kWh and a historical component of $(0.000244) per kWh. Any uncollected (overcollected) deferrals during the 2015 PSA FERC FORM NO. 1 (ED. 12-88) Page 123.10 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2016. Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2014. Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The LFCR adjustment has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques. APS filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million; representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012. APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014. The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014. APS filed its 2015 annual LFCR adjustment on January 15, 2015, requesting an LFCR adjustment of $38.5 million effective March 1, 2015. FERC FORM NO. 1 (ED. 12-88) Page 123.11 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Deregulation On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these wuold be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-serive regulatory model that could include elemetns of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. A series of workshops in this docket were held in 2014 and another is currently scheduled for February 26, 2015. Net Metering On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules. On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid. ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift. The ACC also required APS to file its next rate case in June 2015, the earliest date contemplated in the 2012 Settlement Agreement. In May 2014, the ACC began conducting a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering. On July 22, 2014, the ACC Commissioners voted to reopen the December 2013 net metering decision for the limited purpose of deciding whether to eliminate the requirement that APS file its next rate case in June 2015. The vote included a request that parties comment in the docket about their thoughts on removing the filing date requirement and on the process for the broader discussion regarding rate design. On August 12, 2014, the ACC Commissioners voted to lift the requirement that APS file its next general rate case by June 2015. On September 29, 2014, the staff of the ACC filed in a new docket a proposal for permitting a utility to request ACC approval of its proposed rate design outside of and before a general rate case. On October 20, 2014, APS and other interested stakeholders filed comments to this proposal. No further action has been taken in this docket. FERC FORM NO. 1 (ED. 12-88) Page 123.12 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Four Corners On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis. This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates. The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $77 million as of December 31, 2014 and is being amortized in rates over 10 years. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement” that, upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group. However, this alternative arrangement was not approved by FERC. In late March 2014, APS and SCE filed requests for rehearing with FERC. Both requests for rehearing were denied on August 14, 2014. Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control. As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement. If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter if it proceeds to arbitration. If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations. Cholla After considering the costs to comply with environmental regulations, on September 11, 2014, APS announced that it will close Cholla Unit 2 by April 2016 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering depreciation and a return on the net book value of the unit in base rates and plans to seek recovery of all of the unit’s retirement-related costs in its next retail rate case. If APS closes Cholla Unit 2, APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($128 million as of December 31, 2014), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all FERC FORM NO. 1 (ED. 12-88) Page 123.13 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted. Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in millions): Year Ended December 31, 2014 Pension and other postretirement benefits (a) Income taxes – AFUDC equity Deferred fuel and purchased power – mark-to-market (Note 15) Transmission vegetation management Coal reclamation Deferred compensation Deferred fuel and purchased power (b) (c) Tax expense of Medicare subsidy Prior flow through of tax benefits Income taxes – investment tax credit basis adjustment Pension and other postretirement benefits deferral Lost fixed cost recovery Retired power plant costs Four Corners cost deferral Deferred property taxes Other Total regulatory assets (d) $ $ 2013 485 $ 123 97 14 7 34 7 15 5 48 4 38 146 77 30 17 1,147 $ 314 109 34 23 26 34 21 17 8 41 13 25 21 37 11 27 761 (a) This asset represents the future recovery of pension and other postretirement benefits obligation through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. (b) See “Cost Recovery Mechanisms” discussion above. (c) Subject to a carrying charge. (d) There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.” FERC FORM NO. 1 (ED. 12-88) Page 123.14 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Year Ended December 31, 2014 Asset retirement obligations Renewable energy standard (a) Income taxes– change in rates Spent nuclear fuel Deferred gains on utility property Income taxes- deferred investment tax credit Excess deferred taxes Demand side management Other postretirement benefits Other Total regulatory liabilities (a) 5. $ $ 2013 296 $ 47 76 70 10 96 5 31 231 37 899 $ 266 48 78 42 12 82 8 27 — 17 580 See “Cost Recovery Mechanisms” discussion above. Income Taxes APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’s taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement. Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted tax rates. APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits ("ITCs") and the change in income tax rates. In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property, with such amortization applied as a credit to reduce current income tax expense in the statement of income. Included in the $167 million prepayments balance on the Comparative Balance Sheets as of December 31, 2013 was $136 million that represented an anticipated IRS refund related to the finalized examinations of tax years ended December 31, 2008 and 2009. Cash related to this refund was received in the first quarter of 2014. FERC FORM NO. 1 (ED. 12-88) Page 123.15 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The components of APS’s income tax expense are as follows (dollars in thousands): Year Ended December 31, 2014 Current: Federal State Total current Deferred: Federal State Total deferred Total income tax expense $ $ 39,756 15,598 55,354 166,426 16,620 183,046 238,400 2013 $ $ (1,878) 11,982 10,104 213,996 25,254 239,250 249,354 On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income. The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands): Year Ended December 31, 2014 Federal income tax expense at 35% statutory rate Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit Credits and favorable adjustments related to prior years resolved in current year Medicare Subsidy Part-D Allowance for equity funds used during construction (see Note 1) Investment tax credit amortization Other Income tax expense $ 230,503 2013 $ 21,148 $ — 830 (8,523) (4,928) (630) 238,400 $ 234,522 23,970 (3,231) 823 (6,997) (3,548) 3,815 249,354 On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four-year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2014, APS has recorded a regulatory liability of $74 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law. On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2014, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law. FERC FORM NO. 1 (ED. 12-88) Page 123.16 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The components of the net deferred income tax liability were as follows (dollars in thousands): December 31, 2014 DEFERRED TAX ASSETS Regulatory liabilities: Asset retirement obligation and removal costs Unamortized investment tax credits Other postretirement benefits Other Risk management activities Pension liabilities Other postretirement liabilities Renewable energy incentives Credit and loss carryforwards Other Total deferred tax assets DEFERRED TAX LIABILITIES Plant-related Risk management activities Other postretirement benefit assets Regulatory assets: Allowance for equity funds used during construction Deferred fuel and purchased power Deferred fuel and purchased power — mark-to-market Pension and other postretirement benefits Retired power plant costs (see Note 4) Other Other Total deferred tax liabilities Deferred income taxes — net $ $ 115,825 96,232 90,496 61,604 66,251 194,541 — 65,169 — 161,379 851,497 2013 $ 105,057 82,116 — 43,839 48,466 132,263 53,950 65,434 38,183 166,781 736,089 (2,877,990) (20,917) (58,495) (2,804,997) (19,737) — (48,286) (2,498) (38,187) (191,747) (57,255) (100,318) (5,484) (3,401,177) (2,549,680) $ (43,058) (8,282) (13,343) (129,250) (8,199) (86,234) (4,916) (3,118,016) (2,381,927) As of December 31, 2014, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits which first begin to expire in 2031. 6. Lines of Credit and Short-Term Borrowings APS maintains committed revolving credit facilities in order to enhance liquidity and provide credit support for its commercial paper programs. The table below presents the credit facilities and the amounts available and outstanding as of December 31, 2014 (dollars in millions): FERC FORM NO. 1 (ED. 12-88) Page 123.17 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Credit Facility Expiration APS Revolving Credit Facility APS Revolving Credit Facility Total (a) Amount Committed May 2019 April 2018 $ 500 500 1,000 Unused Amount (a) $ 500 353 853 Commitment Fees 0.125% 0.125% At December 31, 2014, APS had $147 million of outstanding commercial paper. Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $853 million. On May 9, 2014, APS refinanced its $500 million revolving credit facility that would have matured in November 2016, with a new $500 million facility that matures in May 2019. At December 31, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and a $500 million credit facility that matures in May 2019 (see above). APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2014, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $147 million at December 31, 2014. The table below presents the credit facilities and the amounts available and outstanding as of December 31, 2013 (dollars in millions): Credit Facility Expiration APS Revolving Credit Facility APS Revolving Credit Facility Total (a) Amount Committed November 2016 April 2018 $ 500 500 1,000 Unused Amount (a) $ 347 500 847 Commitment Fees 0.125% 0.125% At December 31, 2013, APS had $153 million of outstanding commercial paper. Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $847 million. On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility. The new revolving credit facility matures in April 2018. At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit facility that matures in November 2016. APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS can use these facilities to refinance indebtedness and for FERC FORM NO. 1 (ED. 12-88) Page 123.18 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $153 million at December 31, 2013. See “Financial Assurances” in Note 11 for a discussion of APS’s separate outstanding letters of credit. Debt Provisions Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017. 7. Long-Term Debt and Liquidity Matters All of APS’s debt is unsecured. The following table presents the components of long-term debt on the Comparative Balance Sheets outstanding at December 31, 2014 and 2013 (dollars in thousands): APS Pollution Control Bonds: Variable Fixed Total Pollution Control Bonds Senior unsecured notes Unamortized discount Unamortized premium Total Long-Term Debt (a) (b) Maturity Interest Dates (a) Rates 2029-2038 2024-2034 (b) 0.45%-5.75% 2015-2044 3.35%-8.75% December 31, $ $ 2014 2013 156,405 $ 249,300 405,705 2,875,000 (9,206) 4,866 3,276,365 $ 75,580 426,125 501,705 2,675,000 (8,732) 5,047 3,173,020 This schedule does not reflect the timing of redemptions that may occur prior to maturities. The weighted-average rate for the variable rate pollution control bonds was 0.03%-0.27% at December 31, 2014 and 0.03%-0.06% at December 31, 2013. FERC FORM NO. 1 (ED. 12-88) Page 123.19 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows principal payments due on APS’s total long-term debt (dollars in millions): Year APS 2015 2016 2017 2018 2019 Thereafter Total $ $ 370 357 32 32 500 1,989 3,280 Debt Fair Value Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions): As of December 31, 2014 Carrying Fair Value Amount Total $ 3,276 $ 3,700 As of December 31, 2013 Carrying Fair Value Amount $ 3,173 $ 3,413 Credit Facilities and Debt Issuances On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024. On January 15, 2014, both of these series of bonds were canceled and refinanced. On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044. The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used in 2013 to re-acquire the two series of tax-exempt indebtedness. On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E, due 2029 in connection with the mandatory tender provisions for this indebtedness. On May 14, 2014, APS remarketed all $36 million of the 2009 Series A Bonds. We expect to remarket or refinance all $64 million of the 2009 Series D Bonds and 2009 Series E Bonds within the next twelve months. FERC FORM NO. 1 (ED. 12-88) Page 123.20 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) On May 30, 2014, APS purchased all $38 million of the Navajo County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034, and on June 1, 2014, APS purchased a total of $64 million of the Navajo 2009 Series B Bonds and 2009 Series C Bonds, in each case, in connection with the mandatory tender provisions for this indebtedness. On September 23, 2014, APS remarketed all $38 million of the 2009 Series A Bonds. On October 1, 2014, APS remarketed all $32 million of the 2009 Series C Bonds. We expect to remarket or refinance all $32 million of the 2009 Series B Bonds within the next twelve months. On June 1, 2014, APS remarketed all $13 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034. On June 18, 2014, APS issued $250 million of 3.35% unsecured senior notes that mature on June 15, 2024. The net proceeds from the sale were used along with other funds to repay at maturity APS’s $300 million aggregate principal amount of 5.80% senior notes due June 30, 2014. On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures. See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit. Debt Provisions APS’s debt covenants related to its respective bank financing arrangements include maximum debt to capitalization ratios. APS complies with this covenant. For APS, this covenant requires that the ratio of debt to total capitalization not exceed 65%. At December 31, 2014, the ratio was approximately 45% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below. None of APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings. All of APS’s bank agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. APS does not have a material adverse change restriction for credit facility borrowings. An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2014, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.5 billion, and total capitalization was approximately $8.0 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.2 billion, assuming APS’s total capitalization FERC FORM NO. 1 (ED. 12-88) Page 123.21 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) remains the same. 8. Retirement Plans and Other Benefits Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. We calculate the benefits based on age, years of service and pay. Pinnacle West also sponsors an other postretirement benefit plan (Pinnacle West Capital Corporation Group Life and Medical Plan) for the employees of Pinnacle West and its subsidiaries. This plan provides medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement (HRA). The Company will provide a subsidy allowing post-65 retirees to purchase a Medicare supplement plan on a private exchange network. The remeasurement of the benefit obligation included updating the assumptions. The remeasurement reduced net periodic benefit costs in 2014 by $10 million ($5 million of which reduced expense), which was recognized during the fourth quarter of 2014. The September 30, 2014 remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income. As a result of this reduction, the other postretirement benefit obligation, and related regulatory asset, have been reduced to the extent that Pinnacle West will now reflect an asset for other postretirement benefits and a related regulatory liability with balances at December 31, 2014 of $152 million and $231 million, respectively. Because of the plan changes, the Company is currently in the process of seeking IRS and regulatory approval to move approximately $100 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 13 for further discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods. A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset or regulatory liability. In its 2009 retail rate case settlement, APS received approval to defer a portion of FERC FORM NO. 1 (ED. 12-88) Page 123.22 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) pension and other postretirement benefit cost increases incurred in 2011 and 2012. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over 3 years beginning in July 2012. We amortized approximately $8 million during 2014, $8 million during 2013, and $4 million during 2012. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands): Pension 2014 Service cost-benefits earned during the $ 53,080 period Interest cost on benefit obligation 129,194 Expected return on plan assets (158,998) Amortization of: Prior service cost (credit) 869 Net actuarial loss 10,963 Net periodic benefit cost $ 35,108 Portion of cost charged to expense $ 21,985 Other Benefits 2013 $ $ $ 2014 64,195 112,392 (146,333) 1,097 39,852 71,203 38,968 $ $ $ 2013 18,139 41,243 (46,400) (9,626) 1,175 4,531 6,000 $ $ $ 23,597 41,536 (45,717) (179) 11,310 30,547 18,469 The following table shows the plans’ changes in the benefit obligations and funded status for the years 2014 and 2013 (dollars in thousands): Pension Change in Benefit Obligation Benefit obligation at January 1 Service cost Interest cost Benefit payments Actuarial (gain) loss Plan amendments Benefit obligation at December 31 Change in Plan Assets Fair value of plan assets at January 1 Actual return on plan assets Employer contributions Benefit payments Fair value of plan assets at December 31 Funded Status at December 31 FERC FORM NO. 1 (ED. 12-88) $ $ Other Benefits 2014 2013 2,646,530 $ 53,080 129,194 (128,550) 378,394 — 3,078,648 2,850,846 64,195 112,392 (125,269) (255,634) — 2,646,530 2,264,121 292,992 175,000 (116,709) 2,615,404 (463,244) $ 2,079,181 150,546 140,500 (106,106) 2,264,121 (382,409) Page 123.23 2014 $ $ 2013 890,418 $ 18,139 41,243 (29,054) 150,188 (388,599) 682,335 990,418 23,597 41,536 (26,675) (138,458) — 890,418 748,339 105,223 770 (19,707) 834,625 152,290 $ 684,221 76,995 14,438 (27,315) 748,339 (142,079) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2014 and 2013 (dollars in thousands): Projected benefit obligation Accumulated benefit obligation Fair value of plan assets $ 2014 2013 3,078,648 $ 2,873,741 2,615,404 2,646,530 2,469,889 2,264,121 The following table shows the amounts recognized on the Comparative Balance Sheets as of December 31, 2014 and 2013 (dollars in thousands): Pension 2014 Noncurrent asset Current liability Noncurrent liability Net amount recognized $ $ Other Benefits 2013 — $ (9,508) (453,736) (463,244) $ — (10,860) (371,549) (382,409) 2014 $ $ 2013 152,290 — — 152,290 $ — — (142,079) (142,079) $ The following table shows the details related to accumulated other comprehensive loss as of December 31, 2014 and 2013 (dollars in thousands): Pension 2014 Net actuarial loss Prior service cost (credit) APS’s portion recorded as a regulatory (asset) liability Income tax expense (benefit) Accumulated other comprehensive loss $ $ 577,976 $ 1,203 (485,037) (36,890) 57,252 $ Other Benefits 2013 344,540 2,072 (265,107) (32,204) 49,301 2014 $ $ 2013 148,006 $ (379,269) 230,916 851 504 $ 57,816 (296) (49,298) (2,528) 5,694 The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2015 (dollars in thousands): Other Benefits Pension Net actuarial loss Prior service cost (credit) Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2014 $ 28,180 595 $ 5,651 (37,968) $ 28,775 $ (32,317) The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs: FERC FORM NO. 1 (ED. 12-88) Page 123.24 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Benefit Obligations As of December 31, 2014 Benefit Costs For the Years Ended December 31, 2013 2014 January September Discount rate – pension Discount rate – other benefits Rate of compensation increase Expected long-term return on plan assets - pension Expected long-term return on plan assets - other benefits Initial healthcare cost trend rate (pre-65 participants) Initial healthcare cost trend rate (post-65 participants) Ultimate healthcare cost trend rate Number of years to ultimate trend rate (pre-65 participants) Number of years to ultimate trend rate (post-65 participants) 2013 2012 October December 4.02% 4.14% 4.00% 4.88% 5.10% 4.00% 4.88% 5.10% 4.00% 4.88% 4.41% 4.00% 4.01% 4.20% 4.00% 4.42% 4.59% 4.00% N/A N/A 6.90% 6.90% 7.00% 7.75% N/A N/A 6.80% 4.25% 7.00% 7.75% 7.00% 7.50% 7.50% 7.50% 7.50% 7.50% 5.00% 5.00% 7.50% 5.00% 7.50% 5.00% 5.00% 5.00% 7.50% 5.00% 7.50% 5.00% 4 4 4 4 4 4 0 4 4 0 4 4 In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2015, we are assuming a 6.90% long-term rate of return for pension assets and 4.74% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance. In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final reports on its recommended mortality basis (“RP-2014 Mortality Tables Report” and "Mortality Improvement Scale MP-2014 Report"). At December 31, 2014, we updated our mortality assumptions using the recommended basis with modifications to better reflect our plan experience and additional data regarding mortality trends. The updated mortality assumptions resulted in a $67 million increase in Pinnacle West’s pension and other postretirement obligations, which was offset by the related regulatory asset, regulatory liability and accumulated other comprehensive income. In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs. A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects (dollars in millions): 1% Increase Effect on other postretirement benefits expense, after consideration of amounts capitalized or $ billed to electric plant participants Effect on service and interest cost components of net periodic other postretirement benefit costs Effect on the accumulated other postretirement benefit obligation FERC FORM NO. 1 (ED. 12-88) Page 123.25 10 $ 12 110 1% Decrease (4) (9) (88) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Plan Assets The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities. The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis. Long-term fixed income assets, also known as liability-hedging assets, are designed to offset changes in the benefit obligations due to changes in interest rates. Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury, other government agencies, and corporations. Long-term fixed income assets may also include interest rate swaps, U.S. Treasury futures and other instruments. Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments include investments in real estate, private equity and various other strategies. The plan may hold investments in return-generating assets by holding securities in partnerships and common and collective trusts. Based on the IPS, and given the pension plan’s funded status at year-end 2014, the long-term fixed income assets had a target allocation of 58% with a permissible range of 55% to 61% and the return-generating assets had a target allocation of 42% with a permissible range of 39% to 45%. The return-generating assets have additional target allocations, as a percent of total plan assets, of 22% equities in U.S. and other developed markets, 6% equities in emerging markets, and 14% in alternative investments. The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade. As of December 31, 2014, long-term fixed income assets represented 61% of total pension plan assets, and return-generating assets represented 39% of total pension plan assets. As of December 31, 2014, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. Some of these asset allocation target mixes vary with the plan’s funded status. As of December 31, 2014, investment in fixed income assets represented 43% of the other postretirement benefit plan total assets, and non-fixed income assets represented 57% of the other postretirement benefit plan’s assets. Fixed income assets are primarily invested in corporate bonds of investment-grade U.S. issuers, and U.S. Treasuries. Non-fixed income assets are primarily invested in large cap U.S. equities in diverse industries, and international equities in both emerging and developed markets. See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of partnerships and common and collective trusts. Equity FERC FORM NO. 1 (ED. 12-88) Page 123.26 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2. The common and collective trusts, which are similar to mutual funds, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index). Common and collective trusts are valued using the concept of net asset value (“NAV”), which is a value derived from the quoted active market prices of the underlying securities. The plans’ common and collective real estate trust is valued using NAV, which is derived from the appraised values of the trust’s underlying real estate assets. As of December 31, 2014, the plans were able to transact in the common and collective trusts at NAV and accordingly classify these investments as Level 2. Because the trust’s shares are offered to a limited group of investors, they are not considered to be traded in an active market. Investments in partnerships are also valued using the concept of NAV, which is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Partnerships are classified as Level 2 if the plan is able to transact in the partnership at the NAV. At December 31, 2014, certain partnerships have been classified as Level 3 due to restrictions that limit the plan's ability to transact in these partnerships at the NAV. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerhips; as of December 31, 2014, $30 million of these commitments have been funded. The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. FERC FORM NO. 1 (ED. 12-88) Page 123.27 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2014, by asset category, are as follows (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Pension Plan: Assets: Cash and cash equivalents Fixed Income Securities: Corporate U.S. Treasury Other (a) Equities: U.S. Companies International Companies Common and collective trusts: U.S. Equities International Equities Real estate Partnerships Short-term investments and other Total Pension Plan Other Benefits: Assets: Cash and cash equivalents Fixed Income Securities: Corporate U.S. Treasury Other (a) Equities: U.S. Companies International Companies Common and collective trusts: U.S. Equities International Equities Real Estate Short-term investments and other Total Other Benefits (a) (b) $ 387 Significant Other Observable Inputs (Level 2) $ — Significant Unobservable Inputs (Level 3) $ — Other (b) $ — $ 387 — 291,817 — 1,162,096 — 113,265 — — — — — — 1,162,096 291,817 113,265 246,387 18,069 — — — — — — 246,387 18,069 $ — — — — — 556,660 127,336 317,167 129,715 138,337 26,016 $ 2,013,932 $ — — — 27,929 — 27,929 $ — — — — 16,883 16,883 127,336 317,167 129,715 166,266 42,899 $ 2,615,404 $ 318 $ $ — $ — $ — $ 318 — 130,967 — 187,961 — 35,291 — — — — — — 187,961 130,967 35,291 265,106 17,813 — — — — — — 265,106 17,813 — — — — 414,204 88,258 85,746 11,657 7,408 416,321 — — — — — — — — 4,100 4,100 88,258 85,746 11,657 11,508 834,625 $ $ $ This category consists primarily of debt securities issued by municipalities. Represents plan receivables and payables. FERC FORM NO. 1 (ED. 12-88) Balance at December 31, 2014 Page 123.28 $ 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2013, by asset category, are as follows (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Pension Plan: Assets: Cash and cash equivalents Fixed Income Securities: Corporate U.S. Treasury Other (a) Equities: U.S. Companies International Companies Common and collective trusts: U.S. Equities International Equities Fixed Income Real estate Partnerships Short-term investments and other Total Pension Plan Other Benefits: Assets: Cash and cash equivalents Fixed Income Securities: Corporate U.S. Treasury Other (a) Equities: U.S. Companies International Companies Common and collective trusts: U.S. Equities International Equities Real Estate Short-term investments and other Total Other Benefits (a) (b) $ $ $ $ 504 Significant Other Observable Inputs (Level 2) $ — Significant Unobservable Inputs (Level 3) $ — Other (b) $ — $ 504 — 231,590 — 898,621 — 84,011 — — — — — — 898,621 231,590 84,011 239,036 19,429 — — — — — — 239,036 19,429 — — — — — — 490,559 116,150 367,551 137,520 119,739 — 41,060 1,764,652 — — — — 8,660 — 8,660 — — — — — 250 250 116,150 367,551 137,520 119,739 8,660 41,310 2,264,121 — 98,704 — $ $ 153,888 — 27,936 $ $ — — — $ $ — — — $ $ 153,888 98,704 27,936 252,181 20,892 — — — — — — 252,181 20,892 — — — — 371,777 80,751 92,382 10,761 8,414 374,132 — — — — — — — — 2,430 2,430 80,751 92,382 10,761 10,844 748,339 $ $ $ This category consists primarily of debt securities issued by municipalities. Represents plan receivables and payables. FERC FORM NO. 1 (ED. 12-88) Balance at December 31, 2013 Page 123.29 $ 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2014 and 2013 (dollars in thousands): Pension Partnerships 2014 Beginning balance at January 1 Actual return on assets still held at December 31 Purchases Sales Transfers in and/or out of Level 3 Ending balance at December 31 $ $ 2013 8,660 927 19,984 (1,642) — 27,929 $ $ 2,419 (498) 7,377 (638) — 8,660 Contributions Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. Pinnacle West made contributions to the pension plan totaling $175 million in 2014, and $141 million in 2013. The minimum contributions for the pension plan are zero for the next three years. Pinnacle West expects to make voluntary contributions totaling up to $300 million for the next three years (up to $100 million each year in 2015, 2016, and 2017). With regard to contributions to the other postretirement benefit plans, Pinnacle West made a contribution of $1 million in 2014, and $14 million in 2013. Pinnacle West expects to make contributions of approximately $1 million in each of the next three years to the other postretirement benefit plans. APS funds its share of the contributions. APS’s share of the pension plan contribution was $175 million in 2014, and $140 million in 2013. APS’s share of the contributions to the other postretirement benefit plan was $1 million in 2014, and $14 million in 2013. Estimated Future Benefit Payments Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands): Year Pension 2015 2016 2017 2018 2019 Years 2020-2024 $ Other Benefits 139,013 $ 155,968 160,080 167,600 177,470 983,557 25,134 27,311 29,253 31,258 33,190 184,772 Electric plant participants contribute to the above amounts in accordance with their respective participation agreements. FERC FORM NO. 1 (ED. 12-88) Page 123.30 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Employee Savings Plan Benefits Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2014, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $9 million for 2014, and $9 million for 2013. 9. Leases We lease a portion of the Palo Verde power plant, certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. APS’s lease expense was $60 million in 2014, and $61 million in 2013 Estimated future minimum lease payments for APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in millions): Year APS 2015 2016 2017 2018 2019 Thereafter Total future lease commitments $ $ 64 29 28 27 26 314 488 In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. 10. Jointly-Owned Facilities APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs, as well as for providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Comparative Balance Sheets at December 31, 2014 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.31 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Percent Owned Generating facilities: Palo Verde Units 1 and 3 Palo Verde Unit 2 (a) Palo Verde Common Palo Verde Sale Leaseback Four Corners Generating Station Navajo Generating Station Units 1, 2 and 3 Cholla common facilities (c) Transmission facilities: ANPP 500kV System Navajo Southern System Palo Verde — Yuma 500kV System Four Corners Switchyards Phoenix — Mead System Palo Verde — Estrella 500kV System Morgan — Pinnacle Peak System Round Valley System Palo Verde — Morgan System Hassayampa - North Gila System (a) (b) (c) 11. 29.1% 16.8% 28.0% Plant in Service (b) (a) 63.0% 14.0% 63.3% (b) 33.6% 22.5% 18.2% 47.5% 17.1% 50.0% 64.4% 50.0% 90.0% 80.0% (b) (b) (b) (b) (b) (b) (b) (b) (b) (b) Accumulated Depreciation $ 1,734,918 $ 1,051,670 $ 556,472 349,960 612,190 224,208 351,050 229,795 811,648 578,772 272,208 159,198 155,856 49,954 106,369 59,994 12,925 33,034 39,777 89,572 130,840 497 — 8,902 35,035 18,119 4,943 10,035 12,843 16,491 8,970 276 — 3,634 Construction Work in Progress 16,955 13,710 68,896 — 33,150 2,716 866 3,731 1,113 12 386 105 736 1,690 1 69,377 142,645 See Note 16. Weighted-average of interests. PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned. Commitments and Contingencies Palo Verde Nuclear Generating Station Spent Nuclear Fuel and Waste Disposal On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the DOE in the United States Court of Federal Claims. The lawsuit seeks to recover damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the NWPA. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on current income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016. FERC FORM NO. 1 (ED. 12-88) Page 123.32 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Nuclear Insurance Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.6 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $13.2 billion of liability coverage is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum retrospective premium assessment per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum potential retrospective premium assessment per incident for all three units is approximately $111 million, with a maximum annual retrospective premium assessment of approximately $16.5 million. The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of replacement generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective premium assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $20 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $53 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions. Fuel and Purchased Power Commitments and Purchase Obligations APS is party to purchase obligations and various fuel and purchased power contracts with terms expiring between 2015 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $723 million in 2015; $747 million in 2016; $630 million in 2017; $610 million in 2018; $583 million in 2019; and $8.2 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions. The current coal contracts with take-or-pay provisions have terms expiring through 2031. The following table summarizes our estimated coal take-or-pay commitments (dollars in millions): Years Ended December 31, 2015 Coal take-or-pay commitments (a) FERC FORM NO. 1 (ED. 12-88) $ 2016 151 $ 2017 171 $ Page 123.33 2018 195 $ 2019 190 $ Thereafter 194 $ 2,469 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) Total take-or-pay commitments are approximately $3.4 billion. The total net present value of these commitments is approximately $2.2 billion. APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual payments under the coal contracts which include take-or-pay provisions for each of the last two years (dollars in millions): Year Ended December 31, 2014 Total payments $ 2013 237 $ 188 Renewable Energy Credits APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $46 million in 2015; $42 million in 2016; $42 million in 2017; $42 million in 2018; $42 million in 2019; and $448 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Also, these amounts do not include purchases of renewable energy credits that are associated with purchased power contracts. Coal Mine Reclamation Obligations APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $198 million at December 31, 2014 and $207 million at December 31, 2013. Under our current coal supply agreements, we expect to make payments to certain coal providers for the final mine reclamation as follows: $1 million in 2015; $15 million in 2016; $17 million in 2017; $18 million in 2018; $19 million in 2019; and $281 million thereafter. Any amendments to current coal supply agreements may change the timing of the reimbursement. Superfund-Related Matters Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, OU3 in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS has agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated. FERC FORM NO. 1 (ED. 12-88) Page 123.34 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) On August 6, 2013, RID filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. We are unable to predict the outcome of this matter; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Southwest Power Outage Regulatory. On September 8, 2011 at approximately 3:30 PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service. Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected. Service to all affected APS customers was restored by 9:15 PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25 AM on September 9. FERC and NERC conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) with their analysis and conclusions as to the causes of the events. The report included recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination. The Joint Report did not address potential reliability violations or an assessment of responsibility of the parties involved. On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS. FERC Staff alleged that each of the named entities violated varying numbers of NERC Reliability Standards. APS was alleged to have violated seven Reliability Standard Requirements. The allegations of violations were preliminary determinations by FERC Staff and did not constitute findings by FERC itself that any violations had occurred. On July 7, 2014, FERC approved a Stipulation and Consent Agreement among FERC’s Office of Enforcement, NERC and APS which resolves all civil and administrative disputes within the jurisdiction of FERC concerning the September 8 event, including FERC’s and NERC’s investigations. In the settlement, APS neither admitted nor denied alleged violations of four Reliability Standard Requirements. APS agreed to pay a civil penalty of $3.25 million, of which $2 million is to be paid in equal parts to the Department of the Treasury and NERC and $1.25 million will be credited as a partial civil penalty offset in exchange for APS completing certain reliability enhancements. Litigation. On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS as a defendant and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS filed a motion to dismiss, which the court granted on FERC FORM NO. 1 (ED. 12-88) Page 123.35 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) December 9, 2013. On January 13, 2014, the plaintiffs appealed the lower court’s decision. The appeal is now fully briefed and pending before the Ninth Circuit Court of Appeals. We are unable to predict the outcome of this matter. Clean Air Act Citizen Lawsuit On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss. We are unable to predict the outcome of this matter. Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS. Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners, Cholla and the Navajo Plant. EPA and ADEQ will require these plants to install pollution control equipment that constitutes the BART to lessen the impacts of emissions on visibility surrounding the plants. Based on EPA’s final standards, APS estimates that its 63% share of the cost of these controls for Four Corners Units 4 and 5 would be at least $350 million. In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5, which would increase our share of the cost of these controls by approximately $40 million. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP proposal, could be up to approximately $200 million. In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. We cannot predict the outcome of this review process. As described under "Regional Haze Rules - Cholla" below, APS filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, would require installation of SCR controls with a cost to APS of approximately $200 million. However, in September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain regulatory approvals, APS would permanently close Cholla Unit 2 by April 2016 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, FERC FORM NO. 1 (ED. 12-88) Page 123.36 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. Because APS’s proposal involves state and federal rule-making processes, APS is unable to predict when or whether it may ultimately be approved. Mercury and Air Toxic Standards. In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $130 million for Cholla, which would be avoided if EPA approves APS's compromise proposal discussed above. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules. Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Because the Subtitle D rule is self-implementing, the CCR standards apply directly to the regulated facility, and facilities are directly responsible for ensuring that their operations comply with the rule’s requirements. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. At this time, SRP, the operating agent for the Navajo Plant, is analyzing the operations that would be covered by the rule and any resulting compliance costs. Other future environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, GHG emissions (such as the EPA’s proposed “Clean Power Plan” rule issued in accordance with President Obama’s Climate Action Plan), and other rules or matters involving the Clean Air Act, Clean Water Act, ESA, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery. Regional Haze Rules — Cholla FERC FORM NO. 1 (ED. 12-88) Page 123.37 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014; the court scheduled oral argument for March 9, 2015. New Mexico Tax Matter On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”). APS’s share of the Assessment is approximately $12 million. For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. We cannot predict the timing or outcome of this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Financial Assurances APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2014, approximately $109 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit will expire in 2015, 2016, and 2017. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 16 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire on December 31, 2015, and totaled approximately $23 million at December 31, 2014. Additionally, APS has issued letters of credit to support collateral obligations under a natural gas tolling contract entered into with a third party. At December 31, 2014, that letter of credit totaled $5 million and will expire in 2015. We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely. 12. Asset Retirement Obligations APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the FERC FORM NO. 1 (ED. 12-88) Page 123.38 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites. In 2014, an update to the 2013 decommissioning study was completed for Palo Verde nuclear generation facility to incorporate additional spent fuel related charges resulting in an increase to the ARO in the amount of $20 million. Also in 2014, an updated Four Corners Units 1-3 coal-fired power plant decommissioning study was finalized, which resulted in an increase to the ARO of $24 million. In addition, Four Corners spent $30 million in actual decommissioning costs. Finally, in 2014 APS also recognized an ARO related to a new solar facility on leased property that requires the land to be returned to its original condition upon decommissioning of the plant, which resulted in an increase to the ARO of $6 million. In 2013, a decommissioning study with updated cash flow estimates was completed for Palo Verde, which resulted in a decrease of $52 million. Also in 2013, APS finalized the transaction to acquire SCE’s interest in Four Corners. As part of that transaction, APS assumed SCE’s asset retirement obligation resulting in an increase to the ARO of $34 million. In addition, on December 30, 2013, APS also retired Four Corners Units 1-3 and began decommissioning activities. Finally, Four Corners spent $12 million in actual decommissioning costs. An update was made to the timing of the Units 1-3 decommissioning cash flows to coincide with the expected decommissioning activities. This update resulted in a decrease to the ARO of $4 million. The following schedule shows the change in our asset retirement obligations for 2014 and 2013 (dollars in millions): 2014 Asset retirement obligations at the beginning of year Changes attributable to: Accretion expense Settlements Assumed SCE’s obligation Estimated cash flow revisions Newly incurred obligation Asset retirement obligations at the end of year 2013 $ 347 $ $ 24 (30) — 44 6 391 $ 357 24 (12) 34 (56) — 347 In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 4. 13. Fair Value Measurements We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are: FERC FORM NO. 1 (ED. 12-88) Page 123.39 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes exchange traded equities, exchange traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities. Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities. This category also includes investments that are redeemable and valued based on NAV, such as common and collective trusts and commingled funds. Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable. Recurring Fair Value Measurements We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 8 for the fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets. Risk Management Activities — Derivative Instruments Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect FERC FORM NO. 1 (ED. 12-88) Page 123.40 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk. Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points. Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs. Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization. Investments Held in our Nuclear Decommissioning Trust The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued based on the concept of NAV, which is a value primarily derived from the quoted active market prices of the underlying equity securities. We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2. The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities. We may transact in this commingled fund on a daily basis at the NAV. Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are FERC FORM NO. 1 (ED. 12-88) Page 123.41 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities. We price securities using information provided by our trustee for our nuclear decommissioning trust assets. Our trustee uses pricing services that utilize the valuation methodologies described to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. See Note 17 for additional discussion about our nuclear decommissioning trust. Fair Value Tables The following table presents the fair value at December 31, 2014 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions): Quoted Prices in Active Markets for Identical Assets (Level 1) Assets Risk management activities — derivative instruments: Commodity Contracts Nuclear decommissioning trust: U.S. commingled equity funds Fixed income securities: U.S. Treasury Cash and cash equivalent funds Corporate debt Mortgage-backed securities Municipality bonds Other Subtotal nuclear decommissioning trust Total Liabilities Risk management activities — derivative instruments: Commodity contracts FERC FORM NO. 1 (ED. 12-88) $ — Significant Other Observable Inputs (Level 2) $ 21 Significant Unobservable Inputs (a) (Level 3) $ 33 Balance at December 31, 2014 Other $ (1) $ 53 — 310 — — 310 $ 119 — — — — — 119 119 $ — 11 109 89 69 14 602 623 — — — — — — — 33 — (7) — — — — (7) (8) $ 119 4 109 89 69 14 714 767 $ — $ (95) $ Page 123.42 $ $ (74) $ — $ (169) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) Primarily consists of heat rate options and other long-dated electricity contracts. The following table presents the fair value at December 31, 2013 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions): Quoted Prices in Active Markets for Identical Assets (Level 1) Assets Risk management activities — derivative instruments: Commodity Contracts $ Nuclear decommissioning trust: U.S. commingled equity funds Fixed income securities: U.S. Treasury Cash and cash equivalent funds Corporate debt Mortgage-backed securities Municipality bonds Other Subtotal nuclear decommissioning trust Total $ Liabilities Risk management activities — derivative instruments: Commodity contracts $ (a) — Significant Other Observable Inputs (Level 2) $ Significant Unobservable Inputs (a) (Level 3) 9 $ 41 Balance at December 31, 2013 Other $ — $ 50 — 272 — — 272 107 — — — — — 107 107 $ — 11 88 85 71 11 538 547 — — — — — — — 41 — (3) — — — — (3) (3) $ 107 8 88 85 71 11 642 692 — $ (33) $ — $ (123) $ $ (90) $ Primarily consists of heat rate options and other long-dated electricity contracts. Fair Value Measurements Classified as Level 3 The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4). Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease. FERC FORM NO. 1 (ED. 12-88) Page 123.43 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The significant unobservable inputs for these instruments include electricity prices, gas prices and volatilities. If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease. If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase. The commodity prices and volatilities do not always move in corresponding directions. The options’ fair values are impacted by the net changes of these various inputs. Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements. The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2014 and December 31, 2013: December 31, 2014 Fair Value (millions) Commodity Contracts Electricity: Forward Contracts (a) Assets $ Option Contracts (b) Valuation Technique Significant Unobservable Input 56 Discounted cash flows 15 Option model Electricity forward price (per MWh) Electricity forward price (per MWh) Natural gas forward price (per MMbtu) Electricity price volatilities Natural gas price volatilities Liabilities 30 $ — WeightedAverage Range $19.51 - $56.72 $ 35.27 $32.14 - $66.09 $ 45.83 $3.18 - $3.29 $ 3.25 23% - 63% 41% 23% - 41% 31% Natural Gas: Discounted cash flows Forward Contracts (a) Total (a) (b) $ 3 33 $ 3 74 Natural gas forward price (per MMbtu) $2.98 - $4.13 $ 3.45 Includes swaps and physical and financial contracts. Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities. FERC FORM NO. 1 (ED. 12-88) Page 123.44 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) December 31, 2013 Fair Value (millions) Commodity Contracts Electricity: Forward Contracts (a) Assets $ Option Contracts (b) Valuation Technique Significant Unobservable Input 66 Discounted cash flows 19 Option model Electricity forward price (per MWh) Electricity forward price (per MWh) Natural gas forward price (per MMbtu) Electricity price volatilities Natural gas price volatilities Liabilities 40 $ — WeightedAverage Range $24.89 - $65.04 $ 41.09 $39.91 - $85.41 $ 58.70 $3.57 - $3.80 $ 3.71 35% - 94% 59% 22% - 36% 27% Natural Gas: Discounted cash flows Forward Contracts (a) Total (a) (b) $ 1 41 $ 5 90 Natural gas forward price (per MMbtu) $3.47 - $4.31 $ 3.87 Includes swaps and physical and financial contracts. Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities. The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2014 and 2013 (dollars in millions): Year Ended December 31, Commodity Contracts 2014 Net derivative balance at beginning of period Total net gains (losses) realized/unrealized: Included in earnings Included in OCI Deferred as a regulatory asset or liability Settlements Transfers into Level 3 from Level 2 Transfers from Level 3 into Level 2 Net derivative balance at end of period Net unrealized gains included in earnings related to instruments still held at end of period FERC FORM NO. 1 (ED. 12-88) Page 123.45 2013 $ (49) $ (48) $ $ — — — 12 (2) (2) (41) $ — $ — — (10) 10 — (1) (49) — 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Amounts included in earnings are recorded in either operating revenues or fuel and purchased power depending on the nature of the underlying contract. Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods. Financial Instruments Not Carried at Fair Value The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our short-term borrowings are classified within Level 2 of the fair value hierarchy. See Note 7 for our long-term debt fair values. 14. Stock-Based Compensation Pinnacle West grants long-term incentive awards under the 2012 Long-Term Incentive Plan (“2012 Plan”) in the form of Stock Grants, Restricted Stock Units, Stock Units and Performance Shares and may grant restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan, effective May 16, 2012, provides 4,595,500 common shares to be available for grant to eligible employees and members of the Board of Directors. Awards made since 2012 were issued under the 2012 Plan, and prior awards from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”). Restricted Stock Unit Awards, Stock Unit Awards and Stock Grants Stock grants issued to non-officer members of the Board of Directors in 2014 and, 2013 provided the members of the Board of Directors the option to elect to receive a stock grant, or to defer receipt until a later date and receive restricted stock units in 2012 and stock units in 2013 and 2014 in lieu of the stock grant. The members of the Board of Directors who elect to defer may elect to receive payment in either stock, or 50% in cash and 50% in stock. The members of the Board of Directors may elect to receive payments either as of the last business day of the month following the month in which they separate from service on the Board of Directors, or as of a specified date, which must be after December 31 of the year in which the grant was received. The deferred restricted stock units and stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, or 50% in cash and 50% in stock. Restricted stock units have been granted to officers and key employees in each year since 2008. From 2008 through 2009, officers and key employees elected to receive payment in either cash or in fully transferable shares of stock, in exchange for each restricted stock unit on pre-established valuation dates. From 2010 through 2014, officers and key employees elected to receive payment in either stock, or 50% in cash and 50% in stock. FERC FORM NO. 1 (ED. 12-88) Page 123.46 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Restricted stock unit awards vest and settle over a 4-year period. In addition, officers and key employees accrue dividend rights on vested restricted stock units, equal to the amount of dividends that they would have received had they directly owned stock, equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest for the 2008 and 2009 awards were paid in cash. The dividends and interest for the 2010 through 2014 awards are paid in the same form as the restricted stock unit payment election. Restricted stock unit awards are accounted for as a liability award, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately. In December 2012, the Company granted a retention award of 50,617 restricted stock units to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West. The award will vest and will be paid in shares of common stock on December 31, 2016, provided that he remains employed with the Company until the vesting date. The award will accrue notional dividends equal to the amount of dividends that would have been received if the Chairman of the Board, President and Chief Executive Officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date. The award can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met. A grant of restricted stock unit awards was made to officers of the company on February 15, 2011, payable solely in shares of common stock upon the officer’s retirement or other separation of employment. This award vested 50% on February 15, 2013 and 25% on February 15, 2014. The remaining award will vest 25% on February 15, 2015, provided that the officer remains employed on such date. The officers will also accrue notional dividends equal to the amount of dividends that they would have received if they had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date. Each additional restricted stock unit will proportionally vest on the same remaining vesting schedule that applies to the original restricted stock unit. The following table is a summary of granted restricted stock units, stock units and stock grants and the weighted-average fair value for the two years ended 2014, and 2013: 2014 Units granted Grant date fair value (a) (a) $ 130,273 54.91 $ 2013 129,620 55.21 Weighted-average grant date fair value. The following table is a summary of the status of restricted stock units, stock units and stock grants, as of December 31, 2014 and changes during the year. This table represents only the stock portion of restricted stock units and stock units, per the election on payment discussed in the paragraph above: FERC FORM NO. 1 (ED. 12-88) Page 123.47 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Nonvested shares Weighted-Average Grant Date Fair Value Shares Nonvested at January 1, 2014 Granted Vested Forfeited Nonvested at December 31, 2014 397,976 $ 130,273 (161,283) (13,067) 353,899 47.74 54.91 45.55 51.53 51.23 The amount of cash required to settle the payments on restricted stock units is (dollars in millions): Year 2014 2009 Grant 2010 Grant 2011 Grant 2012 Grant 2013 Grant $ 2013 — $ 2.3 2.4 2.1 2.1 3.0 2.3 2.5 2.2 — Performance Share Awards Performance share awards have been granted to officers and key employees under the 2012 Plan since 2012 and under the 2007 Plan from 2009 to 2011. Performance share awards contain two performance element criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met. The 2014 and 2013performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s total shareholder return at the end of the three-year performance period, as compared with the total shareholder return of all relevant companies in a specified utility index and the other 50% is based upon six non-financial separate performance metrics. The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that they would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. Performance share awards are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately. Management also evaluates the probability of meeting the performance criteria at each balance sheet date. If performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed. The following table is a summary of the performance shares granted and the weighted-average fair value for the two years ended 2014 and 2013: FERC FORM NO. 1 (ED. 12-88) Page 123.48 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 2014 Units granted (a) Grant date fair value (b) (a) (b) $ 166,244 54.86 $ 2013 176,332 55.45 Reflects the target payout level. Weighted-average grant date fair value. The following table is a summary of the status of performance shares as of December 31, 2014 and changes during the year: Nonvested shares (a) Shares Nonvested at January 1, 2014 Granted Increase in performance factor Vested Forfeited Nonvested at December 31, 2014 (a) Weighted-Average Grant Date Fair Value 344,396 $ 166,244 86,558 (258,224) (14,744) 324,230 51.13 54.86 47.40 47.40 53.30 54.92 Nonvested shares are reflected at target payout level. The increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests. Stock Options The Company has not granted stock options since 2004 and has no stock options outstanding. As of December 31, 2014, there was $15 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested during 2014, and 2013 was $20 million and $20 million, respectively. The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $33 million in 2014 and $25 million in 2013. The compensation cost that Pinnacle West has capitalized is immaterial for all years. Pinnacle West’s total income tax benefit recognized in the Comparative Statements of Income for share-based compensation arrangements was $13 million in 2014 and $10 million in 2013. APS’s share of compensation cost that has been charged against income was $33 million in 2014 and $25 million in 2013. Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans, and it does not expect to repurchase any shares except to satisfy tax withholding obligations upon the vesting of restricted stock units and performance shares. FERC FORM NO. 1 (ED. 12-88) Page 123.49 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 15. Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Comparative Statements of Income, but does not impact our financial condition, net income or cash flows. On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow hedges. This discontinuation is due to changes in PSA recovery (see Note 4), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts. For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through OCI, but are deferred through the PSA. The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur. When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA. Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery. Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. See Note 13 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below. Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts. For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on FERC FORM NO. 1 (ED. 12-88) Page 123.50 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals. As of December 31, 2014, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power Gas (a) 3,915 136 GWh Bcf (a) “Bcf” is Billion Cubic Feet. Gains and Losses from Derivative Instruments The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2014 and 2013 (dollars in thousands): Year Ended December 31, Financial Statement Commodity Contracts Location Loss Recognized in OCI on Derivative Instruments (Effective Portion) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) (a) (b) OCI — derivative instruments Fuel and purchased power (b) 2014 $ (372) $ (21,415) 2013 (353) (44,219) During the years ended December 31, 2014 and 2013 we had zero and zero million of losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. Amounts are before the effect of PSA deferrals. During the next twelve months, we estimate that a net loss of $6 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings. FERC FORM NO. 1 (ED. 12-88) Page 123.51 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2014 and 2013 (dollars in thousands): Year Ended December 31, Financial Statement Commodity Contracts Net Gain Recognized in Income Net Loss Recognized in Income Location Operating revenues Fuel and purchased power (a) Total (a) 2014 2013 $ 324 $ $ (66,367) (66,043) $ 289 (10,449) (10,160) Amounts are before the effect of PSA deferrals. Derivative Instruments in the Comparative Balance Sheets Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are reported gross on the Comparative Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are also reported gross on the Comparative Balance Sheets. We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below. The significant majority of our derivative instruments are not currently designated as hedging instruments. The Comparative Balance Sheets as of December 31, 2014 and December 31, 2013, include gross liabilities of $4 million and $5 million, respectively, of derivative instruments designated as hedging instruments. The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2014 and 2013. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Comparative Balance Sheets. FERC FORM NO. 1 (ED. 12-88) Page 123.52 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) As of December 31, 2014: (dollars in thousands) Gross Recognized Derivatives (a) Current Assets Investments and Other Assets Total Assets $ Current Liabilities Deferred Credits and Other Total Liabilities Total (86,062) (82,990) (169,052) $ (115,680) (a) (b) 28,562 24,810 53,372 $ (15,127) (7,190) (22,317) $ 15,127 7,190 22,317 — $ $ — — — 18,702 25,198 43,900 43,900 Net Derivatives After Impacts of Offsetting $ $ 13,435 17,620 31,055 (52,233) (50,602) (102,835) (71,780) All of our gross recognized derivative instruments were subject to master netting arrangements. We had total cash collateral and margin provided to counterparties of $44,250; this amount is reflected in miscellaneous current and accrued assets. We had total cash collateral received from counterparties of $7,443; this amount is reflected in miscellaneous current and accrued liabilities. Certain cash collateral is not eligible for offsetting as it does not related to recognized derivatives. As of December 31, 2013: (dollars in thousands) Gross Recognized Derivatives (a) Current Assets Investments and Other Assets Total Assets $ Current Liabilities Deferred Credits and Other Total Liabilities Total (50,540) (72,123) (122,663) $ (72,712) (a) (b) Eligible for Offsetting Derivatives Cash Collateral (b) 24,587 25,364 49,951 Eligible for Offsetting Derivatives Cash Collateral (b) $ $ (7,425) (1,549) (8,974) 7,426 1,548 8,974 — $ $ — — — 18,740 260 19,000 19,000 Net Derivatives After Impacts of Offsetting $ $ 17,161 23,816 40,977 (24,374) (70,315) (94,689) (53,712) All of our gross recognized derivative instruments were subject to master netting arrangements. We had total cash collateral and margin provided to counterparties of $19,007; this amount is reflected in miscellaneous current and accrued assets. We had total cash collateral received from counterparties of $7,518; this amount is reflected in miscellaneous current and accrued liabilities. Certain cash collateral is not eligible for offsetting as it does not related to recognized derivatives. Credit Risk and Credit Related Contingent Features FERC FORM NO. 1 (ED. 12-88) Page 123.53 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including one counterparty for which our exposure represents approximately 90% of APS’s $31 million of risk management assets as of December 31, 2014. This exposure relates to a long-term traditional wholesale contract with a counterparty that has a high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2014 (dollars in millions): December 31, 2014 Aggregate Fair Value of Derivative Instruments in a Liability Position Cash Collateral Posted Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a) (a) $ 169 44 80 This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above. We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $175 million if our debt credit ratings were to fall below investment grade. 16. Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will pay approximately $49 million in 2015 FERC FORM NO. 1 (ED. 12-88) Page 123.54 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) related to these leases. The lease agreements include fixed rate renewal periods. On July 7, 2014, APS notified the lessor trust entities of APS’s intent to exercise the fixed rate lease renewal options. The length of the renewal options will result in APS retaining the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make lease payments of approximately $23 million annually for the period 2016 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors. For regulatory reporting purposes, APS accounts for the lease renewal as a capital lease on the balance sheet and an operating lease for income statement and cash flow statement purposes. APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Palo Verde Unit 2 interests which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2014, APS would have been required to pay the noncontrolling equity participants approximately $123 million and assume $13 million of debt. 17. Nuclear Decommissioning Trusts To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Comparative Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2014 and December 31, 2013 (dollars in millions): Total Unrealized Gains Fair Value December 31, 2014 Equity securities Fixed income securities Net payables (a) Total FERC FORM NO. 1 (ED. 12-88) $ $ Page 123.55 310 411 (7) 714 $ $ 159 17 — 176 Total Unrealized Losses $ $ — (1) — (1) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Total Unrealized Gains Fair Value December 31, 2013 Equity securities Fixed income securities Net payables (a) Total (a) $ 272 373 (3) 642 $ $ 129 11 — 140 $ Total Unrealized Losses $ — (6) — (6) $ Net payables relate to pending purchases and sales of securities. The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions): Year Ended December 31, 2014 Realized gains Realized losses Proceeds from the sale of securities (a) (a) $ 2013 5 $ (5) 356 6 (7) 446 Proceeds are reinvested in the trust. The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2014 is as follows (dollars in millions): Fair Value Less than one year 1 year – 5 years 5 years – 10 years Greater than 10 years Total 18. $ $ 14 116 122 159 411 Changes in Accumulated Other Comprehensive Loss The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2014 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.56 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Derivative Instruments Beginning balance OCI (loss) before reclassifications Amounts reclassified from accumulated other comprehensive loss Net current period OCI (loss) Ending balance (a) (b) $ Year Ended December 31, 2014 Pension and Other Postretirement Benefits (23,059) (809) $ 13,483 (a) 12,674 (10,385) $ $ (30,313) (10,415) Total $ (53,372) (11,224) 2,780 (b) (7,635) (37,948) $ 16,263 5,039 (48,333) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 15. These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8. The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands): Derivative Instruments Beginning balance OCI (loss) before reclassifications Amounts reclassified from accumulated other comprehensive loss Net current period OCI Ending balance (a) (b) $ $ Year Ended December 31, 2013 Pension and Other Postretirement Benefits (49,592) (214) 26,747 (a) 26,533 (23,059) $ $ (39,503) 5,387 Total $ (89,095) 5,173 3,803 (b) 9,190 (30,313) $ 30,550 35,723 (53,372) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 15. These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8. FERC FORM NO. 1 (ED. 12-88) Page 123.57 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES 1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. 2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. 4. Report data on a year-to-date basis. Line No. Item (a) Unrealized Gains and Losses on Availablefor-Sale Securities (b) Minimum Pension Liability adjustment (net amount) (c) 1 Balance of Account 219 at Beginning of Preceding Year Foreign Currency Hedges Other Adjustments (d) (e) ( 39,502,968) 2 Preceding Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 3,802,824 3 Preceding Quarter/Year to Date Changes in Fair Value 5,386,683 4 Total (lines 2 and 3) 9,189,507 5 Balance of Account 219 at End of Preceding Quarter/Year ( 30,313,461) 6 Balance of Account 219 at Beginning of Current Year ( 30,313,461) 7 Current Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 2,780,792 8 Current Quarter/Year to Date Changes in Fair Value ( 10,414,982) 9 Total (lines 7 and 8) ( 7,634,190) ( 37,947,651) 10 Balance of Account 219 at End of Current Quarter/Year FERC FORM NO. 1 (NEW 06-02) Page 122a Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES Line No. Other Cash Flow Hedges Interest Rate Swaps Other Cash Flow Hedges [Specify] (f) (g) 1 ( 2 Totals for each category of items recorded in Account 219 (h) 49,592,318) ( 3 4 ( 3,589,049 26,747,134 32,133,817 35,722,866 5 ( 23,058,959) ( 53,372,420) 6 ( 23,058,959) ( 53,372,420) ( 11,224,156) ( 48,332,631) 7 13,483,153 8 ( 9 10 FERC FORM NO. 1 (NEW 06-02) 809,174) 10,384,980) Page 122b (i) (j) 424,968,650 460,691,516 421,220,870 426,260,659 16,263,945 12,673,979 ( Total Comprehensive Income 89,095,286) 213,775) 26,533,359 Net Income (Carried Forward from Page 117, Line 78) 5,039,789 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION 20150811-8000 FERC PDF (Unofficial) (1) 08/11/2015 An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function. Line No. Total Company for the Current Year/Quarter Ended (b) Classification (a) Electric (c) 1 Utility Plant 2 In Service 3 Plant in Service (Classified) 4 Property Under Capital Leases 15,394,598,560 15,394,598,560 214,810,000 214,810,000 446,350,053 446,350,053 16,055,758,613 16,055,758,613 5 Plant Purchased or Sold 6 Completed Construction not Classified 7 Experimental Plant Unclassified 8 Total (3 thru 7) 9 Leased to Others 10 Held for Future Use 11 Construction Work in Progress 12 Acquisition Adjustments 13 Total Utility Plant (8 thru 12) 14 Accum Prov for Depr, Amort, & Depl 15 Net Utility Plant (13 less 14) 51,340,595 51,340,595 591,741,133 591,741,133 255,525,919 255,525,919 16,954,366,260 16,954,366,260 6,173,810,334 6,173,810,334 10,780,555,926 10,780,555,926 5,520,859,057 5,520,859,057 16 Detail of Accum Prov for Depr, Amort & Depl 17 In Service: 18 Depreciation 19 Amort & Depl of Producing Nat Gas Land/Land Right 20 Amort of Underground Storage Land/Land Rights 21 Amort of Other Utility Plant 22 Total In Service (18 thru 21) 652,498,217 652,498,217 6,173,357,274 6,173,357,274 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 Total Leased to Others (24 & 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 Total Held for Future Use (28 & 29) 31 Abandonment of Leases (Natural Gas) 32 Amort of Plant Acquisition Adj 33 Total Accum Prov (equals 14) (22,26,30,31,32) FERC FORM NO. 1 (ED. 12-89) Page 200 453,060 453,060 6,173,810,334 6,173,810,334 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION Year/Period of Report 2014/Q4 End of Gas Other (Specify) Other (Specify) Other (Specify) Common (d) (e) (f) (g) (h) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 FERC FORM NO. 1 (ED. 12-89) Page 201 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) 1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. 2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements. Line No. Description of item Balance Beginning of Year (b) (a) 1 Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) Changes during Year Additions (c) 2 Fabrication 14,933,938 35,222,678 3 Nuclear Materials 69,265,767 32,375,702 4 Allowance for Funds Used during Construction 10,498,140 6,710,542 -155,307 1,986,868 5 (Other Overhead Construction Costs, provide details in footnote) 6 SUBTOTAL (Total 2 thru 5) 94,542,538 7 Nuclear Fuel Materials and Assemblies 8 In Stock (120.2) 79,772,809 9 In Reactor (120.3) 270,613,867 10 SUBTOTAL (Total 8 & 9) 270,613,867 11 Spent Nuclear Fuel (120.4) 12 Nuclear Fuel Under Capital Leases (120.6) 13 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 146,057,247 14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 219,099,158 15 Estimated net Salvage Value of Nuclear Materials in line 9 16 Estimated net Salvage Value of Nuclear Materials in line 11 17 Est Net Salvage Value of Nuclear Materials in Chemical Processing 18 Nuclear Materials held for Sale (157) 19 Uranium 20 Plutonium 21 Other (provide details in footnote): 22 TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21) FERC FORM NO. 1 (ED. 12-89) Page 202 79,772,809 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Amortization (d) Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) Year/Period of Report 2014/Q4 End of Balance End of Year (f) Changes during Year Other Reductions (Explain in a footnote) (e) Line No. 1 34,179,237 15,977,379 2 35,568,427 66,073,042 3 8,038,277 9,170,405 4 1,986,867 -155,306 5 91,065,520 6 7 79,772,809 81,632,181 8 268,754,495 9 268,754,495 10 11 12 -79,128,635 81,632,181 143,553,701 13 216,266,314 14 15 16 17 18 19 20 21 22 FERC FORM NO. 1 (ED. 12-89) Page 203 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) FOOTNOTE DATA Schedule Page: 202 Line No.: 2 Column: e Transfer of Fuel in Process to Fuel in Stock Schedule Page: 202 Line No.: 3 Column: e Transfer of Fuel in Process to Fuel in Stock Schedule Page: 202 Line No.: 4 Column: c Increase relates to AFUDC for material previously charged to FERC acct. 120.2 Schedule Page: 202 Line No.: 4 Column: e Transfer related to AFUDC cost from Fuel in Process to Fuel in Stock Schedule Page: 202 Line No.: 5 Column: e Transfer Use Tax Cost from Fuel in Process to Fuel in Stock Schedule Page: 202 Line No.: 8 Column: e Transfer of Fuel in Stock to Fuel in Reactor Schedule Page: 202 Line No.: 9 Column: e Amortization/Retirement of Fuel in Reactor Schedule Page: 202 Line No.: 13 Column: e Amortization/Retirement of Fuel in Reactor FERC FORM NO. 1 (ED. 12-87) Page 450.1 04/15/2015 2014/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) Year/Period of Report 2014/Q4 End of 1. Report below the original cost of electric plant in service according to the prescribed accounts. 2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. 3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. 4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. 5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. 6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) Line Account Balance Additions Beginning of Year No. (a) (b) (c) 1 1. INTANGIBLE PLANT 2 (301) Organization 3 (302) Franchises and Consents 3,475,960 23,634 4 (303) Miscellaneous Intangible Plant 603,194,565 48,927,912 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 606,670,525 48,951,546 6 2. PRODUCTION PLANT 7 A. Steam Production Plant 8 (310) Land and Land Rights 5,794,738 9 (311) Structures and Improvements 157,888,367 25,389,276 10 (312) Boiler Plant Equipment 1,333,140,554 49,823,431 11 (313) Engines and Engine-Driven Generators 12 (314) Turbogenerator Units 250,544,286 1,976,057 13 (315) Accessory Electric Equipment 162,923,486 11,316,781 14 (316) Misc. Power Plant Equipment 95,534,243 8,562,153 15 (317) Asset Retirement Costs for Steam Production 4,877,201 16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 2,010,702,875 97,067,698 17 B. Nuclear Production Plant 18 (320) Land and Land Rights 4,801,036 -383,247 19 (321) Structures and Improvements 781,642,123 9,414,716 20 (322) Reactor Plant Equipment 1,197,815,558 64,486,648 21 (323) Turbogenerator Units 378,950,436 7,156,830 22 (324) Accessory Electric Equipment 283,845,243 2,404,942 23 (325) Misc. Power Plant Equipment 161,916,486 5,248,169 24 (326) Asset Retirement Costs for Nuclear Production -73,701,972 20,041,754 25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 2,735,268,910 108,369,812 26 C. Hydraulic Production Plant 27 (330) Land and Land Rights 28 (331) Structures and Improvements 29 (332) Reservoirs, Dams, and Waterways 30 (333) Water Wheels, Turbines, and Generators 31 (334) Accessory Electric Equipment 32 (335) Misc. Power PLant Equipment 33 (336) Roads, Railroads, and Bridges 34 (337) Asset Retirement Costs for Hydraulic Production 35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 36 D. Other Production Plant 37 (340) Land and Land Rights 11,170,939 4,551,924 38 (341) Structures and Improvements 98,415,001 9,269,186 39 (342) Fuel Holders, Products, and Accessories 53,645,285 1,186,152 40 (343) Prime Movers 654,597,935 17,437,461 41 (344) Generators 1,091,781,031 143,206,211 42 (345) Accessory Electric Equipment 175,021,836 17,064,509 43 (346) Misc. Power Plant Equipment 26,072,490 -718,741 44 (347) Asset Retirement Costs for Other Production 6,052,254 45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 2,110,704,517 198,048,956 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 6,856,676,302 403,486,466 FERC FORM NO. 1 (REV. 12-05) Page 204 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Line No. 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 (2) X A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Account Balance Beginning of Year (a) (b) 3. TRANSMISSION PLANT (350) Land and Land Rights (352) Structures and Improvements (353) Station Equipment (354) Towers and Fixtures (355) Poles and Fixtures (356) Overhead Conductors and Devices (357) Underground Conduit (358) Underground Conductors and Devices (359) Roads and Trails (359.1) Asset Retirement Costs for Transmission Plant TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 4. DISTRIBUTION PLANT (360) Land and Land Rights (361) Structures and Improvements (362) Station Equipment (363) Storage Battery Equipment (364) Poles, Towers, and Fixtures (365) Overhead Conductors and Devices (366) Underground Conduit (367) Underground Conductors and Devices (368) Line Transformers (369) Services (370) Meters (371) Installations on Customer Premises (372) Leased Property on Customer Premises (373) Street Lighting and Signal Systems (374) Asset Retirement Costs for Distribution Plant TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT (380) Land and Land Rights (381) Structures and Improvements (382) Computer Hardware (383) Computer Software (384) Communication Equipment (385) Miscellaneous Regional Transmission and Market Operation Plant (386) Asset Retirement Costs for Regional Transmission and Market Oper TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 6. GENERAL PLANT (389) Land and Land Rights (390) Structures and Improvements (391) Office Furniture and Equipment (392) Transportation Equipment (393) Stores Equipment (394) Tools, Shop and Garage Equipment (395) Laboratory Equipment (396) Power Operated Equipment (397) Communication Equipment (398) Miscellaneous Equipment SUBTOTAL (Enter Total of lines 86 thru 95) (399) Other Tangible Property (399.1) Asset Retirement Costs for General Plant TOTAL General Plant (Enter Total of lines 96, 97 and 98) TOTAL (Accounts 101 and 106) (102) Electric Plant Purchased (See Instr. 8) (Less) (102) Electric Plant Sold (See Instr. 8) (103) Experimental Plant Unclassified TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) FERC FORM NO. 1 (REV. 12-05) Page Additions (c) 140,677,956 85,364,260 982,150,134 105,328,472 438,967,983 364,573,296 20,834,925 34,000,223 14,670,316 3,825,103 -3,821,843 2,171,897,249 32,970,435 57,699,700 75,501,118 459,214,800 550,481,153 306,020,381 655,481,553 1,541,977,778 785,053,545 346,619,642 280,374,035 42,378,515 2,059,381 3,888,451 23,513,364 2,123,630 25,824,921 15,875,259 14,747,877 54,477,481 33,566,534 15,647,850 19,982,627 1,168,258 75,127,449 809,795 5,175,929,669 213,685,428 14,645,315 174,375,647 162,883,608 41,447,922 248,296 34,684,823 911,788 11,076,871 216,899,580 13,188,085 670,361,935 206 Year/Period of Report 2014/Q4 End of 21,480,051 -3,826,545 125,845 517,508 31,056,101 25,231,686 4,509,031 2,932,559 115,878 17,547,385 12,095,266 93,487,906 670,361,935 15,481,535,680 93,487,906 792,581,781 15,481,535,680 792,581,781 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. 7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. 8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. 9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date Retirements Adjustments Transfers Balance at Line End of Year No. (d) (e) (f) (g) 6,494 3,643,639 3,650,133 3,493,100 648,478,838 651,971,938 -1,229 309,116 23,766,634 206,277,611 40,725,377 50,828,094 9,547,484 -309,116 331,145,200 -1,229 1,922,408 4,927,610 3,568,309 3,287,311 247,043 -110,118 13,952,681 -110,118 137,943 4,803,626 5,482,551 1,325,013 -588 11,749,133 356,847,014 -588 -111,935 FERC FORM NO. 1 (REV. 12-05) Page 205 5,793,509 159,820,125 1,176,686,374 211,794,966 123,412,173 94,239,796 4,877,201 1,776,624,144 4,417,789 789,134,431 1,257,374,596 382,538,957 282,962,874 166,807,494 -53,660,218 2,829,575,923 15,722,863 107,546,244 54,831,437 667,231,770 1,229,504,103 190,761,332 25,353,749 6,052,254 2,297,003,752 6,903,203,819 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Retirements (d) Year/Period of Report 2014/Q4 End of (2) X A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Adjustments Transfers Balance at End of Year (e) (f) (g) 6,087,393 2,007,330 10,073,596 4,013,911 3,944,883 10,266,851 831,385 665,575 -266,106 -1,566,488 -14,157 19,665,279 16,378,894 499,606 174,517 3,776,609 849,704 -12,140,829 153,274,790 91,126,916 978,521,546 105,328,472 459,350,543 358,514,688 20,946,613 34,517,731 2,201,581,299 7,247,037 2,070,051 1,590,347 8,392,283 6,388,617 794,560 9,627,853 207,528 268,795 2,511,227 -540,420 59,259,475 80,064,756 466,810,726 2,123,630 569,327,832 322,336,816 668,639,083 1,587,078,882 812,216,956 361,472,932 290,728,809 42,798,825 302,757 -2,097,028 73,537,459 41,071,765 -12,147,151 5,336,396,181 3,738,398 2,843,749 4,187,127 11,199 1,451,158 101,225 497,001 3,117,483 -121,559 -984,094 -14,506 15,947,340 -14,212 -157,739 62,054 -107,126 14,645,315 201,571,791 185,271,545 41,894,156 237,097 36,166,224 810,563 10,681,536 231,171,743 25,345,405 747,795,375 15,947,340 437,181,531 -107,126 4,012,682 747,795,375 15,840,948,612 437,181,531 4,012,682 15,840,948,612 FERC FORM NO. 1 (REV. 12-05) 124,330 Page 207 Line No. 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) (1) 08/11/2015 An Original Arizona Public Service Company Line No. Name of Lessee (Designate associated companies with a double asterisk) (a) (2) X A Resubmission ELECTRIC PLANT LEASED TO OTHERS (Account 104) Description of Property Leased (b) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 TOTAL FERC FORM NO. 1 (ED. 12-95) Date of Report (Mo, Da, Yr) 04/15/2015 Page 213 Commission Authorization (c) Year/Period of Report End of 2014/Q4 Expiration Date of Lease (d) Balance at End of Year (e) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) Year/Period of Report 2014/Q4 End of 1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. 2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105. Description and Location Of Property (a) Line No. Date Originally Included Date Expected to be used in This Account in Utility Service (b) (c) Balance at End of Year (d) 1 Land and Rights: 2 Roanoke Substation 3 4 Prescott Service Center Office 5 12/31/2024 592,651 10/31/2006 12/31/2024 401,193 12/31/14 12/31/2024 320,827 12/31/2008 12/31/2016 14,677,520 12/31/2008 12/31/2015 18,565,305 12/31/2008 12/31/2016 4,020,354 5/31/2008 12/31/2017 653,352 12/31/1999 12/31/2024 281,561 12/31/1999 12/31/2024 92,023 12/31/1999 12/31/2024 556,005 Township 030N 070W Sec 28; Maricopa, AZ 18 Buckeye to Elianto (SV4) Transmission Line 19 12/31/1993 Township 040N 020W Sec 20; Surprise, AZ 16 Palo Verde to Sun Valley (TS5) 500KV Transmission Ln 17 2,004,206 Township 040N 040W Sec 29; Maricopa, AZ 14 Palm Valley (TS3) to Trilby Wash (TS1) Transmission 15 12/31/2017 146 E. Purtill Trail, Tonto Basin, AZ 12 Sun Valley (TS5) to Trilby Wash (TS1) Transmission 13 11/30/2005 15021 N. 33rd Place, Phoenix, AZ 10 Punkin Center Substation 11 282,772 11th St. & Jackson St., Phoenix, AZ 8 Paradise Substation 9 12/31/2024 Prescott, AZ 6 Madison Substation 7 12/31/1991 35th Ave. & Roanoke Ave., Phoenix, AZ Township 010N 030W Sec 7; Buckeye, AZ 20 21 Other Property: 22 Other General Parcels (2) 23 24 Other Transmission Parcels (2) 25 26 Other Distribution Parcels (4) 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 Total FERC FORM NO. 1 (ED. 12-96) 51,340,595 Page 214 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) Year/Period of Report 2014/Q4 End of 1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. 2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105. Description and Location Of Property (a) Line No. Date Originally Included Date Expected to be used in This Account in Utility Service (b) (c) Balance at End of Year (d) 1 Land and Rights: 2 Delaney Substation 3 4 Payson Substation 5 12/31/2008 12/31/2016 746,020 12/31/2008 12/31/2017 4,825,172 10/31/2008 12/31/2020 1,929,113 5/1/2009 12/31/2024 427,534 118th Place & Via Dona Rd; Scottsdale, AZ 10 Citrus (WS4) Substation 11 964,987 Township 04N 04E Sec29; Buckeye, AZ 8 Via Dona (NE2) Substation 9 12/31/2017 Township100N 100E Sec2; Payson, AZ 6 Sun Valley (TS5) Substation 7 9/30/2008 Thomas & 451st Ave.; Maricopa, AZ Parcel 502-40-267 /T01NR02W.S10/ 2.633 acres 12 13 14 15 16 17 18 19 20 21 Other Property: 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 Total FERC FORM NO. 1 (ED. 12-96) 51,340,595 Page 214.1 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Year/Period of Report 2014/Q4 End of 1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts) 3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped. Line No. Description of Project Construction work in progress Electric (Account 107) (b) 99,560,823 (a) 1 Palo Verde Nuclear Plant Improvements 2 Cholla Plant Improvements 3,762,558 3 Four Corners Plant Improvements 32,907,341 4 Navajo Plant Improvements 2,715,762 5 Gas & Oil Plant Improvements 38,962,228 6 Solar Additions 15,826,005 7 8 Transmission Land and Land Rights 3,652,083 9 Transmission Substations - Add/Improvements 31,459,266 10 500 KV Lines - Add/Improvements 1,292,810 11 115/230 KV Lines - Add/Improvements 29,130,163 12 69 KV Lines - Add/Improvements 6,340,702 13 ANPP 500 KV Transmission System 3,586,744 14 Navajo Southern Transmission System 652,383 15 PV/YUMA 500 KV Transmission System 8,807 16 Hassayampa - North Gila 500kV #2 Transmission System 142,645,274 17 Morgan - Pinnacle Peak Transmission System 1,690,437 18 Palo Verde - Morgan 500kV Transmission System 69,328,534 19 Phoenix - Mead Transmission System 97,699 20 Transmission Lines Relocates 133,960 21 Transmission Lines Conversion 92,995 22 Transmission Reliability 6,893,224 23 24 Distribution Land and Land Rights 748,742 25 Distribution Substation - Add/Improvements 13,102,166 26 Overhead lines - Add/Improvements 5,302,540 27 Underground Lines - Add/Improvements 13,229,571 28 Underground Conversion 17,768 29 Distribution Relocates 3,458,262 30 Distribution Replace 12,115,768 31 Distribution Reliability 1,763,441 32 Other Distribution 1,158,534 33 34 General Computer/Communications 38,352,545 35 Buildings & Equip/Land & Land Rights 11,751,998 36 37 38 39 40 41 42 43 TOTAL FERC FORM NO. 1 (ED. 12-87) 591,741,133 Page 216 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108) 1. Explain in a footnote any important adjustments during year. 2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property. 3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. 4. Show separately interest credits under a sinking fund or similar method of depreciation accounting. Line No. Section A. Balances and Changes During Year Electric Plant in Total (c+d+e) Service (b) (c) Item (a) 1 Balance Beginning of Year 5,471,305,713 5,471,305,713 367,155,333 367,155,333 -923,459 -923,459 1,699,146 1,699,146 506,215 506,215 368,437,235 368,437,235 286,684,301 286,684,301 13 Cost of Removal 36,305,236 36,305,236 14 Salvage (Credit) 31,361,459 31,361,459 15 TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14) 291,628,078 291,628,078 16 Other Debit or Cr. Items (Describe, details in footnote): -27,255,813 -27,255,813 5,520,859,057 5,520,859,057 Electric Plant Held for Future Use (d) 2 Depreciation Provisions for Year, Charged to 3 (403) Depreciation Expense 4 (403.1) Depreciation Expense for Asset Retirement Costs 5 (413) Exp. of Elec. Plt. Leas. to Others 6 Transportation Expenses-Clearing 7 Other Clearing Accounts 8 Other Accounts (Specify, details in footnote): 9 10 TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9) 11 Net Charges for Plant Retired: 12 Book Cost of Plant Retired 17 18 Book Cost or Asset Retirement Costs Retired 19 Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18) Section B. Balances at End of Year According to Functional Classification 20 Steam Production 1,114,975,493 1,114,975,493 21 Nuclear Production 1,510,571,044 1,510,571,044 24 Other Production 568,234,343 568,234,343 25 Transmission 689,158,219 689,158,219 1,452,169,765 1,452,169,765 185,750,193 185,750,193 5,520,859,057 5,520,859,057 22 Hydraulic Production-Conventional 23 Hydraulic Production-Pumped Storage 26 Distribution 27 Regional Transmission and Market Operation 28 General 29 TOTAL (Enter Total of lines 20 thru 28) FERC FORM NO. 1 (REV. 12-05) Page 219 Electric Plant Leased to Others (e) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 219 Line No.: 12 Column: b FERC Page 219 Column (b), Line 12 286,684,301 Cholla Unit 2 - NBV of Retirement moved to Regulatory Asset (182.3) 130,579,692 Cholla Unit 2 - Cost of Removal Reserve move to Regulatory Liability (254.0) (12,956,323) FERC Page 204-207 Column (d), Line 5 3,650,133 FERC Page 204-207 Column (d), Line 48 6,087,393 FERC Page 204-207 Column (d), Line 60 499,606 Four Corners Unit 1-3 - NBV of Retirement moved to Regulatory Asset (182.3) General Plant Retirements 4,072,317 Other (145,111) FERC Page 204-207 Column (d), Line 104 Schedule Page: 219 18,709,523 Line No.: 16 437,181,531 Column: c Palo Verde Decommissioning Asset Retirement Obligation in Reg. Liability Accelerated CIAC to Regulatory Assets Childs Irving Decommissioning SCE Four Corners U4-5 - Accretion Cholla Unit 2 Regulatory Asset Amortization Saguaro Steam Regulatory Asset Amortization Reserve Transfers-- Accounts 1110,1112, & 1220 & Other Entities FERC FORM NO. 1 (ED. 12-87) Page 450.1 (16,251,180) (4,138,619) (304,371) 882,133 (1,712,596) (2,472,088) (2,936,533) (322,559) (27,255,813) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) Year/Period of Report End of X A Resubmission INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) 2014/Q4 1. Report below investments in Accounts 123.1, investments in Subsidiary Companies. 2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in columns (e),(f),(g) and (h) (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. 3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. Line No. Description of Investment Date Acquired (b) (a) Date Of Maturity (c) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 Total Cost of Account 123.1 $ FERC FORM NO. 1 (ED. 12-89) 0 Page 224 TOTAL Amount of Investment at Beginning of Year (d) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) Date of Report (Mo, Da, Yr) 04/15/2015 X A Resubmission INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued) Year/Period of Report End of 2014/Q4 4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. 5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. 6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year. 7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible in column (f). 8. Report on Line 42, column (a) the TOTAL cost of Account 123.1 Equity in Subsidiary Earnings of Year (e) Revenues for Year Amount of Investment at End of Year (g) (f) Gain or Loss from Investment Disposed of (h) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 FERC FORM NO. 1 (ED. 12-89) Page 225 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 MATERIALS AND SUPPLIES 1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. 2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable. Line No. Account Balance Beginning of Year Balance End of Year (a) (b) (c) 1 Fuel Stock (Account 151) Department or Departments which Use Material (d) 36,597,494 32,263,222 2 Fuel Stock Expenses Undistributed (Account 152) 3 Residuals and Extracted Products (Account 153) 4 Plant Materials and Operating Supplies (Account 154) 5 Assigned to - Construction (Estimated) 6 Assigned to - Operations and Maintenance 116,254,030 114,840,074 8 Transmission Plant (Estimated) 7 Production Plant (Estimated) 31,042,642 30,450,516 9 Distribution Plant (Estimated) 73,978,882 73,808,775 10 Regional Transmission and Market Operation Plant (Estimated) 11 Assigned to - Other (provide details in footnote) 12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 212,216 455,476 221,487,770 219,554,841 194,192 -666,160 258,279,456 251,151,903 13 Merchandise (Account 155) 14 Other Materials and Supplies (Account 156) 15 Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util) 16 Stores Expense Undistributed (Account 163) 17 18 19 20 TOTAL Materials and Supplies (Per Balance Sheet) FERC FORM NO. 1 (REV. 12-05) Page 227 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 227 Line No.: 7 Column: b The method used to allocate the materials and supplies to production including intangible and general, transmission and distribution is to allocate the total materials and supplies inventory, after the amount assigned to other, based on a plant allocator as derived from the applicable plant to total electric plant in service as found on page 207. Schedule Page: 227 Line No.: 7 Column: c The method used to allocate the materials and supplies to production including intangible and general, transmission and distribution is to allocate the total materials and supplies inventory, after the amount assigned to other, based on a plant allocator as derived from the applicable plant to total electric plant in service as found on page 207. Schedule Page: 227 Line No.: 8 Column: b The method used to allocate the materials and supplies to production including intangible and general, transmission and distribution is to allocate the total materials and supplies inventory, after the amount assigned to other, based on a plant allocator as derived from the applicable plant to total electric plant in service as found on page 207. Schedule Page: 227 Line No.: 8 Column: c The method used to allocate the materials and supplies to production including intangible and general, transmission and distribution is to allocate the total materials and supplies inventory, after the amount assigned to other, based on a plant allocator as derived from the applicable plant to total electric plant in service as found on page 207. Schedule Page: 227 Line No.: 9 Column: b The method used to allocate the materials and supplies to production including intangible and general, transmission and distribution is to allocate the total materials and supplies inventory, after the amount assigned to other, based on a plant allocator as derived from the applicable plant to total electric plant in service as found on page 207. Schedule Page: 227 Line No.: 9 Column: c The method used to allocate the materials and supplies to production including intangible and general, transmission and distribution is to allocate the total materials and supplies inventory, after the amount assigned to other, based on a plant allocator as derived from the applicable plant to total electric plant in service as found on page 207. Schedule Page: 227 Line No.: 11 Column: b Assigned to - Other. General Plant expenses for communication and garage equipment. Schedule Page: 227 Line No.: 11 Column: c Assigned to - Other. General Plant expenses for communication and garage equipment. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) (1) 08/11/2015 An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 Allowances (Accounts 158.1 and 158.2) 1. Report below the particulars (details) called for concerning allowances. 2. Report all acquisitions of allowances at cost. 3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. 4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). 5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Line No. SO2 Allowances Inventory (Account 158.1) (a) 1 Balance-Beginning of Year 2 3 Acquired During Year: 4 Issued (Less Withheld Allow) 5 Returned by EPA 6 7 8 Purchases/Transfers: 9 10 11 12 13 14 15 Total 16 17 Relinquished During Year: 18 Charges to Account 509 19 Other: 20 21 Cost of Sales/Transfers: 22 23 24 25 26 27 28 Total 29 Balance-End of Year 30 31 Sales: 32 Net Sales Proceeds(Assoc. Co.) 33 Net Sales Proceeds (Other) 34 Gains 35 Losses Allowances Withheld (Acct 158.2) 36 Balance-Beginning of Year 37 Add: Withheld by EPA 38 Deduct: Returned by EPA 39 Cost of Sales 40 Balance-End of Year 41 42 Sales: 43 Net Sales Proceeds (Assoc. Co.) 44 Net Sales Proceeds (Other) 45 Gains 46 Losses FERC FORM NO. 1 (ED. 12-95) 2015 Current Year No. (b) Amt. (c) No. (d) Amt. (e) 156,882.00 36,876.00 11,611.00 11,611.00 11,611.00 11,611.00 7,037.00 161,456.00 48,487.00 533.00 533.00 533.00 533.00 533.00 Page 228a 174 174 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Allowances (Accounts 158.1 and 158.2) Year/Period of Report End of 2014/Q4 (Continued) 6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. 7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). 8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies. 9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. 10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales. 2016 No. (f) 36,876.00 2017 Amt. (g) No. (h) 36,876.00 Amt. (i) Future Years No. Amt. (k) (j) 958,776.00 Totals No. (l) 1,226,286.00 48,487.00 48,487.00 11,611.00 11,611.00 301,886.00 348,330.00 11,611.00 11,611.00 301,886.00 348,330.00 Line No. Amt. (m) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 7,037.00 48,487.00 48,487.00 1,309,149.00 1,616,066.00 533.00 533.00 26,091.00 1,066.00 533.00 28,223.00 1,066.00 1,066.00 533.00 533.00 26,624.00 28,223.00 533.00 FERC FORM NO. 1 (ED. 12-95) Page 229a 16 16 1,066.00 190 190 36 37 38 39 40 41 42 43 44 45 46 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 228 Line No.: 29 Column: m Total ending balance of account 158.1 per this page does not agree to the corresponding line item on page 110. The difference is due to ending balance of $4,833,925 in CO2 allowances issued by the California Air Resources Board (CARB). FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) (1) 08/11/2015 An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 Allowances (Accounts 158.1 and 158.2) 1. Report below the particulars (details) called for concerning allowances. 2. Report all acquisitions of allowances at cost. 3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. 4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). 5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Line No. NOx Allowances Inventory (Account 158.1) (a) 1 Balance-Beginning of Year 2 3 Acquired During Year: 4 Issued (Less Withheld Allow) 5 Returned by EPA 6 7 8 Purchases/Transfers: 9 10 11 12 13 14 15 Total 16 17 Relinquished During Year: 18 Charges to Account 509 19 Other: 20 21 Cost of Sales/Transfers: 22 23 24 25 26 27 28 Total 29 Balance-End of Year 30 31 Sales: 32 Net Sales Proceeds(Assoc. Co.) 33 Net Sales Proceeds (Other) 34 Gains 35 Losses Allowances Withheld (Acct 158.2) 36 Balance-Beginning of Year 37 Add: Withheld by EPA 38 Deduct: Returned by EPA 39 Cost of Sales 40 Balance-End of Year 41 42 Sales: 43 Net Sales Proceeds (Assoc. Co.) 44 Net Sales Proceeds (Other) 45 Gains 46 Losses FERC FORM NO. 1 (ED. 12-95) 2015 Current Year No. (b) Amt. (c) Page 228b No. (d) Amt. (e) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Allowances (Accounts 158.1 and 158.2) Year/Period of Report End of 2014/Q4 (Continued) 6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. 7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). 8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies. 9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. 10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales. 2016 No. (f) Future Years 2017 Amt. (g) No. (h) Amt. (i) No. (j) Totals Amt. (k) No. (l) Amt. (m) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 FERC FORM NO. 1 (ED. 12-95) Page 229b Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Line No. Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a) (2) X A Resubmission EXTRAORDINARY PROPERTY LOSSES (Account 182.1) Total Amount of Loss Losses Recognised During Year (b) (c) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 TOTAL FERC FORM NO. 1 (ED. 12-88) Page 230a Year/Period of Report 2014/Q4 End of WRITTEN OFF DURING YEAR Account Charged (d) Amount (e) Balance at End of Year (f) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Line No. (2) X A Resubmission UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2) Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of Commission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a) Total Amount of Charges Costs Recognised During Year (b) (c) 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 TOTAL FERC FORM NO. 1 (ED. 12-88) Page 230b Year/Period of Report 2014/Q4 End of WRITTEN OFF DURING YEAR Balance at Account Charged Amount End of Year (d) (e) (f) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) (1)08/11/2015 An Original Arizona Public Service Company Year/Period of Report End of 2014/Q4 (2) X A Resubmission Transmission Service and Generation Interconnection Study Costs 1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. 2. List each study separately. 3. In column (a) provide the name of the study. 4. In column (b) report the cost incurred to perform the study at the end of period. 5. In column (c) report the account charged with the cost of the study. 6. In column (d) report the amounts received for reimbursement of the study costs at end of period. 7. In column (e) report the account credited with the reimbursement received for performing the study. Reimbursements Line Account Credited Costs Incurred During Received During No. With Reimbursement Period Account Charged Description the Period (d) (e) (a) (b) (c) 1 Transmission Studies 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Generation Studies 22 SIS (W502466) 40 143 143 23 SMG FACSTD (WA100608) 143 25,368 143 24 SMG FACSTD (WA100608) 143 25 SMG SISSTD (WA127662) 26 SMG SISSTD (WA129495) 27 Facilities Study (WA131362) ( 28 Facilities Study (WA144239) 29 SIS (WA158156) ( 23,871 143 143 ( 28,245) 143 143 ( 28,836) 143 218) 143 143 17 143 143 1,371) 143 30 Facilities Study (WA172708) 82,575 143 31 SIS (WA173723) 143 ( 2,391 143 8,719) 143 143 32 Facilities Study (WA175065) 790 143 143 33 SMG FACSTD (WA179246) 143 33,400 143 34 Facilities Study (WA181006) 35 Facilities Study (WA183634) ( 33 143 143 6) 143 263,285 143 143 38,160 143 36 SMG FACSTD (WA188594) 37 SMG FESSTD (WA192657) 38 Feasibility Study (WA201230) 143 ( 462) 143 9,444 143 143 39 SMG FESSTD (WA202123) 258 143 143 40 SIS (WA205084) 575 143 143 FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) (1)08/11/2015 An Original Arizona Public Service Company Line No. 1 Description (a) Year/Period of Report End of 2014/Q4 (2) X A Resubmission Transmission Service and Generation Interconnection Study Costs (continued) Costs Incurred During Period (b) Account Charged (c) Reimbursements Received During the Period (d) Account Credited With Reimbursement (e) Transmission Studies 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Generation Studies 22 SIS (WA205085) 6,650 143 23 SMG SISSTD (WA208971) 24 SMG FESSTD (WA210441) 25 SMG SISSTD (WA61589) 26 SIS (WA61729) 143 143 ( 30,000) 143 73 143 ( 1,000) 143 7 143 143 24 143 143 1,122) 143 143 466 143 143 29 SIS (WA85636) 8 143 143 30 SIS (WA92332) 140 143 143 31 SIS (WA95638) 119 143 143 27 Facilities Study (WA69759) 28 SIS (WA84273) ( 32 33 34 35 36 37 38 39 40 FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission OTHER REGULATORY ASSETS (Account 182.3) Year/Period of Report 2014/Q4 End of 1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Assets being amortized, show period of amortization. Line No. Description and Purpose of Other Regulatory Assets (a) 1 Deferred Compensation Balance at Beginning of Current Quarter/Year (b) Debits (c) 34,225,593 ( CREDITS Written off During Written off During the Quarter/Year the Period Account Charged Amount (d) (e) Balance at end of Current Quarter/Year (f) 34,162,184 63,409) 2 Amortize through 2036 3 4 Capital Contribution on Phoenix-Mead Transmission 108 12,036,483 332,041 11,704,442 4,151,383 123,209,269 5 U-1345-90-269 Amortize through 2050 6 7 Income Taxes - AFUDC Equity 18,383,876 various 108,976,776 8 E-01345A-03-0437 Amortize through 2044 9 10 Palo Verde Rent Levelization 1,525,582 525 762,791 762,791 115,376 407 55,045 60,331 8,001,220 190 2,501,320 5,499,900 40,527,423 6,925,515 11 E-01345A-03-0437 Amortize through 2015 12 13 Decontamination 14 E-01345A-03-0437 Amortize through 2016 15 16 Prior Flow Through of Tax Benefits 17 Amortize through 2019 18 19 Deferred Fuel and Purchased Power 20,755,441 26,697,497 411.8,426, 33,769,743 63,672,305 547, 555 20 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 21 Amortize through 2015 22 23 Deferred Fuel and Purchased Power Mark-to-Market 97,442,048 24 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 25 Amortize through 2017 26 27 Deferred Fuel and Purchased Power - Accr. Interest 205,648 254 205,648 18,521,906 ( 12,200,936) 501 6,320,970 7,338,442 501 417,889 6,920,553 22,715,820 571 9,086,328 13,629,492 6,887,609 485,036,791 120,879,091 1,147,084,875 28 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 29 Amortize through 2014 30 31 Four Corners Coal Reclamation 32 E-01345A-05-0816, -0826, -0827 33 Amortize through 2038 34 35 Navajo Coal Reclamation 36 E-01345A-08-0172 Amortize through 2026 37 38 Transmission Vegetation Management 39 ER11-3468-000 Amortize through 2016 40 41 Pension and Other Postretirement Benefits 177,519,396 228.3, 926 314,405,004 42 E-01345A-08-0172 43 44 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 760,685,480 Page 507,278,486 232 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission OTHER REGULATORY ASSETS (Account 182.3) Year/Period of Report 2014/Q4 End of 1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Assets being amortized, show period of amortization. Line No. Description and Purpose of Other Regulatory Assets (a) Balance at Beginning of Current Quarter/Year (b) Debits (c) CREDITS Written off During Written off During the Quarter/Year the Period Account Charged Amount (d) (e) Balance at end of Current Quarter/Year (f) 1 2 Pension and Other Postretirement Benefits Deferral 926 12,712,507 8,475,000 4,237,507 3 E-01345A-08-0172 4 Amortize through 2015 5 6 Income Taxes - Change in Rates 3,114,896 ( 16,480) 283, 410.1 48,420 3,049,996 16,902,085 ( 89,424) 283, 410.1 1,528,423 15,284,238 8,667,172 283, 410.1 1,569,936 47,916,218 7 Amortize through 2043 8 9 Income Taxes - Medicare Subsidy 10 Amortize through 2024 11 12 Income Taxes - Investment Tax Credit Basis Adjustmt 40,818,982 13 Amortize through 2044 14 15 Property Tax Deferral 30,282,583 11,411,699 18,870,884 25,182,071 34,391,988 400 21,961,565 9,996,714 1,091,135 400 11,087,849 20,750,051 130,025,955 403 4,680,754 146,095,252 278,697 77,253,271 120,879,091 1,147,084,875 16 17 Lost Fixed Cost Recovery 37,612,494 18 Amortize through 2015 19 20 FERC Transmission Cost Adjustor 21 Amortize through 2014 22 23 Retired Power Plant Costs 24 Amortize through 2033 25 26 Four Corners Cost Deferral 40,328,527 407.4 37,203,441 27 Amortize through 2024 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 760,685,480 Page 507,278,486 232.1 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 232 Line No.: 7 Column: d 411.8, 426.5, 555 FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission MISCELLANEOUS DEFFERED DEBITS (Account 186) 1. Report below the particulars (details) called for concerning miscellaneous deferred debits. 2. For any deferred debit being amortized, show period of amortization in column (a) 3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes. Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 Description of Miscellaneous Deferred Debits (a) Rouse Promissory Note (01/2015) Rouse Deferred Lease Payments (Through 2045) Balance at Beginning of Year Debits (b) (c) CREDITS Account Charged (d) 131 924,995 84,663,061 8,052,092 931 200,000 232 Information Sys Leases & Maint. 5,445,829 64,847,703 165 Unamortized Arrangement Fees 3,614,660 Redhawk Effluent Water Prepaid Training (03/2011 to 03/2016) 2,238,693 431, 525 241,250 232 High Lonesome Wind Ranch Tax Cr Transmission Debits (11/2014 to 03/2016) Prepaid Payroll Agreements Prepaid Water Supply Agreements Through 2050 4,061,193 Amount (e) 847,910 3,434,810 Balance at End of Year (f) 77,085 89,280,343 200,000 62,351,906 7,941,626 2,162,158 3,691,195 193,000 48,250 1,083,722 142 1,083,722 5,289,645 565 9,350,838 294,601 294,601 7,909,413 165 Debt Shelf Registration 236,029 54,320 131 290,349 Freight in Transit 108,980 728,444 232 837,424 Prepaid Monitoring Services (2014 to 2023) 802,372 165 Minor Items 362,239 4,373 various 219,765 7,689,648 44,387 757,985 69,665 296,947 47 Misc. Work in Progress Deferred Regulatory Comm. 48 Expenses (See pages 350 - 351) 49 TOTAL FERC FORM NO. 1 (ED. 12-94) 108,864,622 121,840,013 Page 233 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES (Account 190) 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes. 2. At Other (Specify), include deferrals relating to other income and deductions. Line No. Description and Location Balance of Begining of Year (b) (a) Balance at End of Year (c) 1 Electric 48,466,235 66,251,274 3 Pension and Other Post Retirement Liabilities 2 Risk Management Activities 186,212,541 194,541,344 4 Regulated Liabilities - Asset Retirement Obligation 105,057,220 115,824,489 5 Regulated Liabilities - Other 125,955,643 248,332,195 6 Other 270,397,326 226,548,062 736,088,965 851,497,364 736,088,965 851,497,364 7 Other 8 TOTAL Electric (Enter Total of lines 2 thru 7) 9 Gas 10 11 12 13 14 15 Other 16 TOTAL Gas (Enter Total of lines 10 thru 15 17 Other (Specify) 18 TOTAL (Acct 190) (Total of lines 8, 16 and 17) Notes FERC FORM NO. 1 (ED. 12-88) Page 234 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission CAPITAL STOCKS (Account 201 and 204) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. 2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Line No. Class and Series of Stock and Name of Stock Series Number of shares Authorized by Charter Par or Stated Value per share Call Price at End of Year (a) (b) (c) (d) 1 Common Stock 100,000,000 2 3 Total Common Stock 100,000,000 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 FERC FORM NO. 1 (ED. 12-91) Page 250 2.50 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission CAPITAL STOCKS (Account 201 and 204) (Continued) Year/Period of Report 2014/Q4 End of 3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. 4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or non-cumulative. 5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purposes of pledge. OUTSTANDING PER BALANCE SHEET (Total amount outstanding without reduction for amounts held by respondent) Shares Amount (e) (f) 71,264,947 178,162,368 HELD BY RESPONDENT AS REACQUIRED STOCK (Account 217) Shares (g) Cost (h) IN SINKING AND OTHER FUNDS Shares (i) Line No. Amount (j) 1 2 71,264,947 178,162,368 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 FERC FORM NO. 1 (ED. 12-88) Page 251 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission OTHER PAID-IN CAPITAL (Accounts 208-211, inc.) Year/Period of Report 2014/Q4 End of Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such change. (a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation. (b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to amounts reported under this caption including identification with the class and series of stock to which related. (c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. (d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations, disclose the general nature of the transactions which gave rise to the reported amounts. Line No. Item (a) 1 Gain on Resale or Cancellation of Capital Stock - Account 210 Amount (b) 1,505,626 2 Balance at Beginning of Year: $1,505,626 3 Credits 4 Debits 5 Balance at End of Year: $1,505,626 6 7 Misc Paid in Capital - Account 211 8 Transfer of Contract from Pinnacle West Marketing & Trading LLC 12,323,739 9 Balance at Beginning of Year: $12,323,739 10 Credit 11 Debit 12 Balance at End of Year: $12,323,739 13 14 El Dorado transfer of Aegis software to APS 4,571,000 15 Balance at Beginning of Year: $4,571,000 16 Credit 17 Debit 18 Balance at End of Year: $4,571,000 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 TOTAL FERC FORM NO. 1 (ED. 12-87) 18,400,365 Page 253 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 253 Line No.: 8 Column: a Pinnacle West Marketing & Trading LLC is a subsidiary of Pinnacle West Capital Corporation, parent to Arizona Public Service Company. Schedule Page: 253 Line No.: 14 Column: a El Dorado is a subsidiary of Pinnacle West Capital Corporation, parent to Arizona Public Service Company. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission CAPITAL STOCK EXPENSE (Account 214) Year/Period of Report 2014/Q4 End of 1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock. 2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged. Line No. 1 Common Stock Expense Class and Series of Stock (a) Balance at End of Year (b) 37,461,284 2 Shelf Registration 50,368 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 TOTAL FERC FORM NO. 1 (ED. 12-87) 37,511,652 Page 254b Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission LONG-TERM DEBT (Account 221, 222, 223 and 224) 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received. 5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were issued. 6. In column (b) show the principal amount of bonds or other long-term debt originally issued. 7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued. 8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount. Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted. 9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as specified by the Uniform System of Accounts. Line No. Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a) Principal Amount Of Debt issued (b) Total expense, Premium or Discount (c) 1 Pollution Control Bonds Account 221 2 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series A 49,400,000 1,062,971 3 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series B 65,750,000 1,314,678 4 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series C 31,500,000 776,159 5 Coconino County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 1994 Series A 32,650,000 1,055,827 6 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. Series 1998 16,870,000 538,817 7 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 12,850,000 544,829 8 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series B 26,710,000 653,379 9 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 38,150,000 1,124,037 10 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series B 32,000,000 466,689 11 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series C 32,000,000 656,756 12 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series D 32,000,000 411,777 13 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series E 32,000,000 391,683 14 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series A 35,975,000 541,622 15 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series B 32,000,000 617,526 16 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series C 32,000,000 445,268 17 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series D 32,000,000 342,229 18 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series E 32,000,000 342,228 565,855,000 11,286,475 200,000,000 2,049,339 300,000,000 2,529,839 300,000,000 2,133,668 250,000,000 2,362,692 250,000,000 1,659,703 150,000,000 1,333,769 19 Subtotal 20 21 Other Long Term Debt Account 224 22 5.625% Unsecured Senior Note 23 2,288,000 D 24 4.650% Unsecured Senior Note 25 2,208,000 D 26 5.800% Unsecured Senior Note 27 810,000 D 28 5.500% Unsecured Senior Note 29 2,147,500 D 30 6.250% Unsecured Senior Note 31 1,355,000 D 32 6.875% Unsecured Senior Note 33 TOTAL FERC FORM NO. 1 (ED. 12-96) 3,768,432,791 Page 256 50,259,961 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission LONG-TERM DEBT (Account 221, 222, 223 and 224) 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received. 5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were issued. 6. In column (b) show the principal amount of bonds or other long-term debt originally issued. 7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued. 8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount. Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted. 9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as specified by the Uniform System of Accounts. Line No. Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a) Principal Amount Of Debt issued (b) 1 Total expense, Premium or Discount (c) 226,500 D 2 8.750% Unsecured Senior Note 500,000,000 4,301,413 300,000,000 3,096,550 325,000,000 3,321,373 3 275,000 D 4 5.05% Unsecured Senior Note 5 2,022,000 D 6 4.50% Unsecured Senior Note 7 3,074,500 D 8 4.50% Unsecured Senior Note 100,000,000 9 1,148,640 -5,182,000 P 10 4.7% Unsecured Senior Note 250,000,000 11 2,501,050 1,000,000 D 12 3.35% Unsecured Senior Note 250,000,000 13 2,080,950 230,000 D 14 COLI LOANS (Option II Benefits) 27,577,791 15 16 Subtotal 3,202,577,791 38,973,486 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 TOTAL FERC FORM NO. 1 (ED. 12-96) 3,768,432,791 Page 256.1 50,259,961 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) Year/Period of Report 2014/Q4 End of 10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years. 11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium on Debt - Credit. 12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid during year. Give Commission authorization numbers and dates. 13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee and purpose of the pledge. 14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. 15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. 16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued. Nominal Date of Issue (d) Date of Maturity (e) AMORTIZATION PERIOD Date From (f) Date To (g) Outstanding (Total amount outstanding without reduction for amounts held by respondent) (h) Line No. Interest for Year Amount (i) 1 5/25/94 5/01/24 5/25/94 5/01/24 49,400,000 2,321,800 2 9/14/94 9/01/24 9/14/94 9/01/24 65,750,000 3,090,250 3 9/14/94 9/01/24 9/14/94 9/01/24 10/12/94 10/01/29 10/12/94 10/01/29 11/16/98 11/01/33 11/16/98 11/01/33 16,870,000 183,208 6 5/28/09 6/01/34 5/28/09 6/01/34 12,850,000 313,638 7 9/22/09 4/01/38 9/22/09 4/01/38 26,710,000 289,126 8 5/28/09 6/01/34 5/28/09 6/01/34 38,150,000 246,385 9 5/28/09 6/01/34 5/28/09 6/01/34 733,333 10 5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 790,783 11 5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 1,840,000 12 5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 1,840,000 13 6/26/09 5/01/29 6/26/09 5/01/29 35,975,000 784,708 14 6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 260,166 15 6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 554,293 16 6/26/09 5/01/29 6/26/09 5/01/29 640,000 17 6/26/09 5/01/29 6/26/09 5/01/29 640,000 18 14,535,975 19 8,285 4 5 405,705,000 20 21 5/07/03 5/15/33 5/07/03 5/15/33 200,000,000 11,250,000 22 5/07/03 5/15/15 5/07/03 5/15/15 300,000,000 13,950,000 24 6/29/04 6/30/14 6/29/04 6/30/2014 8,700,000 26 08/22/05 9/01/35 8/22/05 9/1/2035 250,000,000 13,750,000 28 8/03/06 8/01/16 8/03/06 8/01/16 250,000,000 15,625,000 30 8/03/06 8/01/36 8/03/06 8/01/36 150,000,000 10,312,500 32 3,308,282,791 182,336,670 33 23 25 27 29 31 FERC FORM NO. 1 (ED. 12-96) Page 257 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) Year/Period of Report 2014/Q4 End of 10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years. 11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium on Debt - Credit. 12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid during year. Give Commission authorization numbers and dates. 13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee and purpose of the pledge. 14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. 15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. 16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued. Nominal Date of Issue (d) Date of Maturity (e) AMORTIZATION PERIOD Date From (f) Date To (g) Outstanding (Total amount outstanding without reduction for amounts held by respondent) (h) Interest for Year Amount (i) Line No. 1 2/26/09 3/01/19 2/26/09 3/01/19 500,000,000 43,750,000 8/25/11 9/01/41 8/25/11 9/01/41 300,000,000 15,150,000 2 3 4 5 1/13/12 4/01/42 1/13/12 4/01/42 325,000,000 14,625,000 6 7 1/13/12 4/01/42 1/13/12 4/01/42 100,000,000 4,500,000 8 9 1/10/14 1/15/44 1/10/14 1/15/44 250,000,000 11,488,889 10 6/18/14 6/15/24 6/18/14 6/15/24 250,000,000 4,699,306 12 11 13 27,577,791 14 15 2,902,577,791 167,800,695 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 3,308,282,791 FERC FORM NO. 1 (ED. 12-96) Page 257.1 182,336,670 33 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 256 Line No.: 1 Column: a Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On February 6, 2013, the ACC issued a financing order in which it, subject to specified parameters and procedures, (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017. Schedule Page: 256.1 Line No.: 14 Column: h The change in the loan balance for the Coli Loan is as follows: Total outstanding balance @ 12/31/13 2014 death repayments 2014 net premiums 2014 net interest Balance outstanding @ 12/31/14 Schedule Page: 256.1 Line No.: 16 $ $ 26,160,250 (345,370) 530,842 1,232,069 27,577,791 Column: i The difference between the total column (i) and the total of Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies is as follows: Total interest in 427 and 430 Less: Navajo ROW - Past Obligation Letter of Credit Fees Other Total long term interest FERC FORM NO. 1 (ED. 12-87) Page 450.1 $ 183,271,590 $ (1,082,301) 168,529 (21,147) 182,336,671 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES 1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. 2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. 3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote. Particulars (Details) Line No. (a) 1 Net Income for the Year (Page 117) Amount (b) 421,220,870 2 3 4 Taxable Income Not Reported on Books 5 Contributions in Aid of Construction 15,839,236 6 Tax Gain/Loss on Sale of Business Property -18,892,856 7 Other Taxable Income Not Reported on Books 9,392,547 8 9 Deductions Recorded on Books Not Deducted for Return 10 Book Depreciation and Amortization 487,258,314 11 Income Tax Per Books 237,360,012 12 Pension and Other Post-Retirement Benefits 26,915,609 13 Other Deductions Recorded on Books Not Deducted for Return 272,933,183 14 Income Recorded on Books Not Included in Return 15 Book Gain/Loss on Sale of Business Property -581,127 16 Mark-to-Market Adjustments 338,636 17 Cash Surrender Value -893,002 18 Other Income Recorded on Books Not Included in Return -1,736,951 19 Deductions on Return Not Charged Against Book Income 20 Tax Depreciation and Amortization -678,695,247 21 Expenditures Capitalized for Book Not Tax -67,596,504 22 Other Deductions on Return Not Charged Against Book Income -259,774,624 23 24 25 26 27 Federal Tax Net Income 443,088,097 28 Show Computation of Tax: 29 ($443,088,097) * 35% 155,080,834 30 31 Tax Attributes Utilized -103,646,301 32 33 Net Current Year Federal Tax Expense 51,434,533 34 35 Other (including 2013 Return-to-Provision) -11,678,876 36 37 Net Federal Tax Expense per Income Statement 39,755,657 38 39 40 41 42 43 44 FERC FORM NO. 1 (ED. 12-96) Page 261 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 FOOTNOTE DATA Schedule Page: 261 Line No.: 13 Column: b Other Deductions Recorded on Books Not Deducted for Return consists of the following: Book Accrued Expenses - End of Year Regulatory Accounting Adjustments Other Total Schedule Page: 261 Line No.: 22 $ 171,018,039 49,625,287 52,289,857 $ 272,933,183 Column: b Other Deductions Recorded on Books Not Deducted for Return consists of the following: Book Accrued Expenses - Beginning of Year Regulatory Accounting Adjustments Contributions to Qualified Decomissioning Fund State Taxes Other Total FERC FORM NO. 1 (ED. 12-87) (157,965,471) (35,436,497) (17,248,943) (20,963,439) (28,160,274) $ (259,774,624) Page 450.1 2014/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR Year/Period of Report 2014/Q4 End of 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts. 2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes. 3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. 4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. Line No. Kind of Tax (See instruction 5) (a) 1 Federal Income BALANCE AT BEGINNING OF YEAR Taxes Accrued Prepaid Taxes (Account 236) (Include in Account 165) (b) (c) 9,827,534 -127,571,503 2 FICA 3 Unemployment 4 Heavy Vehicle Use -43,120 5 Fuel Tax -22,482 6 Subtotal 9,761,932 Taxes Charged During Year (d) 39,755,567 Taxes Paid During Year (e) -91,474,199 50,890,972 50,890,972 293,801 293,801 86,000 80,220 91,026,340 -40,207,273 14,976,691 11,506,543 783,563 761,772 Adjustments (f) 1,933 -127,571,503 7 8 New Mexico: State and Local 9 Real and Personal Property 4,333,402 10 Income 28,184 11 Unemployment 12 Sales 13 Use 21,586 40,355 217,589 235,887 13,540 13,625 16,031,738 12,558,182 179,017,466 176,162,461 14,673,453 11,236,223 17,512,224 259,148,121 259,892,540 21 State and City Use 1,315,452 22,814,236 23,166,045 1,448 22 State and City Tax Reserve 5,999,205 1,086,487 178,539 -930,000 14 Subtotal -10 40,355 4,354,978 28,184 15 16 Arizona: State and Local 17 Real and Personal Property 84,783,158 18 Income -2,992,812 19 Diesel Fuel 20 State and City Sales 23 Unemployment 24 Subtotal 1,629,703 1,629,703 478,369,466 472,265,511 31,146 120,807 121,751 31,146 120,807 121,751 13,493 27,881 27,434 -800 141,459 71,058 13,493 -800 169,340 98,492 132,509,537 -130,536,931 585,717,691 444,836,663 109,610,039 -2,992,812 -928,552 25 26 NV Real and Personal 27 Unemployment 28 Subtotal 29 30 California: State and Local 31 Real and Personal Property 32 Income 33 Unemployement 34 Subtotal 35 36 Utah: State 37 Income 38 Subtotal 39 40 41 TOTAL FERC FORM NO. 1 (ED. 12-96) Page 262 -529,233 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR Year/Period of Report 2014/Q4 End of 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts. 2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes. 3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. 4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. Line No. Kind of Tax (See instruction 5) (a) 1 Texas: State BALANCE AT BEGINNING OF YEAR Taxes Accrued Prepaid Taxes (Account 236) (Include in Account 165) (b) (c) Taxes Charged During Year (d) Taxes Paid During Year (e) Adjustments (f) 2 Income 3 Unemployment 4 Subtotal 5 6 Sales Tax - Palo Verde Lease 7 Payroll - other 8 Sales Tax - Unbilled Revenue 8,737,949 399,319 9 Subtotal 8,737,949 399,319 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 TOTAL FERC FORM NO. 1 (ED. 12-96) -130,536,931 132,509,537 Page 262.1 585,717,691 444,836,663 -529,233 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) Year/Period of Report 2014/Q4 End of 5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying the year in column (a). 6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. 7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. 8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts. 9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax. BALANCE AT END OF YEAR Prepaid Taxes (Taxes accrued (Incl. in Account 165) Account 236) (g) (h) 13,485,795 DISTRIBUTION OF TAXES CHARGED Extraordinary Items Electric (Account 408.1, 409.1) (Account 409.3) (i) (j) 39,109,116 26,580,756 -37,340 Adjustments to Ret. Earnings (Account 439) (k) Other (l) 646,451 1 24,310,216 2 293,801 3 86,000 -24,415 13,424,040 Line No. 4 5 65,689,872 25,336,468 6 7 8 7,803,549 14,976,691 21,791 778,081 9 5,483 3,288 -95 7,828,533 15,754,772 10 40,355 11 217,589 12 13,540 13 276,967 14 15 16 87,638,164 157,309,348 21,708,118 17 444,418 14,481,570 191,883 18 259,148,121 20 22,815,684 21 19 16,767,805 965,091 5,977,153 111,792,631 -851,298 170,939,620 1,007,785 22 1,629,703 23 306,501,294 24 25 30,202 120,807 26 30,202 120,807 28 27 29 30 13,940 27,881 31 69,601 139,306 2,153 32 83,541 167,187 2,153 34 33 35 36 37 38 39 40 142,296,215 FERC FORM NO. 1 (ED. 12-96) 252,672,258 Page 332,516,201 263 41 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) Year/Period of Report 2014/Q4 End of 5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying the year in column (a). 6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. 7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. 8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts. 9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax. BALANCE AT END OF YEAR Prepaid Taxes (Taxes accrued (Incl. in Account 165) Account 236) (g) (h) DISTRIBUTION OF TAXES CHARGED Extraordinary Items Electric (Account 408.1, 409.1) (Account 409.3) (i) (j) Adjustments to Ret. Earnings (Account 439) (k) Other (l) Line No. 1 2 3 4 5 6 7 9,137,268 399,319 8 9,137,268 399,319 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 142,296,215 FERC FORM NO. 1 (ED. 12-96) 252,672,258 Page 332,516,201 263.1 41 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) (2) A Resubmission 04/15/2015 X ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the average period over which the tax credits are amortized. Line No. Account Subdivisions (a) Balance at Beginning of Year (b) Deferred for Year Account No. Amount (d) (c) Allocations to Current Year's Income Account No. Amount (e) (f) Adjustments (g) 1 Electric Utility 2 3% 3 4% 4 7% 5 10% 347,211 255 6 30% 152,013,771 255 32,192,352 420 81,816 420 5,864,308 7 8 TOTAL 152,360,982 32,192,352 9 Other (List separately and show 3%, 4%, 7%, 10% and TOTAL) 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 FERC FORM NO. 1 (ED. 12-89) Page 266 5,946,124 Date of Report Year/Period of Report (Mo, Da, Yr) 2014/Q4 End of Arizona Public Service Company (2) 04/15/2015 X A Resubmission ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Balance at End of Year (h) 265,395 178,341,815 Average Period of Allocation to Income (i) ADJUSTMENT EXPLANATION Line No. 1 2 3 4 5 6 7 8 9 3.2 years 27.8 years 178,607,210 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 FERC FORM NO. 1 (ED. 12-89) Page 267 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 266 Line No.: 8 Column: b $44,075 is associated with transmission investments. Schedule Page: 266 Line No.: 8 Column: h $33,587 is associated with transmission investments. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission OTHER DEFFERED CREDITS (Account 253) 1. Report below the particulars (details) called for concerning other deferred credits. 2. For any deferred credit being amortized, show the period of amortization. 3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes. Description and Other Deferred Credits Line No. (a) 1 Deferred Compensation Balance at Beginning of Year DEBITS 11,382,780 Contra Account (c) 182.3 9,495,156 242, 411.6 4,747,579 232 12,684,545 (b) Amount (d) 5,476,274 Credits Balance at End of Year (e) (f) 5,906,506 2 3 Palo Verde Unit II Rent 4 Levelization (1/2000 to 12/2015) 4,747,577 5 6 Coal Reclamation 198,874,688 4,117,727 190,307,870 7 8 Navajo Retiree Health Care Costs 8,578,528 182.3, 501 594,220 7,984,308 10,008,302 131 5,176,452 1,800,000 6,631,850 5,058,724 143 661,093 658,774 5,056,405 6,000,000 6,000,000 9 10 Legal Reserves 11 12 Construction Advances 13 14 Transmission Termination Agreemnts 426.5 15 16 License Fees 1,959,636 930.2 776,920 1,182,716 165,712 131 80,268 85,444 45,115 131 17 18 Leasehold Improvements 19 20 Escheated Funds 5,760 50,875 21 22 SCE Right of Way 20,231,739 232, 567 33,343,078 232 271,626 19,960,113 23 24 Tolling Agreements 27,170,944 20,469,211 26,641,345 1,922,000 1,922,000 34,973,472 276,477,009 25 26 Coal Severance Surtax Reserve 501 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 TOTAL FERC FORM NO. 1 (ED. 12-94) 299,143,458 57,639,921 Page 269 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 269 Line No.: 12 Column: b 2013 $327,020 minor item reclassified to construction advance FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281) 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property. 2. For other (Specify),include deferrals relating to other income and deductions. CHANGES DURING YEAR Line No. Account Balance at Beginning of Year (a) (b) 1 Accelerated Amortization (Account 281) 2 Electric 3 Defense Facilities 4 Pollution Control Facilities 5 Other (provide details in footnote): 6 7 8 TOTAL Electric (Enter Total of lines 3 thru 7) 9 Gas 10 Defense Facilities 11 Pollution Control Facilities 12 Other (provide details in footnote): 13 14 15 TOTAL Gas (Enter Total of lines 10 thru 14) 16 17 TOTAL (Acct 281) (Total of 8, 15 and 16) 18 Classification of TOTAL 19 Federal Income Tax 20 State Income Tax 21 Local Income Tax NOTES FERC FORM NO. 1 (ED. 12-96) Page 272 Amounts Debited to Account 410.1 (c) Amounts Credited to Account 411.1 (d) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued) 3. Use footnotes as required. CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.2 to Account 411.2 (e) (f) ADJUSTMENTS Debits Account Credited (g) Credits Account Debited (i) Amount (h) Amount (j) Balance at End of Year Line No. (k) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 NOTES (Continued) FERC FORM NO. 1 (ED. 12-96) Page 273 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282) Year/Period of Report 2014/Q4 End of 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization 2. For other (Specify),include deferrals relating to other income and deductions. CHANGES DURING YEAR Line No. Account Balance at Beginning of Year (a) (b) Amounts Debited to Account 410.1 (c) Amounts Credited to Account 411.1 (d) 1 Account 282 2 Electric 2,772,827,677 615,349,221 543,754,530 2,772,827,677 615,349,221 543,754,530 3 Gas 4 5 TOTAL (Enter Total of lines 2 thru 4) 6 7 8 UTP recorded in ADIT for FERC 9 TOTAL Account 282 (Enter Total of lines 5 thru 32,168,978 23,195,903 21,797,166 2,804,996,655 638,545,124 565,551,696 2,312,158,743 533,440,596 441,326,424 492,837,912 105,104,528 124,225,272 10 Classification of TOTAL 11 Federal Income Tax 12 State Income Tax 13 Local Income Tax NOTES FERC FORM NO. 1 (ED. 12-96) Page 274 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued) Year/Period of Report 2014/Q4 End of 3. Use footnotes as required. CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.2 to Account 411.2 (e) (f) ADJUSTMENTS Debits Account Credited (g) Amount (h) Credits Account Debited (i) Amount (j) Balance at End of Year Line No. (k) 1 2,844,422,368 2 3 4 2,844,422,368 5 6 7 33,567,715 8 2,877,990,083 9 10 2,404,272,915 11 473,717,168 12 13 NOTES (Continued) FERC FORM NO. 1 (ED. 12-96) Page 275 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283) Year/Period of Report 2014/Q4 End of 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts recorded in Account 283. 2. For other (Specify),include deferrals relating to other income and deductions. Line No. Balance at Beginning of Year (b) Account (a) CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 (c) (d) 1 Account 283 2 Electric 3 Reg. Assets - AFUDC 43,058,608 16,608,722 11,381,616 4 Reg Assets - Mark to Market 13,343,009 26,467,084 1,622,553 5 Reg Assets - Pension and Other 129,249,784 91,494,857 28,998,039 6 Reg Assets - Other 102,714,644 137,073,629 79,716,722 19,737,000 18,181,918 4,328,181 4,915,890 79,524,793 20,462,214 313,018,935 369,351,003 146,509,325 313,018,935 369,351,003 146,509,325 258,021,509 308,555,828 118,919,382 54,997,426 60,795,175 27,589,943 7 Mark to Market 8 Other 9 TOTAL Electric (Total of lines 3 thru 8) 10 Gas 11 12 13 14 15 16 17 TOTAL Gas (Total of lines 11 thru 16) 18 19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 20 Classification of TOTAL 21 Federal Income Tax 22 State Income Tax 23 Local Income Tax NOTES FERC FORM NO. 1 (ED. 12-96) Page 276 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued) Year/Period of Report 2014/Q4 End of 3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other. 4. Use footnotes as required. CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.2 to Account 411.2 (e) (f) ADJUSTMENTS Debits Account Credited (g) Credits Account Debited (i) Amount (h) Amount (j) Balance at End of Year (k) Line No. 1 2 219 12,673,978 12,673,978 48,285,714 3 38,187,540 4 191,746,602 5 160,071,551 6 20,916,759 7 63,978,469 8 523,186,635 9 10 11 12 13 14 15 16 17 18 12,673,978 523,186,635 19 20 10,587,841 437,070,114 2,086,137 86,116,521 21 22 23 NOTES (Continued) FERC FORM NO. 1 (ED. 12-96) Page 277 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission OTHER REGULATORY LIABILITIES (Account 254) 1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Liabilities being amortized, show period of amortization. Line No. Description and Purpose of Other Regulatory Liabilities (a) 1 PacifiCorp CT Deferred Gain Balance at Begining of Current Quarter/Year DEBITS Account Credited (c) (b) Amount Credits (d) (e) Balance at End of Current Quarter/Year (f) 12,000,000 456 2,000,000 265,888,694 230 44,661,212 74,318,540 295,546,022 41,790,457 518 1,374,007) 26,825,649 69,990,113 82,116,070 150 3,213,216 17,329,121 96,231,975 1,609,200 12,069,000 ( 1,201,200) 75,844,021 10,000,000 2 U-1345-90-269 Amortize through 2019 3 4 Asset Retirement Obligation 5 FERC Order #552 Amortize through 2044 6 7 Spent Nuclear Fuel Storage ( 8 E-01345A-03-0437, E-01345A-05-0816, -0826, 9 -0827 Amortize through 2047 10 11 Income Taxes - Unamortized Investment Tax Credit 12 E-01345A-05-0816,-0826,-0827 13 Amortize through 2043 14 15 Sundance Maintenance 10,459,800 16 E-01345A-05-0816,-0826,-0827 17 18 Income Tax - Change in Rates 77,551,299 190,410.1,411.1 506,078 19 Amortize through 2043 20 21 Amonix Promissory Note 6,161,929 6,161,929 22 23 Renewable Energy Standard 44,213,234 549 117,467,490 119,230,201 45,975,945 24 E-01345A-03-0437,E-01345A-05-0816,-0826, 25 -0827 Amortize through 2017 26 27 Star Center Patent Rights 1,125,393 1,125,393 28 E-01345A-09-0357 29 30 AZ Sun Program 3,808,928 400 7,617,421 5,105,088 8,001,220 190 2,501,320 26,799,709 908 ( 53,837,655) ( 49,302,646) 31,334,718 -120,159,038 199,035,685 899,167,049 1,296,595 31 E-01345A-09-0338 Amortize through 2017 32 33 Excess Deferred Taxes 5,499,900 34 Amortize through 2019 35 36 Demand Side Management 37 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 38 Amortize through 2015 39 40 41 TOTAL FERC FORM NO. 1/3-Q (REV 02-04) 579,972,326 Page 278 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission OTHER REGULATORY LIABILITIES (Account 254) 1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Liabilities being amortized, show period of amortization. Line No. Description and Purpose of Other Regulatory Liabilities (a) Balance at Begining of Current Quarter/Year (b) Balance at End of Current Quarter/Year DEBITS Account Credited (c) 1 Other Postretirement Benefits 228.3 Amount Credits (d) (e) ( 245,249,177) ( 14,333,683) (f) 230,915,494 2,358,956 4,625,605 2,266,649 13,102,784 13,102,784 527,136 551,028 1,200,127 1,200,127 237) 55,356 199,035,685 899,167,049 2 E-01345A-08-0172 3 4 FERC Transmission True Up 400 5 Amortize through 2016 6 7 Removal costs Cholla 8 Amortize through 2033 9 10 Power Supply Adjuster Interest 421 ( 23,892) 11 Amortize through 2015 12 13 Four Corners Coal Reclamation 14 E-013454A-05-0816, -0826, -0827 15 Amortize through 2038 16 17 Minor Items 55,593 ( 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 TOTAL FERC FORM NO. 1/3-Q (REV 02-04) 579,972,326 Page 278.1 -120,159,038 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission ELECTRIC OPERATING REVENUES (Account 400) 1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. 2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. 3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of each month. 4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. 5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Line No. Operating Revenues Year to Date Quarterly/Annual (b) Title of Account (a) Operating Revenues Previous year (no Quarterly) (c) 1 Sales of Electricity 2 (440) Residential Sales 1,639,833,740 1,672,832,847 1,349,585,933 1,353,056,690 187,964,502 181,069,152 21,012,878 21,785,104 182,742 188,950 3,198,579,795 3,228,932,743 258,829,659 186,036,468 3,457,409,454 3,414,969,211 3 (442) Commercial and Industrial Sales 4 Small (or Comm.) (See Instr. 4) 5 Large (or Ind.) (See Instr. 4) 6 (444) Public Street and Highway Lighting 7 (445) Other Sales to Public Authorities 8 (446) Sales to Railroads and Railways 9 (448) Interdepartmental Sales 10 TOTAL Sales to Ultimate Consumers 11 (447) Sales for Resale 12 TOTAL Sales of Electricity 13 (Less) (449.1) Provision for Rate Refunds -4,818,118 14 TOTAL Revenues Net of Prov. for Refunds 3,457,409,454 3,419,787,329 16 (450) Forfeited Discounts 8,113,649 8,794,671 17 (451) Miscellaneous Service Revenues 9,321,356 9,798,300 10,564,649 8,907,350 5,882,123 5,013,209 30,931,241 32,679,141 64,813,018 65,192,671 3,522,222,472 3,484,980,000 15 Other Operating Revenues 18 (453) Sales of Water and Water Power 19 (454) Rent from Electric Property 20 (455) Interdepartmental Rents 21 (456) Other Electric Revenues 22 (456.1) Revenues from Transmission of Electricity of Others 23 (457.1) Regional Control Service Revenues 24 (457.2) Miscellaneous Revenues 25 26 TOTAL Other Operating Revenues 27 TOTAL Electric Operating Revenues FERC FORM NO. 1/3-Q (REV. 12-05) Page 300 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission ELECTRIC OPERATING REVENUES (Account 400) Year/Period of Report 2014/Q4 End of 6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) 7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases. 8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. 9. Include unmetered sales. Provide details of such Sales in a footnote. AVG.NO. CUSTOMERS PER MONTH MEGAWATT HOURS SOLD Year to Date Quarterly/Annual Amount Previous year (no Quarterly) (d) Current Year (no Quarterly) (f) (e) Previous Year (no Quarterly) (g) Line No. 1 12,837,752 13,290,096 1,033,728 1,019,292 2 3 12,337,218 12,449,137 124,460 123,319 4 2,269,263 2,203,023 3,728 3,701 5 137,571 142,483 1,007 991 6 2,729 2,866 156 159 7 8 9 27,584,533 28,087,605 1,163,079 1,147,462 10 5,366,855 3,999,940 55 52 11 32,951,388 32,087,545 1,163,134 1,147,514 12 13 32,951,388 Line 12, column (b) includes $ Line 12, column (d) includes FERC FORM NO. 1/3-Q (REV. 12-05) 32,087,545 2,875,571 15,519 of unbilled revenues. MWH relating to unbilled revenues Page 301 1,163,134 1,147,514 14 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 FOOTNOTE DATA Schedule Page: 300 Line No.: 4 Column: b Basis of classification for small or large commercial and industrial sales is customer's NAICS code. Includes unmetered sales such as traffic lights, bus stop lighting, and public irrigation systems. Schedule Page: 300 Line No.: 4 Column: c Basis of classification for small or large commercial and industrial sales is customer's NAICS code. Includes unmetered sales such as traffic lights, bus stop lighting, and public irrigation systems. Schedule Page: 300 Line No.: 5 Column: b Basis of classification for small or large commercial and industrial sales is customer's NAICS code. Schedule Page: 300 Line No.: 5 Column: c Basis of classification for small or large commercial and industrial sales is customer's NAICS code. Schedule Page: 300 Line No.: 17 Column: b Connection Charges Other Total Schedule Page: 300 $ $ Line No.: 17 Column: c Connection Charges Other Total Schedule Page: 300 $ $ Line No.: 21 Line No.: 21 $ $ 2,629,500 2,000,000 710,904 976,120 727,288 136,363 (1,509,350) (802,409) 50,000 646,001 317,706 5,882,123 Column: c PCS Project PacifiCorp CT Deferred Gain Amortization Facility Charges Fuel Loading Management/Administration Fees FERC FORM NO. 1 (ED. 12-87) 9,717,135 81,165 9,798,300 Column: b PCS Project PacifiCorp CT Deferred Gain Amortization Facility Charges Fuel Loading Management/Administration Fees Participant Station Power Revenue Surepay and Autopay Discount Risk Management Renewable Energy Misc Revenue Effluent Water Rights Fee Other Total Schedule Page: 300 9,186,485 134,871 9,321,356 $ 2,562,734 2,000,000 708,192 942,742 709,658 Page 450.1 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Participant Station Power Revenue Installation of Photovoltaic Facilities Surepay and Autopay Discount Risk Management Other Total FERC FORM NO. 1 (ED. 12-87) $ 143,559 (4,192) (1,458,646) (904,901) 314,063 5,013,209 Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1) 1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below. Line No. Description of Service (a) Balance at End of Quarter 1 (b) Balance at End of Quarter 2 (c) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 TOTAL FERC FORM NO. 1/3-Q (NEW. 12-05) Page 302 Balance at End of Quarter 3 (d) Balance at End of Year (e) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES OF ELECTRICITY BY RATE SCHEDULES Year/Period of Report 2014/Q4 End of 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading. Revenue Average Number KWh of Sales Revenue Per MWh Sold Line Number and Title of Rate schedule KWh Sold Per Customer of Customers No. (a) (b) (c) (e) (f) (d) 1 440 Residential 2 E-12 3,574,709 496,725,563 464,057 7,703 0.1390 3 ET-1 2,325,377 293,844,435 147,684 15,746 0.1264 4 ET-2 4,009,243 511,244,881 278,630 14,389 0.1275 5 ECT-2 2,017,755 230,428,272 88,461 22,810 0.1142 725,466 83,126,121 28,682 25,293 0.1146 7 ET-SP 16,163 2,032,073 1,143 14,141 0.1257 8 EPR-2 1,440 167,601 103 13,981 0.1164 9 EPR-6 145,657 18,535,813 24,846 5,862 0.1273 10 ET-EV 2,869 328,297 122 23,516 0.1144 11 E-47 1,715 533,692 12,820,394 1,637,125,271 16 E-20 38,650 17 E-30 5,029 18 E-32 XS 19 E-32 S 6 ECT-1R 12 Green Power 13 Total Residential 0.3112 158,523 1,033,728 12,402 0.1277 4,855,156 399 96,867 0.1256 1,273,496 4,313 1,166 0.2532 1,377,621 220,514,570 82,871 16,624 0.1601 2,481,263 325,313,570 29,573 83,903 0.1311 20 E-32 M 2,855,862 303,454,541 3,694 773,108 0.1063 21 E-32 L 2,307,573 208,707,641 629 3,668,638 0.0904 3,363 513,024 88 38,216 0.1525 23 E-32 TOU S 33,189 3,987,187 247 134,368 0.1201 24 E-32 TOU M 66,742 6,704,107 67 996,149 0.1004 25 E-32 TOU L 206,624 17,817,008 42 4,919,619 0.0862 37,557 4,571,094 52 722,250 0.1217 14 15 442 Commercial 22 E-32 TOU XS 26 SCHOOL TOU RATE M 30,206 3,351,834 19 1,589,789 0.1110 28 E-34 27 SCHOOL TOU RATE L 424,552 33,574,063 17 24,973,647 0.0791 29 E-35 847,240 59,961,415 19 44,591,579 0.0708 4,710 502,403 5 942,000 0.1067 31 E-47 20,479 8,154,961 32 E-56 497 531,626 1 497,000 1.0697 334,498 33,448,928 1,362 245,593 0.1000 30 E-36 M 33 E-221 0.3982 34 EPR-2 7,906 784,818 25 316,240 0.0993 35 EPR-6 320,301 38,210,730 823 389,187 0.1193 36 Green Power 987,838 37 E-56R 325,243 26,420,709 64 5,081,922 0.0812 38 AG-1 M & L 447,766 34,587,897 143 3,131,231 0.0772 12,428 771,990 1 12,428,000 0.0621 121,110 8,731,317 4 30,277,500 0.0721 27,569,014 15,519 27,584,533 3,195,704,224 2,875,571 3,198,579,795 1,158,187 4,892 1,163,079 23,804 3,172 23,717 0.1159 0.1853 0.1160 39 AG-1 M & L TOU 40 AG-1 XL 41 42 43 TOTAL Billed Total Unbilled Rev.(See Instr. 6) TOTAL FERC FORM NO. 1 (ED. 12-95) Page 304 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES OF ELECTRICITY BY RATE SCHEDULES Year/Period of Report 2014/Q4 End of 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading. Revenue Average Number KWh of Sales Revenue Per MWh Sold Line Number and Title of Rate schedule KWh Sold Per Customer of Customers No. (a) (b) (c) (e) (f) (d) 1 AG-1 XL TOU 2,957,651 2 21,594,000 0.0685 43,188 2 Total Commercial 12,353,597 1,350,689,574 124,460 99,258 0.1093 3 4 442 Industrial and Irrigation 58 17,074 72 806 0.2944 41,221 7,236,900 2,280 18,079 0.1756 7 E-32 S 74,245 10,676,217 813 91,322 0.1438 8 E-32 M 190,922 22,968,162 299 638,535 0.1203 9 E-32 L 431,545 38,465,379 96 4,495,260 0.0891 10 E-32 TOU XS 100 14,883 2 50,000 0.1488 11 E-32 TOU S 992 115,673 6 165,333 0.1166 5 E-30 6 E-32 XS 12 E-32 TOU M 3,364 440,115 3 1,121,333 0.1308 13 E-32 TOU L 47,618 4,622,157 9 5,290,889 0.0971 14 E-34 210,506 15,873,377 8 26,313,250 0.0754 15 E-35 449,836 33,302,323 11 40,894,182 0.0740 16 E-36 80,546 6,939,133 4 20,136,500 0.0862 17 E-47 709 170,013 18 E-221 10,716 1,096,044 96 111,625 19 EPR-6 20,731 2,503,799 21 987,190 0.1208 1,037 147,526 2 518,500 0.1423 607,401 34,087,290 2 303,700,500 0.0561 78,082 7,192,460 4 19,520,500 0.0921 2,249,629 185,868,525 3,728 603,441 0.0826 25 444 Public Street Lighting 142,665 21,838,112 1,008 141,533 0.1531 26 Total Public Street Lighting 142,665 21,838,112 1,008 141,533 0.1531 28 445 Other Public Authorities 2,729 182,742 156 17,494 0.0670 29 Total Other Public Authorities 2,729 182,742 156 17,494 0.0670 20 AG-1 M & L 21 AG-1 XL TOU 22 Special Contracts 23 Total Industrial & Irrigation 0.2398 0.1023 24 27 30 31 Unbilled MWh & Revenue 32 Residential Unbilled 17,358 2,708,469 0.1560 33 Commercial Unbilled -16,379 -1,103,641 0.0674 34 Ind & Irrig. Unbilled 19,634 2,095,977 0.1068 35 Public Str Lighting Unbilled -5,094 -825,234 0.1620 15,519 2,875,571 0.1853 27,569,014 15,519 27,584,533 3,195,704,224 2,875,571 3,198,579,795 36 Other Public Auth Unbilled 37 Total Unbilled Mwh & Revenue 38 39 449.1 Provision for Rate Refunds 40 Residential PRR 41 42 43 TOTAL Billed Total Unbilled Rev.(See Instr. 6) TOTAL FERC FORM NO. 1 (ED. 12-95) Page 304.1 1,158,187 4,892 1,163,079 23,804 3,172 23,717 0.1159 0.1853 0.1160 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES OF ELECTRICITY BY RATE SCHEDULES Year/Period of Report 2014/Q4 End of 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading. Revenue Average Number KWh of Sales Revenue Per MWh Sold Line Number and Title of Rate schedule KWh Sold Per Customer of Customers No. (a) (b) (c) (e) (f) (d) 1 Commercial PRR 2 Industrial & Irrigation PRR 3 Public Street Lighting PRR 4 Sales For Resale - Traditional 5 Other Public Authorities PRR 6 Total Provision for Rate Refunds 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 TOTAL Billed Total Unbilled Rev.(See Instr. 6) TOTAL FERC FORM NO. 1 (ED. 12-95) 27,569,014 15,519 27,584,533 3,195,704,224 2,875,571 3,198,579,795 Page 304.2 1,158,187 4,892 1,163,079 23,804 3,172 23,717 0.1159 0.1853 0.1160 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 FOOTNOTE DATA Schedule Page: 304 Line No.: 16 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 16 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 17 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 17 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 18 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 18 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 19 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 19 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 20 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 20 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 21 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 21 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 22 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 22 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 23 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 23 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 24 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 24 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 25 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 25 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 26 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 26 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 27 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 27 FERC FORM NO. 1 (ED. 12-87) Column: f Page 450.1 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 FOOTNOTE DATA Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 28 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 28 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 29 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 29 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 30 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 30 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 31 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 31 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 32 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 32 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 33 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 33 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 34 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 34 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 35 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 35 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 36 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 36 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 37 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 37 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 38 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 38 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 39 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 39 FERC FORM NO. 1 (ED. 12-87) Column: f Page 450.2 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 FOOTNOTE DATA Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 40 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304 Line No.: 40 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 1 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 1 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 5 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 5 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 6 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 6 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 7 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 7 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 8 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 8 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 9 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 9 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 10 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 10 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 11 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 11 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 12 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 12 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 13 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 13 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 14 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 14 FERC FORM NO. 1 (ED. 12-87) Column: f Page 450.3 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 FOOTNOTE DATA Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 15 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 15 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 16 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 16 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 17 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 17 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 18 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 18 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 19 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 19 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 20 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 20 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 21 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 21 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 22 Column: c Amount in column (c) was adjusted to correct the allocation of revenues related to AG-1 program. Schedule Page: 304.1 Line No.: 22 Column: f Amount in column (f) was adjusted to correct the allocation of revenues related to AG-1 program. FERC FORM NO. 1 (ED. 12-87) Page 450.4 2014/Q4 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. FERC Rate Schedule or Tariff Number (c) 86308 Actual Demand (MW) Average Monthly Billing Average Average Monthly NCP Demand Monthly CP Demand Demand (MW) (d) (e) (f) 0.185 0.185 0.185 (a) 1 Aguila Irrigation District Statistical Classification (b) RQ 2 Buckeye Irrigation District RQ 86306 0.111 0.111 3 City of Williams RQ MRT Vol 1 5.068 5.202 4.153 4 Electrical District No. 3 RQ 89695 90.705 90.705 84.752 5 Electrical District No. 6 RQ 86307 0.019 0.019 0.019 6 Electrical District No. 7 RQ 86304 0.000 0.000 0.000 7 Electrical District No. 8 RQ 86310 3.124 3.124 3.123 8 Harquahala Valley Irrigation District RQ 86309 0.702 0.702 0.702 9 Maricopa County Municipal Water Conser RQ 86058 0.000 0.000 0.000 10 McMullen Valley Irrigiation District RQ 86311 0.589 0.589 0.589 11 Roosevelt Irrigation District RQ 86305 0.112 0.112 0.112 12 Tohono O'Odham Utility Authority RQ 87975 8.020 8.020 6.214 13 Tonopah Irrigation District RQ 86312 0.030 0.030 0.030 14 Town of Wickenburg RQ 85726 0.000 0.000 0.000 Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 Line No. Name of Company or Public Authority (Footnote Affiliations) FERC FORM NO. 1 (ED. 12-90) Page 310 0.111 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. FERC Rate Schedule or Tariff Number (c) MRT Vol 3 (a) 1 Overton Power District #5 Statistical Classification (b) IF 2 Valley Electric Association IF WSPP 3 Arizona Electric Power Cooperative SF WSPP 4 Brookfield Energy Marketing LP SF WSPP 5 California Independent Systems Operator SF MRT Vol 3 6 Cargill Power Markets, LLC SF WSPP 7 Central Arizona Water Conservation Dist SF MRT Vol 3 8 Citigroup Energy Inc. SF MRT Vol 3 9 ConocoPhillips Company SF WSPP 10 Constellation NewEnergy, Inc. SF WSPP 11 Direct Energy Business, LLC SF WSPP 12 EDF Trading North America LLC SF WSPP 13 El Paso Electric Company SF WSPP 14 Exelon Generation Company, LLC SF WSPP Line No. Name of Company or Public Authority (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.1 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. FERC Rate Schedule or Tariff Number (c) WSPP (a) 1 Freeport-McMoRan Copper & Gold Energy Statistical Classification (b) SF 2 Gila River Power, L.P. SF 3 Guzman Power Markets, LLC SF WSPP 4 IBERDROLA Renewables, Inc. SF MRT Vol 3 5 Idaho Power Company SF WSPP 6 Imperial Irrigation District SF WSPP 7 J. Aron & Company SF WSPP 8 JP Morgan Ventures Energy Corporation SF WSPP 9 Los Alamos County SF WSPP Line No. Name of Company or Public Authority (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) MRT Vol 3 10 Los Angeles Dept of Water and Power SF WSPP 11 Macquarie Energy LLC SF MRT Vol 3 12 Morgan Stanley Capital Group, Inc. SF MRT Vol 3 13 Nevada Power Company SF WSPP 14 NextEra Energy Power Marketing, LLC SF WSPP Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.2 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. FERC Rate Schedule or Tariff Number (c) WSPP (a) 1 Noble Americas Energy Solutions LLC Statistical Classification (b) SF 2 PacifiCorp SF MRT Vol 3 3 PacifiCorp Supplemental Coal SF RS # 182 4 Powerex Corp. SF WSPP 5 PPL Energy Plus, LLC SF WSPP 6 Public Service Co of Colorado SF WSPP 7 Public Service Co of New Mexico SF WSPP 8 Rainbow Energy Marketing Corporation SF WSPP 9 Salt River Project SF WSPP 10 Sempra Generation SF WSPP 11 Shell Energy North America (US), L.P. SF MRT Vol 3 12 Sierra Pacific Power Co. SF WSPP 13 Southern California Edison Company SF WSPP 14 Tenaska Power Services Company SF WSPP Line No. Name of Company or Public Authority (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.3 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. FERC Rate Schedule or Tariff Number (c) WSPP (a) 1 TransAlta Energy Marketing, US, Inc. Statistical Classification (b) SF 2 TransCanada Energy Sales, LTD SF WSPP 3 Tri-State Generation and Transmission SF WSPP 4 Tucson Electric Power Co. SF WSPP 5 Twin Eagle Resource Management, LLC SF WSPP 6 UNS Electric, Inc. SF WSPP 7 WAPA, Colorado River Storage Project SF WSPP 8 WAPA, Desert Southwest Region SF WSPP 9 Arizona Electric Power Cooperative OS WSPP 10 California Independent System Operator OS MRT Vol 3 11 Cargill Power Markets, LLC OS WSPP 12 Central Arizona Water Conservation Dist OS MRT Vol 3 13 EDF Trading North America LLC OS WSPP 14 Imperial Irrigation District OS WSPP Line No. Name of Company or Public Authority (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.4 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. FERC Rate Schedule or Tariff Number (c) MRT Vol 3 (a) 1 Morgan Stanley Capital Group, Inc. Statistical Classification (b) OS 2 Nevada Power Company OS WSPP 3 PacifiCorp OS MRT Vol 3 4 PacifiCorp Supplemental Coal OS RS # 182 5 PacifiCorp Supplemental Other OS RS # 182 6 Powerex Corp. OS WSPP 7 Public Service Co of New Mexico OS WSPP 8 Rainbow Energy Marketing Corporation OS WSPP 9 Salt River Project OS WSPP 10 Southwest Reserve Sharing Group OS SRSG1 11 Sempra Generation OS WSPP 12 Tenaska Power Services Company OS WSPP 13 Tucson Electric Power Co. OS WSPP 14 UNS Electric, Inc. OS WSPP Line No. Name of Company or Public Authority (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.5 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. (a) 1 WAPA, Colorado River Storage Project Statistical Classification (b) OS 2 WAPA, Desert Southwest Region OS 3 Transmission Losses AD 4 Change in Estimate AD Line No. Name of Company or Public Authority (Footnote Affiliations) FERC Rate Schedule or Tariff Number (c) WSPP Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) WSPP 5 6 7 8 9 10 11 12 13 14 Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.6 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Sold (g) 1,596 Demand Charges ($) (h) 22,441 REVENUE Energy Charges ($) (i) 55,978 Other Charges ($) (j) 310,483 Line No. Total ($) (h+i+j) (k) 388,902 1 955 13,439 33,655 240,324 287,418 2 34,084 879,992 715,760 39,600 1,635,352 3 34,449,271 4,887,615 39,336,886 4 505,849 169 2,349 5,971 26,330 34,650 5 399,862 399,862 6 26,662 377,828 939,149 1,714,117 3,031,094 7 6,135 85,320 216,164 684,982 986,466 8 409,702 409,702 9 850,025 10 5,148 71,588 181,410 597,027 969 13,631 34,143 393,645 441,419 11 2,392,515 484,635 2,877,150 12 9,225 180,651 193,562 13 159,543 164,414 14 43,480 262 3,686 4,871 625,309 1,475,145 39,033,241 10,528,516 51,036,902 4,741,546 0 199,592,799 8,199,958 207,792,757 5,366,855 1,475,145 238,626,040 18,728,474 258,829,659 FERC FORM NO. 1 (ED. 12-90) Page 311 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Sold REVENUE Energy Charges ($) (i) Demand Charges ($) (h) (g) Other Charges ($) (j) Line No. Total ($) (h+i+j) (k) 339,845 21,206,329 21,206,329 1 61,515 4,306,088 4,306,088 2 52,682 1,971,950 1,971,950 3 64,000 2,799,018 2,799,018 4 1,187,320 48,804,656 48,804,656 5 53,289 2,252,445 2,252,445 6 7,110 233,979 233,979 7 73,206 3,058,407 3,058,407 8 1,600 74,300 74,300 9 356 13,194 13,194 10 27 1,127 1,127 11 170,271 7,114,640 7,114,640 12 24,087 1,111,716 1,111,716 13 130,689 5,571,003 5,571,003 14 625,309 1,475,145 39,033,241 10,528,516 51,036,902 4,741,546 0 199,592,799 8,199,958 207,792,757 5,366,855 1,475,145 238,626,040 18,728,474 258,829,659 FERC FORM NO. 1 (ED. 12-90) Page 311.1 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Sold REVENUE Energy Charges ($) (i) Demand Charges ($) (h) (g) Other Charges ($) (j) Line No. Total ($) (h+i+j) (k) 196 8,712 8,712 1 69,779 2,866,953 2,866,953 2 11,292 451,835 451,835 3 60,000 3,113,146 3,113,146 4 393 7,963 7,963 5 53,945 2,237,084 2,237,084 6 212,800 8,866,928 8,866,928 7 3,240 286,975 286,975 8 325 16,323 16,323 9 34,059 1,426,468 1,426,468 10 57,601 2,287,784 2,287,784 11 619,349 21,992,476 21,992,476 12 14,760 631,939 631,939 13 130 4,515 4,515 14 625,309 1,475,145 39,033,241 10,528,516 51,036,902 4,741,546 0 199,592,799 8,199,958 207,792,757 5,366,855 1,475,145 238,626,040 18,728,474 258,829,659 FERC FORM NO. 1 (ED. 12-90) Page 311.2 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Sold REVENUE Energy Charges ($) (i) Demand Charges ($) (h) (g) Other Charges ($) (j) Line No. Total ($) (h+i+j) (k) 31 1,380 1,380 1 152,206 6,299,093 6,299,093 2 240,643 240,643 3 75,922 2,727,039 2,727,039 4 4,334 304,952 304,952 5 3,923 165,635 165,635 6 96,513 4,081,847 4,081,847 7 20,026 1,302,494 1,302,494 8 115,832 4,324,395 4,324,395 9 64,357 2,222,076 2,222,076 10 125,854 5,895,051 5,895,051 11 360 10,800 10,800 12 67,801 2,420,306 2,420,306 13 57,514 2,327,600 2,327,600 14 625,309 1,475,145 39,033,241 10,528,516 51,036,902 4,741,546 0 199,592,799 8,199,958 207,792,757 5,366,855 1,475,145 238,626,040 18,728,474 258,829,659 FERC FORM NO. 1 (ED. 12-90) Page 311.3 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Sold REVENUE Energy Charges ($) (i) Demand Charges ($) (h) (g) Other Charges ($) (j) Line No. Total ($) (h+i+j) (k) 174,979 6,692,904 6,692,904 1 4,800 183,900 183,900 2 17,698 689,477 689,477 3 185,642 7,167,610 7,167,610 4 8,607 390,012 390,012 5 15,549 661,008 661,008 6 82,571 3,663,357 3,663,357 7 3,404 153,465 153,465 8 1,271 23,693 23,693 9 13,191 400,171 400,171 10 410 7,530 7,530 11 2,080 103,200 103,200 12 500 10,400 10,400 13 235 6,125 6,125 14 625,309 1,475,145 39,033,241 10,528,516 51,036,902 4,741,546 0 199,592,799 8,199,958 207,792,757 5,366,855 1,475,145 238,626,040 18,728,474 258,829,659 FERC FORM NO. 1 (ED. 12-90) Page 311.4 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Sold REVENUE Energy Charges ($) (i) Demand Charges ($) (h) (g) Other Charges ($) (j) Line No. Total ($) (h+i+j) (k) 600 8,450 8,450 1 8,636 154,820 154,820 2 351 21,288 21,288 3 8,750 261,931 261,931 4 95,514 3,354,398 3,354,398 5 4,915 71,950 71,950 6 825 14,525 14,525 7 8 150 2,250 2,250 3,725 63,450 63,450 9 126,938 10 200 2,500 2,500 11 9,166 334,296 334,296 12 5,240 101,395 101,395 13 150 3,110 3,110 14 3,678 126,938 625,309 1,475,145 39,033,241 10,528,516 51,036,902 4,741,546 0 199,592,799 8,199,958 207,792,757 5,366,855 1,475,145 238,626,040 18,728,474 258,829,659 FERC FORM NO. 1 (ED. 12-90) Page 311.5 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Sold REVENUE Energy Charges ($) (i) Demand Charges ($) (h) (g) Other Charges ($) (j) 100 2,500 70 1,820 Line No. Total ($) (h+i+j) (k) 2,500 1 1,820 2 7,767,262 7,767,262 3 305,758 305,758 4 5 6 7 8 9 10 11 12 13 14 625,309 1,475,145 39,033,241 10,528,516 51,036,902 4,741,546 0 199,592,799 8,199,958 207,792,757 5,366,855 1,475,145 238,626,040 18,728,474 258,829,659 FERC FORM NO. 1 (ED. 12-90) Page 311.6 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 310 Line No.: 1 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 2 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 3 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 4 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 5 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 6 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 7 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 8 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 9 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 10 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 11 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 12 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 13 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310 Line No.: 14 Column: j Administrative Costs and Pass-through Transmission Costs Schedule Page: 310.4 Line No.: 9 Column: b Represents NonFirm Schedule Page: 310.4 Line No.: 10 Column: b Line No.: 11 Column: b Line No.: 12 Column: b Line No.: 13 Column: b Line No.: 14 Column: b Represents NonFirm Schedule Page: 310.4 Represents NonFirm Schedule Page: 310.4 Represents NonFirm Schedule Page: 310.4 Represents NonFirm Schedule Page: 310.4 Represents NonFirm Schedule Page: 310.5 Line No.: 1 Column: b Line No.: 2 Column: b Line No.: 3 Column: b Line No.: 4 Column: b Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.5 FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Represents NonFirm Schedule Page: 310.5 Line No.: 5 Column: b Line No.: 6 Column: b Line No.: 7 Column: b Line No.: 8 Column: b Line No.: 9 Column: b Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.5 Line No.: 10 Column: b Line No.: 10 Column: c Represents NonFirm Schedule Page: 310.5 Rates are set per the Southwest Reserve Sharing Group participation agreement. Schedule Page: 310.5 Line No.: 10 Column: j Emergency Assist Exempt Schedule Page: 310.5 Line No.: 11 Column: b Line No.: 12 Column: b Line No.: 13 Column: b Line No.: 14 Column: b Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.5 Represents NonFirm Schedule Page: 310.6 Line No.: 1 Column: b Line No.: 2 Column: b Line No.: 3 Column: b Represents NonFirm Schedule Page: 310.6 Represents NonFirm Schedule Page: 310.6 Adjustment for transmission losses. Schedule Page: 310.6 Line No.: 3 Column: j Line No.: 4 Column: a Transmission losses. Schedule Page: 310.6 The amounts shown on pages 310 and 311are actual amounts sold to companies during the reporting period. The change in estimate amount represents various timing differences between the accrued amounts for sales for resale compared to the actual amount. Schedule Page: 310.6 Line No.: 4 Column: b The amounts shown on pages 310 and 311are actual amounts sold to companies during the reporting period. The change in estimate amount represents various timing differences between the accrued amounts for sales for resale compared to the actual amount. Schedule Page: 310.6 Line No.: 4 Column: j Change in estimate between accrual and actual. FERC FORM NO. 1 (ED. 12-87) Page 450.2 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission ELECTRIC OPERATION AND MAINTENANCE EXPENSES If the amount for previous year is not derived from previously reported figures, explain in footnote. Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 Account (a) 1. POWER PRODUCTION EXPENSES A. Steam Power Generation Operation (500) Operation Supervision and Engineering (501) Fuel (502) Steam Expenses (503) Steam from Other Sources (Less) (504) Steam Transferred-Cr. (505) Electric Expenses (506) Miscellaneous Steam Power Expenses (507) Rents (509) Allowances TOTAL Operation (Enter Total of Lines 4 thru 12) Maintenance (510) Maintenance Supervision and Engineering (511) Maintenance of Structures (512) Maintenance of Boiler Plant (513) Maintenance of Electric Plant (514) Maintenance of Miscellaneous Steam Plant TOTAL Maintenance (Enter Total of Lines 15 thru 19) TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) B. Nuclear Power Generation Operation (517) Operation Supervision and Engineering (518) Fuel (519) Coolants and Water (520) Steam Expenses (521) Steam from Other Sources (Less) (522) Steam Transferred-Cr. (523) Electric Expenses (524) Miscellaneous Nuclear Power Expenses (525) Rents TOTAL Operation (Enter Total of lines 24 thru 32) Maintenance (528) Maintenance Supervision and Engineering (529) Maintenance of Structures (530) Maintenance of Reactor Plant Equipment (531) Maintenance of Electric Plant (532) Maintenance of Miscellaneous Nuclear Plant TOTAL Maintenance (Enter Total of lines 35 thru 39) TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) C. Hydraulic Power Generation Operation (535) Operation Supervision and Engineering (536) Water for Power (537) Hydraulic Expenses (538) Electric Expenses (539) Miscellaneous Hydraulic Power Generation Expenses (540) Rents TOTAL Operation (Enter Total of Lines 44 thru 49) C. Hydraulic Power Generation (Continued) Maintenance (541) Mainentance Supervision and Engineering (542) Maintenance of Structures (543) Maintenance of Reservoirs, Dams, and Waterways (544) Maintenance of Electric Plant (545) Maintenance of Miscellaneous Hydraulic Plant TOTAL Maintenance (Enter Total of lines 53 thru 57) TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) FERC FORM NO. 1 (ED. 12-93) Page 320 Amount for Current Year (b) Amount for Previous Year (c) 13,091,699 313,774,272 28,447,926 12,631,574 247,451,505 24,944,236 5,401,512 13,164,889 1,344,400 3,880,172 379,104,870 5,579,013 22,323,309 716,482 1,460,372 315,106,491 7,972,993 3,799,286 51,427,942 14,168,312 15,575,593 92,944,126 472,048,996 7,021,350 2,572,922 30,242,922 9,397,960 10,702,390 59,937,544 375,044,035 25,890,446 83,733,824 12,317,679 9,759,065 23,128,726 86,569,367 11,609,010 9,467,875 8,606,521 33,647,188 45,367,801 219,322,524 9,286,901 32,253,498 45,467,274 217,782,651 8,092,140 2,377,507 12,504,993 15,826,106 3,671,813 42,472,559 261,795,083 7,243,234 1,845,258 14,096,339 13,359,515 4,048,865 40,593,211 258,375,862 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) If the amount for previous year is not derived from previously reported figures, explain in footnote. Line No. 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 Account Amount for Current Year (b) (a) D. Other Power Generation Operation (546) Operation Supervision and Engineering (547) Fuel (548) Generation Expenses (549) Miscellaneous Other Power Generation Expenses (550) Rents TOTAL Operation (Enter Total of lines 62 thru 66) Maintenance (551) Maintenance Supervision and Engineering (552) Maintenance of Structures (553) Maintenance of Generating and Electric Plant (554) Maintenance of Miscellaneous Other Power Generation Plant TOTAL Maintenance (Enter Total of lines 69 thru 72) TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) E. Other Power Supply Expenses (555) Purchased Power (556) System Control and Load Dispatching (557) Other Expenses TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 2. TRANSMISSION EXPENSES Operation (560) Operation Supervision and Engineering (561.1) Load Dispatch-Reliability (561.2) Load Dispatch-Monitor and Operate Transmission System (561.3) Load Dispatch-Transmission Service and Scheduling (561.4) Scheduling, System Control and Dispatch Services (561.5) Reliability, Planning and Standards Development (561.6) Transmission Service Studies (561.7) Generation Interconnection Studies (561.8) Reliability, Planning and Standards Development Services (562) Station Expenses (563) Overhead Lines Expenses (564) Underground Lines Expenses (565) Transmission of Electricity by Others (566) Miscellaneous Transmission Expenses (567) Rents TOTAL Operation (Enter Total of lines 83 thru 98) Maintenance (568) Maintenance Supervision and Engineering (569) Maintenance of Structures (569.1) Maintenance of Computer Hardware (569.2) Maintenance of Computer Software (569.3) Maintenance of Communication Equipment (569.4) Maintenance of Miscellaneous Regional Transmission Plant (570) Maintenance of Station Equipment (571) Maintenance of Overhead Lines (572) Maintenance of Underground Lines (573) Maintenance of Miscellaneous Transmission Plant TOTAL Maintenance (Total of lines 101 thru 110) TOTAL Transmission Expenses (Total of lines 99 and 111) FERC FORM NO. 1 (ED. 12-93) Page 321 Amount for Previous Year (c) 4,672,333 361,678,254 7,841,540 55,181,306 598,483 429,971,916 4,234,383 368,768,134 8,261,518 70,991,693 327,757 452,583,485 357,661 800,851 27,426,301 4,971,094 33,555,907 463,527,823 261,979 1,624,429 24,166,745 6,989,820 33,042,973 485,626,458 422,679,819 -2,913,482 3,080,675 422,847,012 1,620,218,914 404,490,137 -2,589,094 3,072,890 404,973,933 1,524,020,288 3,156,313 2,037,248 2,347,786 2,082,930 760,826 2,012,881 1,130,645 144,238 148,682 1,956,535 1,597,841 2,102,625 81,810 27,191,422 7,557,285 7,498,643 59,770,462 2,280,987 2,225,078 758,409 1,895,624 1,072,151 249,693 246,745 1,895,117 1,347,318 2,421,477 92,986 20,531,524 7,713,552 7,438,771 52,206,680 569,389 709,655 440,427 649,485 164,443 157,886 5,115,203 12,980,510 308,883 19,364 19,867,447 79,637,909 4,578,863 13,887,442 9,456 138,013 19,861,572 72,068,252 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Year/Period of Report 2014/Q4 End of If the amount for previous year is not derived from previously reported figures, explain in footnote. Line No. 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 Account Amount for Current Year (b) (a) 3. REGIONAL MARKET EXPENSES Operation (575.1) Operation Supervision (575.2) Day-Ahead and Real-Time Market Facilitation (575.3) Transmission Rights Market Facilitation (575.4) Capacity Market Facilitation (575.5) Ancillary Services Market Facilitation (575.6) Market Monitoring and Compliance (575.7) Market Facilitation, Monitoring and Compliance Services (575.8) Rents Total Operation (Lines 115 thru 122) Maintenance (576.1) Maintenance of Structures and Improvements (576.2) Maintenance of Computer Hardware (576.3) Maintenance of Computer Software (576.4) Maintenance of Communication Equipment (576.5) Maintenance of Miscellaneous Market Operation Plant Total Maintenance (Lines 125 thru 129) TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 4. DISTRIBUTION EXPENSES Operation (580) Operation Supervision and Engineering (581) Load Dispatching (582) Station Expenses (583) Overhead Line Expenses (584) Underground Line Expenses (585) Street Lighting and Signal System Expenses (586) Meter Expenses (587) Customer Installations Expenses (588) Miscellaneous Expenses (589) Rents TOTAL Operation (Enter Total of lines 134 thru 143) Maintenance (590) Maintenance Supervision and Engineering (591) Maintenance of Structures (592) Maintenance of Station Equipment (593) Maintenance of Overhead Lines (594) Maintenance of Underground Lines (595) Maintenance of Line Transformers (596) Maintenance of Street Lighting and Signal Systems (597) Maintenance of Meters (598) Maintenance of Miscellaneous Distribution Plant TOTAL Maintenance (Total of lines 146 thru 154) TOTAL Distribution Expenses (Total of lines 144 and 155) 5. CUSTOMER ACCOUNTS EXPENSES Operation (901) Supervision (902) Meter Reading Expenses (903) Customer Records and Collection Expenses (904) Uncollectible Accounts (905) Miscellaneous Customer Accounts Expenses TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) FERC FORM NO. 1 (ED. 12-93) Page 322 Amount for Previous Year (c) 4,841,222 1,880,305 1,533,751 1,955,505 1,707,195 22,141 5,537,027 -742,895 34,068,083 735,247 51,537,581 4,707,368 1,174,963 1,346,050 2,212,361 2,470,601 39,317 6,638,518 -57,934 34,808,960 726,877 54,067,081 3,198,813 1,202,145 2,085,061 18,584,504 9,234,082 2,422,117 727,857 2,491,880 857,131 2,024,999 18,754,819 10,884,620 2,920,782 125,815 3,236,446 40,691,025 92,228,606 4,270,784 42,330,830 96,397,911 2,263,316 3,086,747 42,902,342 3,942,074 349,460 52,543,939 2,231,297 4,657,476 40,234,409 4,922,865 551,274 52,597,321 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Year/Period of Report 2014/Q4 End of If the amount for previous year is not derived from previously reported figures, explain in footnote. Line No. 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180 181 182 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 Account (a) 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES Operation (907) Supervision (908) Customer Assistance Expenses (909) Informational and Instructional Expenses (910) Miscellaneous Customer Service and Informational Expenses TOTAL Customer Service and Information Expenses (Total 167 thru 170) 7. SALES EXPENSES Operation (911) Supervision (912) Demonstrating and Selling Expenses (913) Advertising Expenses (916) Miscellaneous Sales Expenses TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 8. ADMINISTRATIVE AND GENERAL EXPENSES Operation (920) Administrative and General Salaries (921) Office Supplies and Expenses (Less) (922) Administrative Expenses Transferred-Credit (923) Outside Services Employed (924) Property Insurance (925) Injuries and Damages (926) Employee Pensions and Benefits (927) Franchise Requirements (928) Regulatory Commission Expenses (929) (Less) Duplicate Charges-Cr. (930.1) General Advertising Expenses (930.2) Miscellaneous General Expenses (931) Rents TOTAL Operation (Enter Total of lines 181 thru 193) Maintenance (935) Maintenance of General Plant TOTAL Administrative & General Expenses (Total of lines 194 and 196) TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) FERC FORM NO. 1 (ED. 12-93) Page 323 Amount for Current Year (b) Amount for Previous Year (c) 573,659 59,068,309 279,125 239,041 60,160,134 432,063 75,819,851 353,550 1,117,273 77,722,737 5,707,899 5,389,397 4,266,430 9,974,329 3,942,759 9,332,156 96,813,137 10,138,062 22,370,000 25,038,368 5,438,796 8,907,704 75,334,711 96,903,406 17,895,089 23,360,000 22,931,512 5,597,748 10,369,544 105,682,133 17,228,362 16,440,636 8,390,441 -51,466,697 7,062,721 180,515,605 5,369,001 -61,138,467 7,855,210 204,545,812 11,601,954 192,117,559 2,106,881,390 9,247,670 213,793,482 2,045,932,147 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) FERC Rate Schedule or Tariff Number (c) Average Monthly Billing Demand (MW) (d) 1 Dynegy Arlington - Tolling Agreement RQ 178,987 2 Gila River Power - Tolling Agreement RQ 120,773 Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) 3 Salt River Project RQ 11,072 4 CE Turbo LLC LF N/A N/A N/A 5 Shell Energy North America (US), L.P. LF N/A N/A N/A 6 WAPA, Desert Southwest Region LF N/A N/A N/A 7 Ajo Improvement Co. LF N/A N/A N/A 8 Co-Generation LF N/A N/A N/A 9 Electrical District #5 LF N/A N/A N/A 10 Net Inadvertent LF N/A N/A N/A 11 Citigroup Energy Inc. IF N/A N/A N/A 12 Macquarie Energy LLC IF N/A N/A N/A 13 Morgan Stanley Capital Group, Inc. IF N/A N/A N/A 14 AG-1 Contracts SF N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) FERC Rate Schedule or Tariff Number (c) Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) 1 Arizona Electric Power Cooperative SF N/A N/A N/A 2 Brookfield Energy Marketing LP SF N/A N/A N/A 3 California Independent System Operator SF N/A N/A N/A 4 California Independent System Operator SF N/A N/A N/A 5 Cargill Power Markets, LLC SF N/A N/A N/A 6 Central Arizona Water Conservation Dit SF N/A N/A N/A 7 EDF Trading North America LLC SF N/A N/A N/A 8 El Paso Electric Company SF N/A N/A N/A 9 Exelon Generation Company, LLC SF N/A N/A N/A 10 Gila River Power, LLC SF N/A N/A N/A 11 Guzman Power Markets, LLC SF N/A N/A N/A 12 IBERDROLA Renewables, Inc SF N/A N/A N/A 13 Idaho Power Company SF N/A N/A N/A 14 Imperial Irrigation District SF N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.1 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) FERC Rate Schedule or Tariff Number (c) Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) 1 J. Aron & Company SF N/A N/A N/A 2 JP Morgan Ventures Energy Corporation SF N/A N/A N/A 3 Los Angeles Dept of Water & Power SF N/A N/A N/A 4 Macquarie Energy LLC SF N/A N/A N/A 5 Morgan Stanley Capital Group, Inc. SF N/A N/A N/A 6 Nevada Power Company SF N/A N/A N/A 7 Overton Power District #5 SF N/A N/A N/A 8 PacifiCorp SF N/A N/A N/A 9 Portland General Electric Co. SF N/A N/A N/A 10 Powerex Corp. SF N/A N/A N/A 11 PPL Energy Plus, LLC SF N/A N/A N/A 12 Public Service Co of Colorado SF N/A N/A N/A 13 Public Service Co of New Mexico SF N/A N/A N/A 14 Rainbow Energy Marketing Corporation SF N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.2 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) FERC Rate Schedule or Tariff Number (c) Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) 1 Salt River Project SF N/A N/A N/A 2 Sempra Generation SF N/A N/A N/A 3 Shell Energy North America (US), L.P. SF N/A N/A N/A 4 Sierra Pacific Power Co. SF N/A N/A N/A 5 Southern California Edison SF N/A N/A N/A 6 Tenaska Power Service Company SF N/A N/A N/A 7 TransAlta Energy Marketing, US, Inc. SF N/A N/A N/A 8 Tri-State Generation and Transmissio SF N/A N/A N/A 9 Tucson Electric Power Co SF N/A N/A N/A 10 UNS Electric, Inc. SF N/A N/A N/A 11 Valley Electric Association, Inc. SF N/A N/A N/A 12 WAPA, Colorado River Storage Project SF N/A N/A N/A 13 WAPA, Desert Southwest Region SF N/A N/A N/A 14 Aragonne Wind, LLC LU N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.3 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) FERC Rate Schedule or Tariff Number (c) Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) 1 Arizona Solar One, LLC LU N/A N/A N/A 2 Desert Sky Solar LLC LU N/A N/A N/A 3 Glendale Energy LLC LU N/A N/A N/A 4 High Lonesome Wind Ranch, LLC LU N/A N/A N/A 5 Novo BioPower LLC LU N/A N/A N/A 6 Perrin Ranch Wind LLC LU N/A N/A N/A 7 RE Ajo 1 LLC LU N/A N/A N/A 8 RE Bagdad Solar 1 LLC LU N/A N/A N/A 9 RE Gillespie 1, LLC LU N/A N/A N/A 10 SunE AZ 1 LLC LU N/A N/A N/A 11 SunE AZ 2 LLC LU N/A N/A N/A 12 Waste Management Renewable Energy, LLC LU N/A N/A N/A 13 Aguila Irrigation District EX 141 N/A N/A N/A 14 Buckeye Water Conservation & Drainage EX 155 N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.4 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) FERC Rate Schedule or Tariff Number (c) Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) 1 City of Azusa Exchange EX N/A N/A N/A 2 Electric District #6 EX 126 N/A N/A N/A 3 Electric District #7 EX 128 N/A N/A N/A 4 Electric District #8 EX 140 N/A N/A N/A 5 Harquahala Valley Power District EX 153 N/A N/A N/A 6 Maricopa City Municipal Water Conservt EX 168 N/A N/A N/A 7 McMullen Valley Water Conservt Dist EX 142 N/A N/A N/A 8 PacifiCorp Exchange EX 182 N/A N/A N/A 9 Roosevelt Irrigation District EX 158 N/A N/A N/A 10 Tonopah Irrigation District EX 143 N/A N/A N/A 11 AG-1 Contracts OS N/A N/A N/A 12 Arizona Electric Power Cooperative OS N/A N/A N/A 13 Banked Energy OS N/A N/A N/A 14 California Independent System Operator OS N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.5 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) FERC Rate Schedule or Tariff Number (c) Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) 1 Central Arizona Water Conservation Dit OS N/A N/A N/A 2 EDF Trading North America LLC OS N/A N/A N/A 3 Gila River Power, LLC OS N/A N/A N/A 4 Guzman Power Markets, LLC OS N/A N/A N/A 5 IBERDROLA Renewables, Inc OS N/A N/A N/A 6 Los Angeles Dept of Water & Power OS N/A N/A N/A 7 Macquarie Energy LLC OS N/A N/A N/A 8 Morgan Stanley Capital Group, Inc. OS N/A N/A N/A 9 Nevada Power Company OS N/A N/A N/A 10 Options and Hedges OS N/A N/A N/A 11 PacifiCorp OS N/A N/A N/A 12 Power Supply Adjuster OS N/A N/A N/A 13 Powerex Corp. OS N/A N/A N/A 14 Public Service Co of New Mexico OS N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.6 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) FERC Rate Schedule or Tariff Number (c) Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) 1 Salt River Project OS N/A N/A N/A 2 San Diego Gas & Electric Co OS N/A N/A N/A 3 SFAS 133 OS N/A N/A N/A 4 Southern California Edison OS N/A N/A N/A 5 Southwest Reserve Sharing Group OS N/A N/A N/A 6 Tenaska Power Service Company OS N/A N/A N/A 7 TransAlta Energy Marketing, US, Inc. OS N/A N/A N/A 8 Twin Eagle Resource Management, LLC OS N/A N/A N/A 9 WAPA, Desert Southwest Region OS N/A N/A N/A 10 Change in Estimate AD N/A N/A N/A 11 Various counterparties - prior yrs adt AD N/A N/A N/A 12 13 14 Total FERC FORM NO. 1 (ED. 12-90) Page 326.7 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) 1,073,924 59,089,200 1,449,281 37,819,068 179,108 1,800,000 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 3,484,233 7,491,932 Total (j+k+l) of Settlement ($) (m) Line No. 59,089,200 1 41,303,301 2 9,291,932 3 49,734 3,540,589 3,540,589 4 164,800 6,853,171 6,853,171 5 12 432,952 432,952 6 7 23 364 8 1,251 9 10 3,231 748,069 43,162,454 43,162,454 11 61,500 3,751,500 3,751,500 12 15 994 994 13 1,186,046 44,135,883 44,135,883 14 7,239,997 823,724 FERC FORM NO. 1 (ED. 12-90) 945,331 98,708,268 Page 327 288,733,758 35,237,793 422,679,819 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) MegaWatt Hours Purchased (g) Demand Charges ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 4,054 186,394 5 125 4,072,318 Total (j+k+l) of Settlement ($) (m) Line No. 186,394 1 125 2 4,072,318 3 138,013 4,731,432 4,731,432 4 3,804 104,825 104,825 5 375 8,925 8,925 6 1,542,944 7 31,223 1,542,944 7,029 230,695 230,695 8 3,213 139,266 139,266 9 14,604 -454,485 -454,485 10 1,966 89,855 89,855 11 1,200 46,500 46,500 12 6,120 152,680 152,680 13 2,430 1,200 1,200 14 7,239,997 823,724 FERC FORM NO. 1 (ED. 12-90) 945,331 98,708,268 Page 327.1 288,733,758 35,237,793 422,679,819 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) 2,000 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 179,600 Total (j+k+l) of Settlement ($) (m) Line No. 179,600 1 2 842 39,892 39,892 6,363 425,056 425,056 3 1,529 35,964 35,964 4 5,402 218,159 218,159 5 37,568 1,987,578 1,987,578 6 285 17,747 17,747 7 87,635 3,222,582 3,222,582 8 600 20,200 20,200 9 20,352 1,193,455 1,193,455 10 8,664 208,164 208,164 11 439 22,941 22,941 12 10,153 353,242 353,242 13 36,497 1,038,017 1,038,017 14 7,239,997 823,724 FERC FORM NO. 1 (ED. 12-90) 945,331 98,708,268 Page 327.2 288,733,758 35,237,793 422,679,819 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) 24,721 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 1,393,046 Total (j+k+l) of Settlement ($) (m) 1,393,046 Line No. 1 3,228 139,239 139,239 2 12,523 468,404 468,404 3 65 2,990 2,990 4 1,334 48,894 48,894 5 3,338 102,610 102,610 6 13,398 518,052 518,052 7 1,540 55,722 55,722 8 3,533 126,041 126,041 9 170 4,595 4,595 10 162 11,130 11,130 11 985 42,323 42,323 12 187 2,915 2,915 13 263,999 15,814,819 15,814,819 14 7,239,997 823,724 FERC FORM NO. 1 (ED. 12-90) 945,331 98,708,268 Page 327.3 288,733,758 35,237,793 422,679,819 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) 603,568 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 75,952,032 Total (j+k+l) of Settlement ($) (m) 75,952,032 Line No. 1 40,080 3,432,937 3,432,937 2 16,585 1,384,075 1,384,075 3 276,235 14,191,760 14,191,760 4 5 93,250 8,419,142 8,419,142 208,842 17,594,939 17,594,939 6 10,221 1,312,362 1,312,362 7 35,371 5,106,026 5,106,026 8 44,653 4,260,239 4,260,239 9 26,604 2,606,857 2,606,857 10 37,668 3,074,003 3,074,003 11 23,833 1,920,463 1,920,463 12 7,239,997 3,066 10,048 13 2,138 4,244 14 823,724 945,331 FERC FORM NO. 1 (ED. 12-90) 98,708,268 Page 327.4 288,733,758 35,237,793 422,679,819 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) 203,311 Demand Charges ($) (j) 293,996 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) -2,383,955 Total (j+k+l) of Settlement ($) (m) -2,383,955 Line No. 1 479 501 2 5,427 8,751 3 7,883 15,790 4 7,433 12,152 5 7,335 7,943 6 5,920 9,928 7 571,431 566,750 4,561 8,387 4,740 6,841 521,959 521,959 8 9 10 39,149 1,309,496 1,309,496 11 800 32,500 32,500 12 -4,802,493 -4,802,493 13 3,097 190,320 931,049 1,121,369 14 288,733,758 35,237,793 422,679,819 7,239,997 823,724 FERC FORM NO. 1 (ED. 12-90) 945,331 98,708,268 Page 327.5 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) 849 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 24,838 Total (j+k+l) of Settlement ($) (m) 24,838 Line No. 1 30,578 1,709,840 1,709,840 2 4,936 1,384,075 1,384,075 3 600 41,400 41,400 4 5 800 31,200 31,200 2,364 148,760 148,760 6 7 800 31,120 31,120 2,345 131,735 131,735 8 2,943 192,500 192,500 9 16,121,860 10 5,729 296,412 16,121,860 14,753,209 296,412 11 14,753,209 12 4,212 293,319 293,319 13 600 63,000 63,000 14 7,239,997 823,724 FERC FORM NO. 1 (ED. 12-90) 945,331 98,708,268 Page 327.6 288,733,758 35,237,793 422,679,819 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 3,625 258,475 15,459 795,427 258,475 -1,205,240 5,417 Total (j+k+l) of Settlement ($) (m) 1,773 Line No. 1 795,427 2 -1,205,240 3 1,773 4 187,064 5 9,057 224,062 224,062 6 825 56,775 56,775 7 3,017 187,064 67 1,072 1,072 8 6,912 279,612 279,612 9 1,885,548 1,885,548 10 -189,755 -189,755 11 12 13 14 7,239,997 823,724 FERC FORM NO. 1 (ED. 12-90) 945,331 98,708,268 Page 327.7 288,733,758 35,237,793 422,679,819 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 326 Line No.: 2 Column: l Line No.: 3 Column: a Administrative Costs Schedule Page: 326 Eastern Area Schedule Page: 326.1 Line No.: 3 Column: l Control Area Charges such as Imbalances, Scheduling, System Control, and Dispatch, and Other Fees. Schedule Page: 326.5 Line No.: 11 Column: b Line No.: 12 Column: b Line No.: 13 Column: b Line No.: 13 Column: l Represents nonfirm Schedule Page: 326.5 Represents nonfirm Schedule Page: 326.5 Represents nonfirm Schedule Page: 326.5 Value of Energy owed to other utilities. Schedule Page: 326.5 Line No.: 14 Column: b Line No.: 14 Column: l Represents nonfirm Schedule Page: 326.5 Change in accrual Schedule Page: 326.6 Line No.: 1 Column: b Line No.: 2 Column: b Line No.: 3 Column: b Line No.: 4 Column: b Line No.: 5 Column: b Line No.: 6 Column: b Line No.: 7 Column: b Line No.: 8 Column: b Line No.: 9 Column: b Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Line No.: 10 Column: b Line No.: 10 Column: l Represents nonfirm Schedule Page: 326.6 Power financial hedges and options Schedule Page: 326.6 Line No.: 11 Column: b Line No.: 12 Column: b Line No.: 12 Column: l Represents nonfirm Schedule Page: 326.6 Represents nonfirm Schedule Page: 326.6 Arizona Corporation Commission approved Power Supply Adjustor Schedule Page: 326.6 Line No.: 13 FERC FORM NO. 1 (ED. 12-87) Column: b Page 450.1 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Represents nonfirm Schedule Page: 326.6 Line No.: 14 Column: b Represents nonfirm Schedule Page: 326.7 Line No.: 1 Column: b Line No.: 2 Column: b Line No.: 3 Column: b Line No.: 3 Column: l Represents nonfirm Schedule Page: 326.7 Represents nonfirm Schedule Page: 326.7 Represents nonfirm Schedule Page: 326.7 SFAS 133 mark-to-market adjustment Schedule Page: 326.7 Line No.: 4 Column: b Line No.: 5 Column: b Line No.: 5 Column: l Represents nonfirm Schedule Page: 326.7 Represents nonfirm Schedule Page: 326.7 Purchased Power to ensure reserve requirements are met Schedule Page: 326.7 Line No.: 6 Column: b Line No.: 7 Column: b Line No.: 8 Column: b Line No.: 9 Column: b Represents nonfirm Schedule Page: 326.7 Represents nonfirm Schedule Page: 326.7 Represents nonfirm Schedule Page: 326.7 Represents nonfirm Schedule Page: 326.7 Line No.: 10 Column: a The amount shown on pages 326 and 327 are actual amounts purchased from counterparties during the reporting period. The change in estimate amount represents various timing differences between the accrued amounts for purchased power compared to the actual amount. Schedule Page: 326.7 Line No.: 10 Column: b The amount shown on pages 326 and 327 are actual amounts purchased from counterparties during the reporting period. The change in estimate amount represents various timing differences between the accrued amounts for purchased power compared to the actual amount. Schedule Page: 326.7 Line No.: 10 Column: l Change in estimate between accrual and actual. Schedule Page: 326.7 Line No.: 11 Column: l Prior year adjustment FERC FORM NO. 1 (ED. 12-87) Page 450.2 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of 1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) 1 Arizona Public Service Various Various FNS 2 Arizona Public Service Pinnacle West Capital Company Arizona Public Service Co. FNS 3 Arizona Public Service Arizona Public Service Co. Arizona Public Service Co. FNS 4 Arizona Public Service Various Arizona Public Service Co. FNS 5 Ajo Improvement Company Arizona Public Service Co. Ajo Improvement FNO 6 Central Arizona Water Conservation District Salt River Project Central Arizona Project FNO 7 Navajo Tribal Utility Authority Tucson Electric Power Navajo Tribal Utility Auth FNO 8 Public Service Company of New Mexico Various Various FNO 9 Southwest Transmission Cooperative Various Various FNO 10 Ak-Chin Electric Utility Authority DOE WAPA Upper AkChin LFP 11 EDF Trading North America, LLC Not Available Not Available LFP 12 NOVO BioPower LLC Not Available Not Available LFP 13 PacifiCorp Not Available Not Available LFP 14 Public Service Company of New Mexico Not Available Not Available LFP 15 Salt River Project Not Available Not Available LFP 16 Arizona Electric Power Cooperative, Inc Not Available Not Available SFP 17 Arizona Public Service Company Not Available Not Available SFP 18 Brookfield Energy Marketing LP Not Available Not Available SFP 19 Central Arizona Water Conservation District Not Available Not Available SFP 20 City of Aneheim Not Available Not Available SFP 21 EDF Trading North America, LLC Not Available Not Available SFP 22 El Paso Electric Co Not Available Not Available SFP 23 FPL Energy Power Marketing, LLC (Nextera) Not Available Not Available SFP 24 Gila River L.L.C Not Available Not Available SFP 25 Guzman Power Markets LLC Not Available Not Available SFP 26 Iberdrola Renewables Not Available Not Available SFP 27 Imperial Irrigation District Not Available Not Available SFP 28 Macquire Energy LLC Not Available Not Available SFP 29 Morgan Stanley Not Available Not Available SFP 30 Nevada Power Company Not Available Not Available SFP 31 PacifiCorp Not Available Not Available SFP 32 Powerex Not Available Not Available SFP 33 Public Service Company of New Mexico Not Available Not Available SFP 34 Salt River Project Not Available Not Available SFP TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of 1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) 1 Salt River Project (OATT General Service) Not Available Not Available SFP 2 Shell Energy North America LP Not Available Not Available SFP 3 Southern California Edison Company Not Available Not Available SFP 4 Sundevil Power Holdings Not Available Not Available SFP 5 Tenaska Power Services Co. Not Available Not Available SFP 6 TransAlta Energy Marketing U.S. Inc Not Available Not Available SFP 7 Tucson Electric Power Company Not Available Not Available SFP 8 Arizona Public Service Company Not Available Not Available NF 9 Brookfield Energy Marketing LP Not Available Not Available NF 10 Cargill Power Markets, LLC Not Available Not Available NF 11 Central Arizona Water Conservation District Not Available Not Available NF 12 City of Anaheim Not Available Not Available NF 13 EDF Trading North America, LLC Not Available Not Available NF 14 El Paso Electric Co Not Available Not Available NF 15 FPL Energy Power Marketing, LLC (Nextera) Not Available Not Available NF 16 Gila River L.L.C Not Available Not Available NF 17 Iberdrola Renewables Not Available Not Available NF 18 Macquire Energy LLC Not Available Not Available NF 19 Mag Energy Solutions, Inc Not Available Not Available NF 20 Morgan Stanley Not Available Not Available NF 21 Nevada Power Company Not Available Not Available NF 22 PacifiCorp Not Available Not Available NF 23 Portland General Electric Company Not Available Not Available NF 24 Powerex Not Available Not Available NF 25 Public Service Company of New Mexico Not Available Not Available NF 26 Pudget Sound Energy Inc Not Available Not Available NF 27 Salt River Project Not Available Not Available NF 28 Salt River Project (OATT General Service) Not Available Not Available NF 29 Sempra Generation Not Available Not Available NF 30 Shell Energy North America LP Not Available Not Available NF 31 Southern California Edison Company Not Available Not Available NF 32 Tenaska Power Services Co. Not Available Not Available NF 33 TransAlta Energy Marketing U.S Inc. Not Available Not Available NF 34 Tri-State Generation and Transmission Not Available Not Available NF TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of 1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) 1 Tucson Electric Power Company Not Available Not Available NF 2 Western Area Power Administration (DSW) Not Available Not Available NF 3 Yuma Cogeneration Associates Yuma Cogeneration Assoc. San Diego Gas and Elect. NF 4 Arizona Public Service Company Not Available Not Available NF 5 PacifiCorp Not Available Not Available NF 6 WestConnect Not Available Not Available NF 7 Imperial Irrigation District Not Available Not Available OLF 8 Luke AFB Main Field DOE WAPA Lower Luke Air Force Base OLF 9 Marine Corps. Air Station DOE WAPA Lower Marine Corp Air Station OLF 10 NOVO BioPower LLC Not Available Not Available OLF 11 Public Service Company of New Mexico Public Serv of New Mexico Public Serv of New Mexico OLF 12 Salt River Project (Schedule F) Salt River Project Salt River Project OLF 13 Salt River Project (Schedule Q) Pinnacle Peak Ocotillo 230 OLF 14 Tucson Electric Power Company Tucson Electric Power Tucson Electric Power OLF 15 Unit B Irrigation and Drainage District Arizona Power Authority Unit B Irrigation District OLF 16 Yuma Cogeneration Associates Yuma Cogeneration Assoc. San Diego Gas and Elect. OLF 17 Yuma Mesa Irrigation and Drainage District DOE WAPA Lower Yuma-Mesa Irrigation Dist OLF 18 Other Not Available Not Available AD 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328.2 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company 5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered. FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other Designation) (g) Billing Demand (MW) (h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Line No. MegaWatt Hours Delivered (j) OATT Various Various 1,402,187 1,367,987 1 OATT Various Various 27,262,316 27,262,316 OATT Various Various 3 OATT Various Various 4 OATT Cholla Ajo Customers OATT West Wing Substation Various OATT Various Various 7 OATT Various Various 53 OATT Various Various 7 OATT Maricopa Substation AkChin Customer 2 OATT Various Various OATT Various OATT OATT 2 3 14,714 14,355 5 46 321,815 321,815 6 43,347 43,347 7 347,825 347,825 8 16,435 16,435 9 3 2 2 11 Various 14 111,978 111,978 12 Various Various 37 302,767 302,767 13 Various Various 10 49,210 49,210 14 OATT Various Various 332 614,952 614,952 15 OATT Various Various 120 120 120 16 OATT Various Various 26,391 56,408 56,408 17 OATT Various Various 3,175 18,634 18,634 18 OATT Various Various 42 42 42 19 OATT Various Various 4,802 320,507 320,507 20 OATT Various Various 7,254 1,906 1,906 21 OATT Various Various 540 340 340 22 OATT Various Various 17,710 191,145 191,145 23 OATT Various Various 2,078 4,120 4,120 24 OATT Various Various 300 350 350 25 OATT Various Various 140 217 217 26 OATT Various Various 818 800 800 27 OATT Various Various 1,527 2,266 2,266 28 OATT Various Various 17,530 44,480 44,480 29 OATT Various Various 200 3,200 3,200 30 OATT Various Various 10,671 29,296 29,296 31 OATT Various Various 1,056 3,478 3,478 32 OATT Various Various 1,656 5,438 5,438 33 OATT Various Various 20,069 26,012 26,012 34 363,417 36,600,168 36,479,125 FERC FORM NO. 1 (ED. 12-90) Page 329 10 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company 5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered. FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other Designation) (g) Billing Demand (MW) (h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Line No. MegaWatt Hours Delivered (j) OATT Various Various 4,911 2,095 2,095 1 OATT Various Various 3,880 6,480 6,480 2 OATT Various Various 2,033 3,614 3,614 3 OATT Various Various 7,345 10,031 10,031 4 OATT Various Various 3,913 5,963 5,963 5 OATT Various Various 17,942 29,457 29,457 6 OATT Various Various 29,004 36,646 36,646 7 OATT Various Various 8,472 45,123 45,123 8 OATT Various Various 1 OATT Various Various 2,337 7,118 7,118 OATT Various Various 30 45 45 11 OATT Various Various 182 178 178 12 OATT Various Various 1,650 1,783 1,783 13 OATT Various Various 450 751 751 14 OATT Various Various 16,050 29,182 29,182 15 OATT Various Various 1,020 335 335 16 OATT Various Various 398 1,055 1,055 17 OATT Various Various 1,560 4,568 4,568 18 OATT Various Various 5,055 6,782 6,782 19 OATT Various Various 27,524 44,175 44,175 20 OATT Various Various 522 672 672 21 OATT Various Various 12,627 35,786 35,786 22 OATT Various Various 454 554 554 23 OATT Various Various 1,424 4,037 4,037 24 OATT Various Various 807 2,482 2,482 OATT Various Various 1 OATT Various Various 32,823 54,411 54,411 27 OATT Various Various 3,404 2,345 2,345 28 OATT Various Various 75 75 75 29 OATT Various Various 450 1,951 1,951 30 OATT Various Various 3,677 7,823 7,823 31 OATT Various Various 1,295 5,879 5,879 32 OATT Various Various 11,326 33,654 33,654 33 OATT Various Various 165 165 165 34 363,417 36,600,168 36,479,125 FERC FORM NO. 1 (ED. 12-90) Page 329.1 9 10 25 26 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2014/Q4 End of 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company 5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered. FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other Designation) (g) Billing Demand (MW) (h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Line No. MegaWatt Hours Delivered (j) OATT Various Various 43,676 88,327 88,327 1 OATT Various Various 30 30 30 2 OATT Various Various 30 36 36 3 RS 183 Various Various 1,041,600 1,041,600 4 RS 183 Various Various 2,650,267 2,650,267 5 Tariff Volume 6 Various Various 17,665 17,665 6 OATT Various Various 7 RS 162 Pinnacle Peak Sub Luke Substation 8 RS 166 Gila Substation Marine Corp Air Stn 9 OATT Various Various RS 73 Palo Verde Four Corners RS 3 West Phoenix Sub West Phoenix Sub RS 3 Pinnacle Peak Ocotillo 230 RS 32 Four Corners Saguaro Plant RS 181 Gila Substation District Customer RS 198 Riverside Substation North Gila Sub RS 31 Gila Substation Yuma Mesa Load 17 NA Not Available Not Available 18 10 130 821,265 821,265 11 12 13 100 322,583 236,099 14 15 51 76,873 76,873 16 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 363,417 FERC FORM NO. 1 (ED. 12-90) Page 329.2 36,600,168 36,479,125 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively. 11. Footnote entries and provide explanations following all required data. REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS Energy Charges (Other Charges) ($) ($) (l) (m) Demand Charges ($) (k) 13,259,082 104,420 1 2 -13,259,082 -13,259,082 -241,992,891 3 241,992,891 241,992,891 4 56,310 54,182 160,730 5 1,607,923 6 240,913 7 1,906,641 1,906,641 8 203,896 203,896 9 29,946 -82,746 13,259,082 -241,992,891 1,607,923 269,477 Line No. Total Revenues ($) (k+l+m) (n) -87,115 10 100,111 -117,061 100,111 11 500,694 500,694 12 1,323,077 1,323,077 13 357,588 357,588 14 10,630,434 10,630,434 15 820 706,741 14,670 91,549 820 16 721,411 17 91,549 18 171 171 19 2,218,005 2,218,005 20 80,264 80,264 21 2,308 2,308 22 1,668,861 1,668,861 23 138,743 138,743 24 2,564 2,564 25 2,399 2,399 26 5,649 5,649 27 15,939 15,939 28 226,934 226,934 29 19,724 19,724 30 309,412 31 24,079 24,079 32 36,065 36,065 33 282,954 282,954 34 297,812 31,083,340 FERC FORM NO. 1 (ED. 12-90) 11,600 -142,821 Page 330 -9,278 30,931,241 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively. 11. Footnote entries and provide explanations following all required data. REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS Energy Charges (Other Charges) ($) ($) (l) (m) Demand Charges ($) (k) Line No. Total Revenues ($) (k+l+m) (n) 30,051 30,051 1 52,334 52,334 2 27,005 27,005 3 83,395 83,395 4 39,807 39,807 5 155,643 155,643 6 394,176 394,176 7 289,987 8 7 7 9 43,138 43,138 10 183 183 11 1,473 1,473 12 13,214 13,214 13 4,684 4,684 14 238,438 238,438 15 13,677 13,677 16 7,304 7,304 17 29,271 29,271 18 54,022 54,022 19 202,757 202,757 20 288,835 1,152 2,730 2,730 21 320,819 320,819 22 3,684 3,684 23 22,707 22,707 24 16,936 16,936 25 7 7 26 481,177 481,177 27 20,417 20,417 28 308 308 29 11,399 11,399 30 57,866 57,866 31 32,896 32,896 32 194,799 194,799 33 677 677 34 31,083,340 FERC FORM NO. 1 (ED. 12-90) -142,821 Page 330.1 -9,278 30,931,241 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively. 11. Footnote entries and provide explanations following all required data. REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS Energy Charges (Other Charges) ($) ($) (l) (m) Demand Charges ($) (k) Line No. Total Revenues ($) (k+l+m) (n) 688,798 688,798 1 154 154 2 238 238 3 4 5 62,419 52,997 173,763 676 77,652 2,716 62,419 6 52,997 7 174,439 8 77,652 9 2,716 10 1,415,030 1,415,030 11 26,034 26,034 12 772,910 13 772,910 1,824,000 1,824,000 14 540 540 15 1,171,007 1,171,007 16 4,500 4,500 17 -981,924 18 -981,924 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 31,083,340 FERC FORM NO. 1 (ED. 12-90) -142,821 Page 330.2 -9,278 30,931,241 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 328 Line No.: 1 Column: a Service to Arizona Public Service Company pursuant to Part III of the OATT Schedule Page: 328 Line No.: 1 Column: m Intracompany Transmission Schedule Page: 328 Line No.: 2 Column: a Service to Arizona Public Service Company pursuant to Part III of the OATT Schedule Page: 328 Line No.: 2 Column: m Intracompany Transmission Schedule Page: 328 Line No.: 3 Column: a Service to Arizona Public Service Company pursuant to Part IV of the OATT Schedule Page: 328 Line No.: 3 Column: m Intracompany Transmission Schedule Page: 328 Line No.: 4 Column: a Service to Arizona Public Service Company pursuant to Part IV of the OATT Schedule Page: 328 Line No.: 4 Column: m Intracompany Transmission Schedule Page: 328 Line No.: 7 Column: m Direct Assignment Charges and Billing Adjustments Schedule Page: 328 Line No.: 10 Column: d Termination date - Not yet determined when this control area will be transferred. Once determined, APS will provide written notice to the transmission customer. Schedule Page: 328 Line No.: 11 Column: d Line No.: 12 Column: d Termination 2/1/2015 Schedule Page: 328 10 MW Terminates 1/1/2028 and 4 MW Terminates 10/1/2031 Schedule Page: 328 Line No.: 13 Column: d Termination date 7/15/2041 Schedule Page: 328 Line No.: 14 Column: d Line No.: 15 Column: d Can renew annually Schedule Page: 328 Termination date - Not yet determined when this control area will be transferred. Once, Determined, APS will provide written notice to the transmission customer. Schedule Page: 328 Line No.: 17 Column: a APS Merchant is an affiliate of Arizona Public Service Company Schedule Page: 328 Line No.: 17 Column: m Line No.: 31 Column: m Line No.: 8 Column: a Penalty Schedule Page: 328 Penalty Schedule Page: 328.1 APS Merchant is an affiliate of Arizona Public Service Company Schedule Page: 328.1 Line No.: 8 Column: m Line No.: 4 Column: n Penalty Schedule Page: 328.2 Exchange agreement pursuant to Pre888 contract Schedule Page: 328.2 Line No.: 5 FERC FORM NO. 1 (ED. 12-87) Column: n Page 450.1 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Exchange agreement pursuant to Pre888 contract Schedule Page: 328.2 Line No.: 6 Column: m Line No.: 7 Column: d 3rd party billing Schedule Page: 328.2 Terminates upon mutual agreement Schedule Page: 328.2 Line No.: 7 Column: m Direct Assignment Charges Schedule Page: 328.2 Line No.: 8 Column: d Termination date 10 years or longer with a three year termination notice by either party. Schedule Page: 328.2 Line No.: 8 Column: k Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 9 Column: d Termination date - Indefinite term subject to a three year termination notice by either party. Schedule Page: 328.2 Line No.: 9 Column: k Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 10 Column: d Termination date 1/1/2028 Schedule Page: 328.2 Line No.: 10 Column: m Direct Assignment Charges Schedule Page: 328.2 Line No.: 11 Column: d Termination date - Good until terminated with thirty days advance written notice if no service schedule is in effect or scheduled to become effective. Schedule Page: 328.2 Line No.: 12 Column: d Termination date - Good until terminated with a three year advance written notice. Schedule Page: 328.2 Line No.: 13 Column: d Schedule Q is for transmission but the cost is based on the plant investment of Pinnacle Peak-Ocotillo 230kV lines and not the current transmission rates. Schedule Page: 328.2 Line No.: 13 Column: m Direct Assignment Charges Schedule Page: 328.2 Line No.: 14 Column: d Termination date - Good until terminated by May 31st of any year with three years advance written notice. Schedule Page: 328.2 Line No.: 15 Column: d Termination date - indefinite term subject to three year termination notice by either party. Schedule Page: 328.2 Line No.: 15 Column: k Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 16 Column: d Termination date 12/31/2024 Schedule Page: 328.2 Line No.: 17 Column: d Termination date 2/3/1997 - Automatic five year renewal subject to a three year termination notice by either party. Schedule Page: 328.2 Line No.: 17 Column: k Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 18 Column: d FERC transmission rate true up, change in estimate, and timing difference. Schedule Page: 328.2 Line No.: 18 Column: m FERC transmission rate true up, change in estimate, and timing difference. FERC FORM NO. 1 (ED. 12-87) Page 450.2 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 (2) X A Resubmission TRANSMISSION OF ELECTRICITY BY ISO/RTOs 1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). 3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. 4. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. 5. In column (d) report the revenue amounts as shown on bills or vouchers. 6. Report in column (e) the total revenues distributed to the entity listed in column (a). Line Total Revenue Payment Received by Statistical FERC Rate Schedule Total Revenue by Rate Schedule or Tarirff (Transmission Owner Name) Classification or Tariff Number No. (d) (e) (a) (b) (c) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 TOTAL FERC FORM NO. 1/3-Q (REV 03-07) Page 331 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling") Year/Period of Report 2014/Q4 End of 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data. Line No. Statistical Name of Company or Public Authority (Footnote Affiliations) Classification (b) (a) 1 Agua Caliente TRANSFER OF ENERGY MagawattMagawatthours hours Received Delivered (c) (d) EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Energy Other Total Cost of Charges Charges Charges Transmission ($) ($) ($) ($) (e) (f) (g) (h) OS -44,795 2 Arizona Public Service LFP 1,011,398 3 Bureau of Indian Affair OLF 118,800 4 Department of Energy FNS 251,099 251,099 891,926 5 Department of Energy OLF 12,591 12,591 668,304 6 Department of Energy LFP 57,875 57,875 7 Department of Energy LFP 486,696 486,696 8 Department of Energy FNS -44,795 1,011,398 10,800 129,600 566,303 42,859 1,501,088 87,212 -68,149 687,367 6,522,689 68,938 13,017 6,604,644 50,505 545,796 -5,802 590,499 -1 92,023 92,024 9 Department of Energy OS 202,229 30,005 232,234 10 Department of Energy FNS 1,143,080 1,143,080 3,195,034 1,328,970 261,289 4,785,293 11 Department of Energy LFP 1,014,000 1,014,000 1,708,784 541,014 73,796 2,323,594 12 Department of Energy OS 2,648 2,648 3,843 27,119 30,962 13 Department of Energy SFP 8,008 8,008 194,626 14 Department of Energy OS 45,000 45,000 15 Electric District # 2 LFP 12 12 16 Electric District # 3 LFP 2,503 2,503 6,019,556 6,019,515 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) Page 332 19,271,935 -2,949 191,677 1,517 -852 665 70,108 552 70,660 6,505,920 1,413,567 27,191,422 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling") Year/Period of Report 2014/Q4 End of 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data. Line No. Statistical Name of Company or Public Authority (Footnote Affiliations) Classification (b) (a) TRANSFER OF ENERGY MagawattMagawatthours hours Received Delivered (c) (d) 446 405 EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Energy Other Total Cost of Charges Charges Charges Transmission ($) ($) ($) ($) (e) (f) (g) (h) 1 Electric District # 4 OLF 2 Electric District # 5 OS 24,242 24,242 3 Electric District # 5 OS -33,024 -33,024 4 El Paso Electric Co SFP 9,981 58,261 5 Public Servicr of NM NF 6 Salt River Project LFP 159,457 159,457 1,004,036 133,630 7 Salt River Project FNS 473,377 473,377 1,871,573 8 Salt River Project OLF 39,387 39,387 140,805 336,262 336,262 1,277,542 142,000 142,000 9 Salt River Project OLF LFP 11 Salt River Project OLF 12 Salt River Project OLF 111,126 111,126 13 Salt River Project OS 1,696,854 14 Salt River Project FNS 366 15 Salt River Project OS 7,462 16 San Carlos IIP OS FERC FORM NO. 1/3-Q (REV. 02-04) 181 48,280 2,238 10 Salt River Project TOTAL 14,062 2,238 4,277 1,141,943 390,299 91,107 2,352,979 32,189 -32,189 140,805 1,435,581 391,200 -233,161 -326,258 326,258 14,947 74,785 91,432 -91,420 239,797 1,696,854 664,426 350,561 1,014,987 366 1,536,501 583,875 2,120,376 7,462 19,468 30,443 49,911 2,755 2,755 1,413,567 27,191,422 59,838 6,019,556 14,243 6,019,515 Page 332.1 239,785 19,271,935 6,505,920 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling") Year/Period of Report 2014/Q4 End of 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data. Line No. Statistical Name of Company or Public Authority (Footnote Affiliations) Classification (b) (a) 1 San Carlos IIP TRANSFER OF ENERGY MagawattMagawatthours hours Received Delivered (c) (d) EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Energy Other Total Cost of Charges Charges Charges Transmission ($) ($) ($) ($) (e) (f) (g) (h) OS 2 Southern Cal Edison LFP 104 104 3 Southwester Transmissio SFP 29,023 29,023 199,217 4 Tucson Electric Power SFP 180 180 4,906 6,019,556 6,019,515 19,271,935 112,666 660 660 20,265 219,482 5,916 118,582 1,004 5,910 1,413,567 27,191,422 5 6 7 8 9 10 11 12 13 14 15 16 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2 6,505,920 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 332 Line No.: 1 Column: b Line No.: 1 Column: g Hodoo Wash Schedule Page: 332 Prior period adjustment Schedule Page: 332 Line No.: 2 Column: a Intercompany Transmission Schedule Page: 332 Line No.: 2 Column: b Terminates December 31, 2015 Schedule Page: 332 Line No.: 3 Column: b Teminates with 30 days notice Schedule Page: 332 Line No.: 3 Column: g Line No.: 4 Column: g Timing Schedule Page: 332 Prior period adjustment Schedule Page: 332 Line No.: 5 Column: b Terminates September 30, 2014 Schedule Page: 332 Line No.: 5 Column: g Prior period adjustment Schedule Page: 332 Line No.: 6 Column: b Terminates December 31, 2017 Schedule Page: 332 Line No.: 6 Column: g Prior period adjustment Schedule Page: 332 Line No.: 7 Column: b Terminates September 30, 2029 Schedule Page: 332 Line No.: 7 Column: g Prior period adjustment Schedule Page: 332 Line No.: 8 Column: b Terminates September 30, 2029 Schedule Page: 332 Line No.: 9 Column: b Loss compensation on Jointly owned facilites Schedule Page: 332 Line No.: 9 Column: g Prior period adjustment Schedule Page: 332 Line No.: 10 Column: g Line No.: 11 Column: b Timing Schedule Page: 332 Terminates May 1, 2022 Schedule Page: 332 Line No.: 11 Column: g Prior period adjustment Schedule Page: 332 Line No.: 12 Column: g Prior period adjustment Schedule Page: 332 Line No.: 13 Column: g Line No.: 14 Column: g Ancilliary charges Schedule Page: 332 Prior period adjustment Schedule Page: 332 Line No.: 15 Column: b Effective until terminated by counterparty FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 332 Line No.: 15 Column: h APS has a Reciprocal Transmission Agreement with Electric District 2 for power and energy. Any exchange or payback is done in energy, not dollars. Schedule Page: 332 Line No.: 16 Column: g Prior period adjustment Schedule Page: 332.1 Line No.: 1 Column: b Effective until terminated by counterparty Schedule Page: 332.1 Line No.: 1 Column: g Line No.: 2 Column: g Line No.: 2 Column: h Prior period adjustment Schedule Page: 332.1 Prior period adjustment Schedule Page: 332.1 Retail electric purchase moved to purchased power Schedule Page: 332.1 Line No.: 3 Column: g Line No.: 3 Column: h Prior period adjustment Schedule Page: 332.1 Retail electric purchase moved to purchased power Schedule Page: 332.1 Line No.: 4 Column: g Line No.: 6 Column: b Line No.: 6 Column: g Line No.: 7 Column: g Line No.: 7 Column: h Prior period adjustment Schedule Page: 332.1 Terminates May 1, 2019 Schedule Page: 332.1 Prior period adjustment Schedule Page: 332.1 Prior period adjustment Schedule Page: 332.1 APS payment as a credit on APS provides SRP in the same contract Schedule Page: 332.1 Line No.: 8 Column: b Terminates with 1 year APS notice or 5 year SRP notice Schedule Page: 332.1 Line No.: 8 Column: g Line No.: 9 Column: b Prior period adjustment Schedule Page: 332.1 Terminates with 5 year notice Schedule Page: 332.1 Line No.: 9 Column: g Prior period adjustment Schedule Page: 332.1 Line No.: 10 Column: b Terminates with 6 month notice Schedule Page: 332.1 Line No.: 10 Column: g Line No.: 11 Column: b Prior period adjustment Schedule Page: 332.1 Terminates with 1 year notice Schedule Page: 332.1 Line No.: 11 Column: g Line No.: 12 Column: b Prior period adjustment Schedule Page: 332.1 Terminates with 1 year notice Schedule Page: 332.1 Line No.: 12 Column: g Prior period adjustment FERC FORM NO. 1 (ED. 12-87) Page 450.2 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 332.1 Line No.: 13 Column: b Loss compensation for deliveries to DV Schedule Page: 332.1 Line No.: 13 Column: g Line No.: 14 Column: g Line No.: 15 Column: g Line No.: 16 Column: g Line No.: 16 Column: h Prior period adjustment Schedule Page: 332.1 Prior period adjustment Schedule Page: 332.1 Prior period adjustment Schedule Page: 332.1 Prior period adjustment Schedule Page: 332.1 Retail electric purchase moved to purchased power Schedule Page: 332.2 Line No.: 1 Column: g Line No.: 1 Column: h Communication charge Schedule Page: 332.2 Retail electric purchase moved to purchased power Schedule Page: 332.2 Line No.: 2 Column: b Terminates September 30, 2037 Schedule Page: 332.2 Line No.: 2 Column: g Line No.: 3 Column: g Ancilliary charges Schedule Page: 332.2 Prior period adjustment FERC FORM NO. 1 (ED. 12-87) Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 Name of Respondent 20150811-8000 FERC Arizona Public Service Company This Report Is: PDF (Unofficial) (1) 08/11/2015 An Original Line No. Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC) Description (a) 1 Industry Association Dues Year/Period of Report 2014/Q4 End of Amount (b) 1,119,887 2 Nuclear Power Research Expenses 3 Other Experimental and General Research Expenses 144,525 4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 6 Allocation of Parent Company Costs -238,501 10,193,780 7 Bank Fees 785,188 8 Billed to Others-Services Performed -73,433,635 9 Communication Service 266,993 10 Materials & Supplies 94,858 11 Miscellaneous Payroll 2,432,445 12 Outside Services 6,684,270 13 Rents/Leases 14,183 14 Transportation Expense 15,864 15 Travel 453,446 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 -51,466,697 TOTAL FERC FORM NO. 1 (ED. 12-94) Page 335 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405) (Except amortization of aquisition adjustments) Year/Period of Report 2014/Q4 End of 1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). 2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. 3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. 4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related. Line No. Functional Classification (a) 1 Intangible Plant A. Summary of Depreciation and Amortization Charges Amortization of Depreciation Expense for Asset Limited Term Depreciation Retirement Costs Expense Electric Plant (Account 403.1) (Account 403) (Account 404) (b) (d) (c) 53,011,286 Amortization of Other Electric Plant (Acc 405) (e) Total (f) 53,011,286 2 Steam Production Plant 53,560,889 1,521,588 2,135 55,084,612 3 Nuclear Production Plant 57,744,575 -2,454,287 7,669,692 62,959,980 4 Hydraulic Production Plant-Conventional -882,133 -882,133 5 Hydraulic Production Plant-Pumped Storage 6 Other Production Plant 65,069,597 7 Transmission Plant 41,037,197 4,097,542 45,134,739 120,507,429 927,708 121,435,137 30,117,779 5,970,605 36,088,384 71,678,968 437,910,842 8 Distribution Plant 9,240 65,078,837 9 Regional Transmission and Market Operation 10 General Plant 11 Common Plant-Electric 12 TOTAL 367,155,333 -923,459 B. Basis for Amortization Charges RATES Franchises Software Misc. Intangibles Limited Term Land Rights Office Equipment & Furniture, Small Tools, Garage Equipment, Misc. Equipment Leasehold Improvements 302 303 303.0 310 / 350 / 360 / 389 4.00% 10.00% - 50.00% 20.00% 1.67% - 50.00% 391 / 391.2 / 393 / 394 / 395 / 398 4.17% - 5.00% 321 / 322 / 323 / 324 / 325 / 326 / 371 / 390 / 397 amortized over the life of the lease * Note: Hydro expense relates to the Childs Irving Regulatory Liability balance being amorted over 3 years to clear the Regulatory "2540" balance upon final decommissioning per ACC Dec. 73183. FERC FORM NO. 1 (REV. 12-03) Page 336 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Line No. Account No. (a) (2) X A Resubmission DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) C. Factors Used in Estimating Depreciation Charges Depreciable Estimated Net Plant Base Avg. Service Salvage (In Thousands) Life (Percent) (d) (b) (c) 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 FERC FORM NO. 1 (REV. 12-03) Date of Report (Mo, Da, Yr) 04/15/2015 Page 337 Applied Depr. rates (Percent) (e) Year/Period of Report 2014/Q4 End of Mortality Curve Type (f) Average Remaining Life (g) Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission REGULATORY COMMISSION EXPENSES Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. 2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Line No. Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a) 1 ACC/RUCO Expenses Assessed by Regulatory Commission (b) Expenses of Utility (c) Total Expense for Current Year (b) + (c) (d) 2 Annual Assessment by Arizona Corporation 3 Commission (ACC) and Annual Assessment by 4 Residential Utility Consumer Office (RUCO) 6,928,059 5 Legal and Filing Fees 6,928,059 -6,458 6 Consulting Fees 7 Payroll and Employee Expense 8 Est. ACC and RUCO Assessments on Unbilled Rev -6,458 3,311 3,311 1,664,424 1,664,424 90,654 90,654 2,468,493 2,468,493 9 Other 10 11 FERC Expenses 12 Regulatory Assessment by FERC 13 Legal and Filing Fees 14 Consulting Fees 15 Payroll and Employee Expenses 53,736 53,736 222,152 222,152 16 Other 17 18 NRC Expenses 19 NRC License Fees 5,803,991 5,803,991 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 TOTAL FERC FORM NO. 1 (ED. 12-96) 15,291,197 Page 350 1,937,165 17,228,362 Deferred in Account 182.3 at Beginning of Year (e) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission REGULATORY COMMISSION EXPENSES (Continued) Year/Period of Report 2014/Q4 End of 3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. 4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts. 5. Minor items (less than $25,000) may be grouped. EXPENSES INCURRED DURING YEAR CURRENTLY CHARGED TO Account Amount Department No. (f) (g) (h) AMORTIZED DURING YEAR Deferred to Account 182.3 (i) Contra Account Amount (j) (k) Deferred in Account 182.3 End of Year (l) Line No. 1 2 3 Electric 928 6,928,059 4 Electric 928 -6,458 5 Electric 928 3,311 6 Electric 928 1,664,424 7 Electric 928 90,654 8 Electric 928 9 10 11 Electric 928 2,468,493 12 Electric 928 Electric 928 53,736 13 14 Electric 928 222,152 15 Electric 928 16 17 18 Electric 928 5,803,991 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 17,228,362 FERC FORM NO. 1 (ED. 12-96) 46 Page 351 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES Year/Period of Report 2014/Q4 End of 1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). 2. Indicate in column (a) the applicable classification, as shown below: Classifications: A. Electric R, D & D Performed Internally: (1) Generation a. hydroelectric i. Recreation fish and wildlife ii Other hydroelectric b. Fossil-fuel steam c. Internal combustion or gas turbine d. Nuclear e. Unconventional generation f. Siting and heat rejection (2) Transmission Line No. a. Overhead b. Underground (3) Distribution (4) Regional Transmission and Market Operation (5) Environment (other than equipment) (6) Other (Classify and include items in excess of $50,000.) (7) Total Cost Incurred B. Electric, R, D & D Performed Externally: (1) Research Support to the electrical Research Council or the Electric Power Research Institute Description (b) Classification (a) 1 A(1)e RENEWABLES 2 A(1)e HPS 3 4 5 Total 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 FERC FORM NO. 1 (ED. 12-87) Page 352 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued) Year/Period of Report 2014/Q4 End of (2) Research Support to Edison Electric Institute (3) Research Support to Nuclear Power Groups (4) Research Support to Others (Classify) (5) Total Cost Incurred 3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D & D activity. 4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e) 5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. 6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by "Est." 7. Report separately research and related testing facilities operated by the respondent. Costs Incurred Internally Costs Incurred Externally Current Year Current Year (c) (d) 235,608 68,438 63,202 AMOUNTS CHARGED IN CURRENT YEAR Account (e) 5490 5880 Amount (f) 235,608 131,640 Unamortized Accumulation (g) Line No. 1 2 3 4 68,438 298,810 367,248 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 FERC FORM NO. 1 (ED. 12-87) Page 353 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission DISTRIBUTION OF SALARIES AND WAGES Year/Period of Report 2014/Q4 End of Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used. Line No. Classification Direct Payroll Distribution (b) (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 Electric Operation Production Transmission Regional Market Distribution Customer Accounts Customer Service and Informational Sales Administrative and General TOTAL Operation (Enter Total of lines 3 thru 10) Maintenance Production Transmission Regional Market Distribution Administrative and General TOTAL Maintenance (Total of lines 13 thru 17) Total Operation and Maintenance Production (Enter Total of lines 3 and 13) Transmission (Enter Total of lines 4 and 14) Regional Market (Enter Total of Lines 5 and 15) Distribution (Enter Total of lines 6 and 16) Customer Accounts (Transcribe from line 7) Customer Service and Informational (Transcribe from line 8) Sales (Transcribe from line 9) Administrative and General (Enter Total of lines 10 and 17) TOTAL Oper. and Maint. (Total of lines 20 thru 27) Gas Operation Production-Manufactured Gas Production-Nat. Gas (Including Expl. and Dev.) Other Gas Supply Storage, LNG Terminaling and Processing Transmission Distribution Customer Accounts Customer Service and Informational Sales Administrative and General TOTAL Operation (Enter Total of lines 31 thru 40) Maintenance Production-Manufactured Gas Production-Natural Gas (Including Exploration and Development) Other Gas Supply Storage, LNG Terminaling and Processing Transmission FERC FORM NO. 1 (ED. 12-88) Page Allocation of Payroll charged for Clearing Accounts (c) Total (d) 119,621,565 15,416,529 35,849,976 30,218,022 2,403,424 5,999,233 95,621,815 305,130,564 48,059,115 3,485,310 23,285,664 4,090,484 78,920,573 167,680,680 18,901,839 59,135,640 30,218,022 2,403,424 5,999,233 99,712,299 384,051,137 354 384,051,137 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Line No. (2) X A Resubmission DISTRIBUTION OF SALARIES AND WAGES (Continued) Classification Direct Payroll Distribution (b) (a) 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 Distribution Administrative and General TOTAL Maint. (Enter Total of lines 43 thru 49) Total Operation and Maintenance Production-Manufactured Gas (Enter Total of lines 31 and 43) Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, Other Gas Supply (Enter Total of lines 33 and 45) Storage, LNG Terminaling and Processing (Total of lines 31 thru Transmission (Lines 35 and 47) Distribution (Lines 36 and 48) Customer Accounts (Line 37) Customer Service and Informational (Line 38) Sales (Line 39) Administrative and General (Lines 40 and 49) TOTAL Operation and Maint. (Total of lines 52 thru 61) Other Utility Departments Operation and Maintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64) Utility Plant Construction (By Utility Departments) Electric Plant Gas Plant Other (provide details in footnote): TOTAL Construction (Total of lines 68 thru 70) Plant Removal (By Utility Departments) Electric Plant Gas Plant Other (provide details in footnote): TOTAL Plant Removal (Total of lines 73 thru 75) Other Accounts (Specify, provide details in footnote): Inventory Deferred Debits Other Revenue Other Income Miscellaneous Income Deductions Misc. Deferred Debit Reconciling Items Palo Verde Generating Station Four Corners Cholla-Pacificorp Yucca Morgan Pinnacle Peak PV-NG Yuma Navajo STS 500 KV Line All Other Billed to Participants Studies Street Lights Miscellaneous Billings TOTAL Other Accounts TOTAL SALARIES AND WAGES FERC FORM NO. 1 (ED. 12-88) Page 355 Year/Period of Report 2014/Q4 End of Allocation of Payroll charged for Clearing Accounts (c) Total (d) 384,051,137 384,051,137 144,307,625 144,307,625 144,307,625 144,307,625 165,288 149,415 88,724 248 3,308,319 367,043 211,176,067 16,038,870 8,653,196 2,026,209 287,816 620,956 1,195,843 110,471 84,884 610,994 1,887,876 246,772,219 775,130,981 165,288 149,415 88,724 248 3,308,319 367,043 211,176,067 16,038,870 8,653,196 2,026,209 287,816 620,956 1,195,843 110,471 84,884 610,994 1,887,876 246,772,219 775,130,981 20150811-8000 08/11/2015 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 COMMON UTILITY PLANT AND EXPENSES 1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors. 2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used. 3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation. 4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other authorization. FERC FORM NO. 1 (ED. 12-87) Page 356 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2014/Q4 End of AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS 1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively. Description of Item(s) Line No. (a) Balance at End of Quarter 1 (b) Balance at End of Quarter 2 (c) Balance at End of Quarter 3 (d) Balance at End of Year (e) 1 Energy 2 Net Purchases (Account 555) 3 Net Sales (Account 447) 1,796,517 4,215,556 6,954,372 9,155,379 ( 13,618,988) ( 20,579,439) ( 37,875,285) ( 49,204,828) ( 11,822,471) ( 16,363,883) ( 30,920,913) ( 40,049,449) 4 Transmission Rights 5 Ancillary Services 6 Other Items (list separately) 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 TOTAL FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission PURCHASES AND SALES OF ANCILLARY SERVICES Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. (1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year. (2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold during the year. (3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold during the year. (4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year. (5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services purchased and sold during the period. (6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided. Amount Purchased for the Year Line No. Type of Ancillary Service (a) Amount Sold for the Year Usage - Related Billing Determinant Unit of Measure Number of Units Dollars (b) (c) (d) 1 Scheduling, System Control and Dispatch 60,366 MW 2 Reactive Supply and Voltage 60,356 MW 3 Regulation and Frequency Response 60,356 MW 4 Energy Imbalance 1,787,434 Usage - Related Billing Determinant Unit of Measure Number of Units Dollars (e) (f) (g) 65,847 MW 1,993,717 65,847 MW 6,776,643 61,513 MW mWh -4,056 mWh 6,782,723 -156,595 5 Operating Reserve - Spinning 60,366 MW 15,649,795 61,513 MW 15,656,438 6 Operating Reserve - Supplement 60,366 MW 1,980,964 61,513 MW 1,981,339 7 Other 8 Total (Lines 1 thru 7) FERC FORM NO. 1 (New 2-04) mWh mWh 301,810 26,194,836 Page 398 312,177 26,257,622 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 398 Line No.: 1 Column: e Short-term demand excluded due to mismatch of demand measurement (Hourly, Daily, etc.). Short-term service accounts for $69,740.39 of sold revenue in column (g) Schedule Page: 398 Line No.: 2 Column: f Service currently provided at $0 per MW FERC FORM NO. 1 (ED. 12-87) Page 450.1 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission MONTHLY TRANSMISSION SYSTEM PEAK LOAD (1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. (2) Report on Column (b) by month the transmission system's peak load. (3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). (4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification. NAME OF SYSTEM: Line No. Month Monthly Peak MW - Total Day of Monthly Peak (a) (b) (c) 1 January 4,727 2 February 4,730 3 March 4,343 Hour of Firm Network Monthly Service for Self Peak (d) Firm Network Service for Others Long-Term Firm Point-to-point Reservations Other LongTerm Firm Service Short-Term Firm Point-to-point Reservation Other Service (f) (g) (h) (i) (j) (e) 800 3,964 93 389 281 4 800 3,974 83 392 281 25 2000 3,594 76 392 281 11,532 252 1,173 843 10 4 Total for Quarter 1 5 April 5,219 21 1800 4,432 114 392 281 6 May 6,493 27 1700 5,724 93 396 281 7 June 7,187 30 1800 8 Total for Quarter 2 6,450 117 339 281 16,606 324 1,127 843 9 July 7,912 23 1800 7,168 124 339 281 10 August 7,314 17 1800 6,594 100 339 281 11 September 6,956 2 1700 6,231 105 339 281 19,993 329 1,017 843 12 Total for Quarter 3 13 October 5,300 4 1700 4,581 99 339 281 14 November 4,192 6 1900 3,520 52 339 281 15 December 4,844 31 1900 16 Total for Quarter 4 4,134 89 339 281 12,235 240 1,017 843 60,366 1,145 4,334 3,372 17 Total Year to Date/Year FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 400 Line No.: 1 Column: b Rows 1 - 12 adjusted from previously reported amounts to remove duplicative capture of resold TSR Schedule Page: 400 Line No.: 1 Column: e Rows 1 - 12 modified from previouly reported amounts to reflect load served in APS system through interchange on unaffiliated system Schedule Page: 400 Line No.: 1 Column: g Rows 1 - 12 adjusted from previously reported amounts to remove duplicative capture of resold TSR Schedule Page: 400 Line No.: 1 Column: h Rows 1 - 12 modified from previously reported amounts to remove distribution agreements whose transmission is captured by another class of service Schedule Page: 400 Line No.: 1 Column: i Rows 1 - 12 modified from previously reported amounts to remove short-tem transactions not serving load in the APS system FERC FORM NO. 1 (ED. 12-87) Page 450.1 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD Year/Period of Report 2014/Q4 End of (1) Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. (2) Report on Column (b) by month the transmission system's peak load. (3) Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). (4) Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). (5) Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i). NAME OF SYSTEM: Line No. Monthly Peak MW - Total Day of Monthly Peak Hour of Monthly Peak Imports into ISO/RTO Exports from ISO/RTO Through and Out Service Network Service Usage Point-to-Point Service Usage Total Usage Month (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) 1 January 2 February 3 March 4 Total for Quarter 1 5 April 6 May 7 June 8 Total for Quarter 2 9 July 10 August 11 September 12 Total for Quarter 3 13 October 14 November 15 December 16 Total for Quarter 4 17 Total Year to Date/Year FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400a Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission ELECTRIC ENERGY ACCOUNT Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year. Line No. Item MegaWatt Hours (a) (b) Line No. Item MegaWatt Hours (a) (b) 1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY 2 Generation (Excluding Station Use): 22 Sales to Ultimate Consumers (Including 3 Steam 15,585,390 4 Nuclear 9,408,239 23 Requirements Sales for Resale (See 24 Non-Requirements Sales for Resale (See 6 Hydro-Pumped Storage 25 Energy Furnished Without Charge 26,987,843 26 Energy Used by the Company (Electric 7,239,997 27 Total Energy Losses 28 TOTAL (Enter Total of Lines 22 Through 11 Power Exchanges: 12 Received 823,724 13 Delivered 945,331 14 Net Exchanges (Line 12 minus line 13) 27) (MUST EQUAL LINE 20) -121,607 15 Transmission For Other (Wheeling) 16 Received 36,600,168 17 Delivered 36,479,125 18 Net Transmission for Other (Line 16 minus 121,043 line 17) 19 Transmission By Others Losses 20 TOTAL (Enter Total of lines 9, 10, 14, 18 -373 34,226,903 and 19) FERC FORM NO. 1 (ED. 12-90) 55,761 Dept Only, Excluding Station Use) through 8) 10 Purchases 4,741,546 instruction 4, page 311.) 1,994,214 8 Less Energy for Pumping 9 Net Generation (Enter Total of lines 3 625,309 instruction 4, page 311.) 5 Hydro-Conventional 7 Other 27,584,533 Interdepartmental Sales) Page 401a 1,219,754 34,226,903 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission MONTHLY PEAKS AND OUTPUT Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. 2. Report in column (b) by month the system’s output in Megawatt hours for each month. 3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. 4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. 5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d). NAME OF SYSTEM: Line No. Month (a) Total Monthly Energy (b) Monthly Non-Requirments Sales for Resale & Associated Losses (c) MONTHLY PEAK Megawatts (See Instr. 4) (d) Day of Month (e) Hour (f) 29 January 2,382,100 295,165 3,977 10 800 30 February 2,255,546 459,726 3,988 4 800 31 March 2,295,330 504,896 3,604 25 2000 32 April 2,082,047 312,228 4,445 21 1800 33 May 2,459,457 299,571 5,740 27 1700 34 June 2,837,244 282,862 6,469 30 1800 35 July 3,172,066 404,974 7,188 23 1800 36 August 3,354,707 664,167 6,613 17 1800 37 September 3,338,770 650,235 6,249 2 1700 38 October 3,712,515 418,647 4,593 4 1700 39 November 2,916,087 218,732 3,530 6 1900 40 December 3,421,034 356,722 4,148 31 1900 34,226,903 4,867,925 41 TOTAL FERC FORM NO. 1 (ED. 12-90) Page 401b 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 401 Line No.: 29 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 29 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 30 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 30 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 31 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 31 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 32 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 32 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 33 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 33 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 34 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 34 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 35 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 35 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 36 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 36 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 37 Column: b Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. Schedule Page: 401 Line No.: 37 Column: d Loads adjusted from previously reported to reflect total BAA load rather than an adjusted APS load in BAA. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item Plant Name: Cholla 1 (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: (b) Coal Tons 449748 9264 40.624 41.546 2.242 0.024 0.000 Page 402 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoor 1962 1981 113.60 116 8152 0 116 116 44 787283616 1403949 19831250 141391351 0 162626550 1431.5717 881642 18706859 0 2826179 0 0 493776 950539 0 316732 1249479 320134 4365478 2059283 1358541 33528642 0.0426 Gas MCF 3099 856825 6.345 7.262 8.475 0.090 0.000 (c) 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 Total 0 0 0.000 0.000 2.244 0.024 10588.328 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2014/Q4 End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item Plant Name: (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: Four Corners 1 (c) (b) Steam Over 50% Outdoor 1963 1970 190.10 0 0 0 0 0 47 0 0 0 0 0 0 0.0000 86383 -605695 0 6350 0 0 -2791 214411 193510 0 -862 1587 54942 3982 -57160 -105343 0.0000 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 Total 0 0 0.000 0.000 2.275 0.024 10643.108 Page 402.1 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: Four Corners 5 (b) Coal Tons 1355789 8848 52.487 54.976 3.107 0.031 0.000 Page 402.2 Plant Name: Ocotillo 1 (c) Steam Over 50% Outdoor 1969 1970 515.40 494 5790 0 485 485 27 2445267195 36571 9546451 121088462 1509233 132180717 256.4624 1748398 75993888 0 6287698 0 0 678776 3695460 339347 983757 1230891 811058 14929236 4100933 4336480 115135922 0.0471 Gas Total Gas MCF MCF 121744 0 575984 1024798 0 1028478 10.213 0.000 4.551 11.967 0.000 5.332 11.677 3.151 5.184 0.115 0.031 0.064 0.000 9862.311 0.000 Steam Over 50% Outdoor 1960 1960 113.60 104 1032 0 110 110 11 48010000 152946 2360181 27042987 0 29556114 260.1771 0 3071016 0 236061 0 0 813897 179826 0 19315 0 299586 199142 535031 107213 5461087 0.1137 Total 0 0 0.000 0.000 5.184 0.064 12338.825 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2014/Q4 End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item Plant Name: Navajo (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: Yucca 1 (b) Coal Tons 928756 10764 46.722 49.555 2.302 0.023 0.000 Page 402.3 Steam Units 1,2,3 Over 50% Outdoor 1974 1976 337.34 326 24627 0 315 315 0 1980916002 25111 32680219 236111030 1865912 270682272 802.4019 5076447 46640878 0 2178252 0 0 1010915 1257225 85176 0 1159809 323702 5208118 1911128 1005640 65857290 0.0332 Oil Total Oil Bbls Bbls 3342 0 0 136837 0 0 137.244 0.000 0.000 184.422 0.000 0.000 32.089 2.330 0.000 0.324 0.024 0.000 0.000 10103.451 0.000 (c) Comb. Turbine Over 50% Outdoor 1971 2008 23.60 19 70 0 19 0 1 921000 33986 561297 2867486 0 3462769 146.7275 0 94182 0 0 0 0 196696 0 0 0 0 164 0 58329 761 350132 0.3802 Gas MCF 15057 1032676 4.567 6.255 6.057 0.102 0.000 0 0 0.000 0.000 6.057 0.102 16882.736 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2014/Q4 End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item Plant Name: Yucca 5 (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: Yucca 6 (b) Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Page 402.4 Comb. Turbine Over 50% Outdoor 2007 2008 60.50 48 2153 0 48 0 2 69035000 13711 1240218 35902987 0 37156916 614.1639 585413 4490384 0 0 0 0 0 46139 0 0 0 12318 0 480124 291875 5906253 0.0856 Gas Total Oil MCF Bbls 754275 0 0 1039923 0 0 4.347 0.000 0.000 5.953 0.000 0.000 5.725 5.725 0.000 0.065 0.065 0.000 0.000 11362.179 0.000 (c) Comb. Turbine Over 50% Outdoor 2007 2008 60.50 48 2416 0 48 0 1 80621000 0 1233294 35558664 0 36791958 608.1315 0 5199496 0 0 0 0 0 379567 0 0 0 31259 0 186599 15642 5812563 0.0721 Total Gas MCF 806872 1038285 4.705 6.444 6.206 0.064 0.000 0 0 0.000 0.000 6.206 0.064 10391.374 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item Plant Name: Saguaro 3 (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: Ocotillo 1 (c) (b) Comb. Turbine Over 50% Outdoor 2002 2002 78.30 75 180 0 79 0 0 8812000 0 530985 28940760 0 29471745 376.3952 0 784401 0 0 0 0 14029 0 0 0 0 13884 0 209708 0 1022022 0.1160 Gas MCF 118425 1091619 4.836 6.624 6.068 0.089 0.000 Page 402.5 Total 0 0 0.000 0.000 6.068 0.089 14670.336 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoor 1972 1973 53.10 52 167 0 55 0 2 868000 0 650111 23118477 0 23768588 447.6194 0 133450 0 0 0 0 200464 67268 0 0 677 22995 0 176170 40577 641601 0.7392 Gas MCF 18055 1029576 5.397 7.391 7.179 0.154 0.000 Total 0 0 0.000 0.000 7.179 0.154 21415.899 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item Plant Name: Sundance (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: West Phoenix 1 (c) (b) Comb. Turbine Over 50% Outdoor 2002 2002 605.00 447 1997 0 420 0 18 52865000 681252 13415221 270271331 0 284367804 470.0294 0 3512980 0 0 0 0 561179 2852543 0 0 0 270456 0 2469290 20009 9686457 0.1832 Gas MCF 562713 1017346 4.558 6.243 6.136 0.066 0.000 Page 402.6 Total 0 0 0.000 0.000 6.136 0.066 10828.979 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoor 1976 2003 132.00 160 2061 0 88 0 3 67213910 3943 2950076 44679933 0 47633952 360.8633 127274 5834692 0 0 0 0 0 0 0 0 1166 8334 0 796796 417143 7185405 0.1069 Gas MCF 851490 1029955 5.003 6.852 6.653 0.087 0.000 Total 0 0 0.000 0.000 6.653 0.087 13047.835 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2014/Q4 End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: West Phoenix 5 (b) Plant Name: Redhawk 1 (c) Combined Cycle Over 50% Outdoor 2003 2003 569.60 509 7917 0 506 0 32 1336643000 18896 14714269 266016847 0 280750012 492.8898 2531022 65317220 0 0 0 0 3024138 2936201 0 0 23196 210991 0 3333317 997045 78373130 0.0586 Gas MCF 10532380 1030516 6.428 8.804 8.543 0.069 0.000 Page 402.7 Total 0 0 0.000 0.000 8.543 0.069 8102.117 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoor 2002 2002 573.10 551 14540 0 492 0 27 1543743000 1178266 13460847 292857101 0 307496214 536.5490 29848 75254055 0 0 0 0 1847977 2508111 0 0 164481 70784 0 10489493 1020904 91385653 0.0592 Gas MCF 11279910 1032274 4.871 6.672 6.463 0.049 0.000 Total 0 0 0.000 0.000 6.463 0.049 7551.879 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) Plant Name: Palo Verde 3 (b) Plant Name: (c) Nuclear Under 50% Outdoor 1988 1988 410.82 396 8760 0 382 0 205 3369526799 1620068 299414126 753848097 -21910663 1032971628 2514.4142 8600334 30300762 4106715 2731336 0 0 3009886 10604717 15125625 0 1304444 606758 1443209 3335341 972230 82141357 0.0244 Nuclear Kg Uranium 526 66700 0.000 57623.931 1.037 0.009 8672.000 Page 402.8 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned. Line No. Item Plant Name: Plant Name: (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Kind of Plant (Internal Comb, Gas Turb, Nuclear Type of Constr (Conventional, Outdoor, Boiler, etc) Year Originally Constructed Year Last Unit was Installed Total Installed Cap (Max Gen Name Plate Ratings-MW) Net Peak Demand on Plant - MW (60 minutes) Plant Hours Connected to Load Net Continuous Plant Capability (Megawatts) When Not Limited by Condenser Water When Limited by Condenser Water Average Number of Employees Net Generation, Exclusive of Plant Use - KWh Cost of Plant: Land and Land Rights Structures and Improvements Equipment Costs Asset Retirement Costs Total Cost Cost per KW of Installed Capacity (line 17/5) Including Production Expenses: Oper, Supv, & Engr Fuel Coolants and Water (Nuclear Plants Only) Steam Expenses Steam From Other Sources Steam Transferred (Cr) Electric Expenses Misc Steam (or Nuclear) Power Expenses Rents Allowances Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Boiler (or reactor) Plant Maintenance of Electric Plant Maintenance of Misc Steam (or Nuclear) Plant Total Production Expenses Expenses per Net KWh Fuel: Kind (Coal, Gas, Oil, or Nuclear) Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Quantity (Units) of Fuel Burned Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) Avg Cost of Fuel/unit, as Delvd f.o.b. during year Average Cost of Fuel per Unit Burned Average Cost of Fuel Burned per Million BTU Average Cost of Fuel Burned per KWh Net Gen Average BTU per KWh Net Generation FERC FORM NO. 1 (REV. 12-03) (b) (c) 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 Page 402.9 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Cholla 2 Plant Name: (d) Coal Tons 973934 9251 40.676 41.564 2.246 0.025 0.000 Oil Bbls 1541 127357 170.804 237.377 44.378 0.491 0.000 Plant Name: Cholla 3 (e) Steam Over 50% Outdoor 1978 1981 288.90 250 7681 0 260 260 49 1630435524 2 24 237 0 263 0.0009 1519307 40840539 0 4919509 0 0 474873 1451126 0 655941 1631068 605858 6481771 333723 1537608 60451323 0.0371 Gas MCF 0 0 0.000 0.000 0.000 0.000 0.000 FERC FORM NO. 1 (REV. 12-03) Line No. (f) 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 Total 0 0 0.000 0.000 2.265 0.025 11057.668 0 0 0.000 0.000 0.000 0.000 0.000 Page 403 0 0 0.000 0.000 0.000 0.000 0.000 Coal Tons 907329 9249 40.677 41.418 2.239 0.024 0.000 Oil Bbls 3025 126626 164.895 218.454 41.076 0.437 0.000 Steam Over 50% Outdoor 1980 1981 312.30 267 7131 0 271 271 51 1578410285 3944787 56024112 397027603 0 456996502 1463.3253 1411851 38218706 0 4617511 0 0 439170 1367917 0 635011 1470963 590686 4458585 2881387 1900745 57992532 0.0367 Gas MCF 0 0 0.000 0.000 0.000 0.000 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Four Corners 2 (d) Plant Name: Four Corners 3 (e) Steam Over 50% Outdoor 1963 1970 190.10 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 16197 -704440 0 6350 0 0 -2791 -8477 193510 0 -862 2093 58694 4038 -47585 -483273 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Plant Name: Four Corners 4 (f) Steam Over 50% Outdoor 1964 1970 253.40 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 68732 -844459 0 6352 0 0 -2791 -8577 193510 0 -863 1604 66009 4663 -31020 -546840 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Page 403.1 0 0 0.000 0.000 0.000 0.000 0.000 Coal Tons 1748253 8754 48.797 51.160 2.922 0.029 0.000 Gas MCF 263186 1023763 4.369 5.119 5.001 0.049 0.000 Line No. Steam Over 50% Outdoor 1969 1970 515.40 498 7019 0 485 485 26 3129078765 27475 10839779 86934462 1502055 99303771 192.6732 2203623 90788400 0 6437419 0 0 678777 3769650 339347 1258861 1230891 840613 15305267 1762041 4582172 129197061 0.0413 Total 0 0 0.000 0.000 2.940 0.029 9867.811 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Ocotillo 2 Plant Name: Saguaro 1 (d) Plant Name: Saguaro 2 (e) Steam Over 50% Outdoor 1960 1960 113.60 111 545 0 110 110 11 26235000 138638 2444337 27107789 0 29690764 261.3624 0 1668580 0 128995 0 0 814290 98266 0 10555 0 0 298185 563715 58368 3640954 0.1388 Gas MCF 304039 1029315 4.684 5.488 5.332 0.064 0.000 Total 0 0 0.000 0.000 5.332 0.064 11928.797 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Line No. (f) Steam Over 50% Outdoor 1954 1955 125.00 0 0 0 0 0 0 0 8097 0 0 0 8097 0.0648 3941 0 0 0 0 0 2705 197522 0 0 1241 1182 2515 60 824592 1033758 0.0000 Gas Total 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Page 403.2 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoor 1955 1955 125.00 0 0 0 0 0 0 0 8097 0 0 0 8097 0.0648 3941 0 0 0 0 0 2705 0 0 0 1241 1182 0 60 0 9129 0.0000 Gas Total 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Yucca 2 Plant Name: Yucca 3 (d) Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Gas MCF 5275 1033934 4.966 6.801 6.578 0.106 0.000 Plant Name: Yucca 4 (e) Comb. Turbine Over 50% Outdoor 1971 2008 23.60 19 24 0 19 0 1 340000 0 431199 2574060 0 3005259 127.3415 0 35876 0 0 0 0 65481 0 0 0 0 61 0 180686 0 282104 0.8297 Total FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 6.578 0.106 16041.176 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Gas MCF 113212 1037735 5.110 6.999 6.744 0.117 0.000 Line No. (f) Comb. Turbine Over 50% Outdoor 1973 2008 72.40 50 357 0 55 0 2 6777000 0 714124 14076555 0 14790679 204.2911 0 1141709 0 0 0 0 29249 0 0 0 65 1209 0 347605 1018 1520855 0.2244 Total Page 403.3 0 0 0.000 0.000 9.718 0.168 17335.694 Oil Bbls 783 138189 0.000 0.000 0.000 0.000 0.000 Gas MCF 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoor 1974 2008 72.40 50 13 0 54 0 1 378000 0 596333 7587025 0 8183358 113.0298 0 0 0 0 0 0 8278 3366 0 0 0 67 0 80184 0 91895 0.2431 Total 0 0 0.000 0.000 0.000 0.000 12022.451 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Douglas Plant Name: Saguaro 1 (d) Plant Name: Saguaro 2 (e) Comb. Turbine Over 50% Outdoor 1972 1972 26.10 16 28 0 16 0 0 289000 9557 103952 7072606 0 7186115 275.3301 0 121205 0 0 0 0 0 3328 0 0 -15 2000 0 914932 23465 1064915 3.6848 Oil Bbls 1035 138385 117.106 117.106 20.148 0.419 0.000 Total 0 0 0.000 0.000 20.148 0.419 20815.219 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Line No. (f) Comb. Turbine Over 50% Outdoor 1972 2002 53.10 54 40 0 55 0 0 1481000 0 768872 12911663 0 13680535 257.6372 0 161635 0 0 0 2358 61791 0 0 0 0 2333 0 1002666 14884 1245667 0.8411 Gas MCF 37923 1044300 3.112 4.262 4.081 0.000 0.000 Total 0 0 0.000 0.000 4.081 0.109 26740.716 Page 403.4 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoor 1973 2002 53.10 50 24 0 55 0 0 679000 0 1365782 10404132 0 11769914 221.6556 0 89178 0 0 0 0 1081 61791 0 0 0 1070 0 56239 36309 245668 0.3618 Gas MCF 17764 1043965 3.665 5.020 4.809 0.131 0.000 Total 0 0 0.000 0.000 4.809 0.131 27312.224 0 0 0.000 0.000 0.000 0.000 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Ocotillo 2 Plant Name: West Phoenix 1 (e) (d) Comb. Turbine Over 50% Outdoor 1973 1973 53.10 58 452 0 55 0 3 812000 0 859908 19761752 0 20621660 388.3552 0 125494 0 0 0 0 199475 36758 0 0 0 12566 0 195295 0 569588 0.7015 Gas MCF 17436 1030913 5.255 7.197 6.982 0.155 0.000 Total 0 0 0.000 0.000 6.982 0.155 22136.700 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Plant Name: West Phoenix 2 (f) Comb. Turbine Over 50% Outdoor 1972 1973 53.10 53 108 0 55 0 1 764000 6294 1016483 17827901 0 18850678 355.0034 79548 91691 0 0 0 0 44203 0 0 0 0 0 0 25694 80292 321428 0.4207 Gas MCF 13126 1032531 5.100 6.985 6.765 0.120 0.000 Total 0 0 0.000 0.000 6.765 0.120 17739.529 Page 403.5 0 0 0.000 0.000 0.000 0.000 0.000 Line No. Comb. Turbine Over 50% Outdoor 1973 1973 53.10 60 21 0 55 0 1 781000 0 633181 19826543 0 20459724 385.3055 81318 74988 0 0 0 0 45187 0 0 0 0 6572 0 91116 -26054 273127 0.3497 Gas MCF 13941 1033283 3.927 5.379 5.206 0.096 0.000 Total 0 0 0.000 0.000 5.206 0.096 18444.302 0 0 0.000 0.000 0.000 0.000 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: West Phoenix 2 (d) Plant Name: West Phoenix 3 (e) Combined Cycle Over 50% Outdoor 1976 2003 132.00 0 1866 0 88 0 2 60751710 3826 2448179 43765364 0 46217369 350.1316 115037 5327988 0 0 0 0 0 0 0 0 1054 7533 0 552009 189170 6192791 0.1019 Gas MCF 791101 1029911 4.917 6.735 6.539 0.088 0.000 Total 0 0 0.000 0.000 6.539 0.088 13411.376 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Plant Name: West Phoenix 4 (f) Combined Cycle Over 50% Outdoor 1976 2003 132.00 88 1313 0 88 0 2 70453530 4572 4268571 52411795 0 56684938 429.4313 133408 4914290 0 0 0 0 0 0 0 0 1223 8990 0 586833 294419 5939163 0.0843 Gas MCF 688749 1030072 5.210 7.135 6.927 0.070 0.000 Total 0 0 0.000 0.000 6.927 0.070 10069.914 Page 403.6 0 0 0.000 0.000 0.000 0.000 0.000 Line No. Combined Cycle Over 50% Outdoor 2001 2003 135.60 184 1006 0 117 0 10 76853000 32909 5499674 77964394 0 83496977 615.7594 649941 4345818 0 0 0 0 519620 0 0 0 1334 9529 0 3058512 124492 8709246 0.1133 Gas MCF 744566 1029337 4.262 5.837 5.670 0.057 0.000 Total 0 0 0.000 0.000 5.670 0.057 9972.402 0 0 0.000 0.000 0.000 0.000 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Redhawk 2 Plant Name: Palo Verde 1 (e) (d) Combined Cycle Over 50% Outdoor 2002 2002 567.20 548 20643 0 492 0 14 2140739000 1006514 10713739 243321784 0 255042037 449.6510 41390 102552967 0 0 0 0 1879375 3478047 0 0 164480 98158 0 2142972 1429141 111786530 0.0522 Gas MCF 15890970 1034637 4.712 6.454 6.235 0.048 0.000 Total 0 0 0.000 0.000 6.235 0.048 8946.837 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Plant Name: Palo Verde 2 (f) Nuclear Under 50% Outdoor 1986 1988 410.82 395 7943 0 382 0 233 3011940365 1728842 304753009 818766176 -16921025 1108327002 2697.8409 8695579 26350435 4105482 3479445 0 0 3010465 10938853 15121088 0 2875226 1000518 5887379 6360913 1404776 89230159 0.0296 Nuclear Kg Uranium 457 66708 2978.592 57623.931 0.836 0.009 10459.208 0 0 0.000 0.000 0.000 0.000 0.000 Page 403.7 0 0 0.000 0.000 0.000 0.000 0.000 Line No. Nuclear Under 50% Outdoor 1986 1988 410.82 402 7903 0 382 0 231 3024683772 1068880 184967293 513170123 -14828531 684377765 1665.8823 8594533 27082627 4105482 3548284 0 0 2586171 12103617 15121088 0 3912467 770231 5174405 6129852 1294808 90423565 0.0299 Nuclear Kg Uranium 470 66706 3045.621 57623.931 0.808 0.009 11077.393 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Plant Name: (d) Plant Name: (e) (f) 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Line No. 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Page 403.8 0 0 0.000 0.000 0.000 0.000 0.000 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2014/Q4 STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Plant Name: Plant Name: (d) Plant Name: (e) (f) 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Line No. 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Page 403.9 0 0 0.000 0.000 0.000 0.000 0.000 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 402.1 Line No.: -1 Column: c Four Corners Units 1 - 3 began shutdown operations December 30, 2013 Schedule Page: 403.1 Line No.: -1 Column: d Four Corners Units 1 - 3 began shutdown operations December 30, 2013 Schedule Page: 403.1 Line No.: -1 Column: e Four Corners Units 1 - 3 began shutdown operations December 30, 2013 Schedule Page: 403.2 Line No.: -1 Column: e Saguaro steam plants were retired effective June 30, 2013 Schedule Page: 403.2 Line No.: -1 Column: f Saguaro steam plants were retired effective June 30, 2013 Schedule Page: 402.6 Line No.: 5 Column: b Sundance: Generator Name Plate Rating is 605 MW at 15 degrees C and 0.85 Power Factor. Plant Output is limited by gas turbine. Schedule Page: 403.7 Line No.: 1 Column: e The Palo Verde Nuclear Units have pressurized water reactors. The nuclear fuel assemblies in the reactors contain enriched uranium. The cost of nuclear fuel is amortized to fuel expense (acct. 518) based on the fuel burns, or quantity of heat, produced in the generation of energy. Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from the reactors. Additional information on APS' nuclear fuel program and nuclear decommissioning is detailed in the Notes to Consolidated Financial Statements. Schedule Page: 403.7 Line No.: 1 Column: f The Palo Verde Nuclear Units have pressurized water reactors. The nuclear fuel assemblies in the reactors contain enriched uranium. The cost of nuclear fuel is amortized to fuel expense (acct. 518) based on the fuel burns, or quantity of heat, produced in the generation of energy. Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from the reactors. Additional information on APS' nuclear fuel program and nuclear decommissioning is detailed in the Notes to Consolidated Financial Statements. Schedule Page: 402.8 Line No.: 1 Column: b The Palo Verde Nuclear Units have pressurized water reactors. The nuclear fuel assemblies in the reactors contain enriched uranium. The cost of nuclear fuel is amortized to fuel expense (acct. 518) based on the fuel burns, or quantity of heat, produced in the generation of energy. Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from the reactors. Additional information on APS' nuclear fuel program and nuclear decommissioning is detailed in the Notes to Consolidated Financial Statements. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) 1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number. 3. If net peak demand for 60 minutes is not available, give that which is available specifying period. 4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant. Line No. Item (a) FERC Licensed Project No. Plant Name: (b) FERC Licensed Project No. Plant Name: (c) 0 0 1 Kind of Plant (Run-of-River or Storage) 2 Plant Construction type (Conventional or Outdoor) 3 Year Originally Constructed 4 Year Last Unit was Installed 0.00 0.00 6 Net Peak Demand on Plant-Megawatts (60 minutes) 5 Total installed cap (Gen name plate Rating in MW) 0 0 7 Plant Hours Connect to Load 0 0 8 Net Plant Capability (in megawatts) 9 (a) Under Most Favorable Oper Conditions 0 0 10 (b) Under the Most Adverse Oper Conditions 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - Kwh 0 0 13 Cost of Plant 14 Land and Land Rights 0 0 15 Structures and Improvements 0 0 16 Reservoirs, Dams, and Waterways 0 0 17 Equipment Costs 0 0 18 Roads, Railroads, and Bridges 0 0 19 Asset Retirement Costs 0 0 20 TOTAL cost (Total of 14 thru 19) 0 0 21 Cost per KW of Installed Capacity (line 20 / 5) 0.0000 0.0000 22 Production Expenses 23 Operation Supervision and Engineering 0 0 24 Water for Power 0 0 25 Hydraulic Expenses 0 0 26 Electric Expenses 0 0 27 Misc Hydraulic Power Generation Expenses 0 0 28 Rents 0 0 29 Maintenance Supervision and Engineering 0 0 30 Maintenance of Structures 0 0 31 Maintenance of Reservoirs, Dams, and Waterways 0 0 32 Maintenance of Electric Plant 0 0 33 Maintenance of Misc Hydraulic Plant 0 0 34 Total Production Expenses (total 23 thru 33) 0 0 0.0000 0.0000 35 Expenses per net KWh FERC FORM NO. 1 (REV. 12-03) Page 406 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2014/Q4 End of HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." 6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment. FERC Licensed Project No. Plant Name: (d) FERC Licensed Project No. Plant Name: (e) 0 0 FERC Licensed Project No. Plant Name: (f) 0 Line No. 1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0 0 0 18 0 0 0 19 20 0 0 0 0.0000 0.0000 0.0000 21 22 FERC FORM NO. 1 (REV. 12-03) 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 Page 407 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) 1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. 3. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each plant. 5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Line No. Item FERC Licensed Project No. Plant Name: (b) (a) 1 Type of Plant Construction (Conventional or Outdoor) 2 Year Originally Constructed 3 Year Last Unit was Installed 4 Total installed cap (Gen name plate Rating in MW) 5 Net Peak Demaind on Plant-Megawatts (60 minutes) 6 Plant Hours Connect to Load While Generating 7 Net Plant Capability (in megawatts) 8 Average Number of Employees 9 Generation, Exclusive of Plant Use - Kwh 10 Energy Used for Pumping 11 Net Output for Load (line 9 - line 10) - Kwh 12 Cost of Plant 13 Land and Land Rights 14 Structures and Improvements 15 Reservoirs, Dams, and Waterways 16 Water Wheels, Turbines, and Generators 17 Accessory Electric Equipment 18 Miscellaneous Powerplant Equipment 19 Roads, Railroads, and Bridges 20 Asset Retirement Costs 21 Total cost (total 13 thru 20) 22 Cost per KW of installed cap (line 21 / 4) 23 Production Expenses 24 Operation Supervision and Engineering 25 Water for Power 26 Pumped Storage Expenses 27 Electric Expenses 28 Misc Pumped Storage Power generation Expenses 29 Rents 30 Maintenance Supervision and Engineering 31 Maintenance of Structures 32 Maintenance of Reservoirs, Dams, and Waterways 33 Maintenance of Electric Plant 34 Maintenance of Misc Pumped Storage Plant 35 Production Exp Before Pumping Exp (24 thru 34) 36 Pumping Expenses 37 Total Production Exp (total 35 and 36) 38 Expenses per KWh (line 37 / 9) FERC FORM NO. 1 (REV. 12-03) Page 408 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report End of 2014/Q4 PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued) 6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. 7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract. FERC Licensed Project No. Plant Name: (c) FERC Licensed Project No. Plant Name: (d) FERC Licensed Project No. Plant Name: (e) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 FERC FORM NO. 1 (REV. 12-03) Page 409 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 (2) X A Resubmission GENERATING PLANT STATISTICS (Small Plants) 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of 1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote. Net Peak Year Installed Capacity Net Generation Line Demand Orig. Name Plate Rating Cost of Plant Name of Plant Excluding MW Const. Plant Use (In MW) No. (60 min.) (e) (f) (a) (b) (c) (d) 1 Solar Plants 2 Flagstaff 1997 0.45 139 2,566,632 3 Star 1998 0.19 347 1,598,086 4 Tempe 1998 5 Glendale Airport 1999 0.07 107 114,593 6 Gilbert 2001 0.12 237 56,928 0.29 589 557,305 353 550,117 12,817 7 Scottsdale Covered Parking 1999 8 Municipal Rooftops 1999 9 Yuma 2002 0.17 10 Prescott Earu 2002 0.18 432 162,310 11 Prescott 2001 2.71 4,926 2,316,079 51,361 12 Red Rock 2005 13 Phoenix 1998 0.09 114 29,053 14 Hyder Phase 1 & 2 2011 16.00 41,990 73,340,993 15 Hyder II 2013 14.00 42,821 51,811,899 16 Cotton Center 2011 17.00 43,648 80,506,726 17 Paloma 2011 17.00 40,298 66,071,021 18 US Airways Center 2011 0.18 273 1,350,091 19 Chase Field 2011 0.06 84 1,477,062 20 Chino Valley 2012 19.00 47,090 86,991,993 21 Foothills 1 & 2 2012 35.00 113,417 143,313,165 22 APS Solar for Schools 2012 13.12 25,116 59,332,100 23 DVN1 2013 0.02 44 24 Palo Verde Emergengy OPS Center 2013 0.03 68 25 Gila Bend Phase 1 2014 16.00 31,509 26 Gila Bend Phase 2 2014 27 Total Solar Operation/Maintenance 16.00 32,237 167.69 425,840 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 FERC FORM NO. 1 (REV. 12-03) Page 410 110,142,135 682,352,466 This Report Is: Name of Respondent Date of Report Year/Period of Report (Mo, Da, Yr) 2014/Q4 End of Arizona Public Service Company 04/15/2015 (2) X A Resubmission GENERATING PLANT STATISTICS (Small Plants) (Continued) 3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant. 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Plant Cost (Incl Asset Retire. Costs) Per MW (g) Operation Exc'l. Fuel (h) Production Expenses Fuel (i) Maintenance (j) Kind of Fuel (k) Fuel Costs (in cents Line (per Million Btu) No. (l) 1 5,669,357 2 8,355,601 3 3,814,586 4 1,598,678 5 494,169 6 1,949,708 7 8 3,316,196 9 880,587 10 853,236 11 12 324,018 13 4,583,812 14 3,700,850 15 4,735,690 16 3,886,531 17 7,418,737 18 23,383,072 19 4,578,526 20 4,094,662 21 4,523,417 22 23 24 6,883,883 25 26 4,069,184 2,817,159 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 FERC FORM NO. 1 (REV. 12-03) Page 411 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 FOOTNOTE DATA Schedule Page: 410 Line No.: 1 Column: a Solar is not required to be reported on these pages but we are choosing to report it here. Schedule Page: 410 Line No.: 12 Column: a Red Rock was decommissioned on 04/30/13. Schedule Page: 410 Line No.: 27 Column: a O&M Expenses for Solar Plants are not broken out by plant or between Operations and Maintenance. FERC FORM NO. 1 (ED. 12-87) Page 450.1 2014/Q4 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION LINE STATISTICS Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. DESIGNATION Line No. From (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 PALO VERDE PALO VERDE FOUR CORNERS NAVAJO PLANT NAVAJO PLANT MOENKOPI CHOLLA PALO VERDE PALO VERDE WESTWING MEAD KYRENE/PALO VERDE GILA RIVER PALO VERDE PALO VERDE MORGAN WESTWING FOUR CORNERS YAVAPAI WESTWING CHOLLA PLANT LIBERTY LIBERTY LIBERTY COCONINO VERDE ROUND VALLEY PINNACLE PEAK EL SOL AGUA FRIA OCOTILLO PLANT OCOTILLO PLANT OCOTILLO PLANT OCOTILLO PLANT LINCOLN STREET VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 345.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 KYRENE WESTWING #2 COLORADO RIVER WESTWING MOENKOPI WESTWING SAGUARO WESTWING NORTH GILA MEAD MARKET PLACE JOJOBA SUB JOJOBA SWITCHYARD RUDD HASSAYAMPA PINNACLE PEAK DUGAS LOOP PINNACLE PEAK TAP IN & OUT EL SOL FLAGSTAFF GILA BEND GILA BEND GILA BEND VERDE WILLOW LAKE SELIGMAN OCOTILLO AGUA FRIA GRAND TERMINAL LINCOLN STREET LINCOLN STREET SRP TAP KYRENE SUB 68TH ST & SALT RIVER WEST PHOENIX PLANT Designed (d) 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 345.00 230.00 345.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 (3) STEEL (A) (3) STEEL (A) (3) STEEL (3) STEEL (A) (3) STEEL (A) (3) STEEL (A) (3) STEEL (3) STEEL (A) (3) STEEL (A) (3) STEEL (A) (3) STEEL (A) (3) STEEL (3) STEEL (3) STEEL (A) (3) STEEL (A) (3) STEEL (A) (3) STEEL (3) STEEL (C) (1) STEEL (3) STEEL (D) (2) WOOD (3) STEEL (D) (1) WOOD (2) WOOD (2) WOOD (2) WOOD (2) WOOD (3) STEEL (3) STEEL (1) STEEL (3) STEEL (4) U.G. (1) STEEL (3) STEEL (3) STEEL TOTAL 36 FERC FORM NO. 1 (ED. 12-87) LENGTH (Pole miles) (In the case of underground lines report circuit miles) Supporting On Structure On Structures of Another of Line Structure Line Designated (e) (g) (f) Type of Page 422 74.80 45.00 366.00 256.00 76.00 180.00 206.00 47.00 120.00 242.70 13.30 0.25 18.50 35.68 27.00 566.00 1.30 3.10 6.00 12.00 12.77 88.14 6.00 12.00 28.00 32.68 34.30 36.19 51.20 5.65 10.02 10.30 1.00 6.50 10.30 (h) 1 1 1 1 1 1 1 1 1 1 1 1 2 1 1 1 1 2 2 1 1 1 1 1 1 1 1 2 1 1 2 1.60 2 1 1 881.15 80 5.50 5,054.11 Number Of Circuits Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION LINE STATISTICS Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. DESIGNATION Line No. From (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 SANTA ROSA PINNACLE PEAK-OCOTILLO PINNACLE PEAK/LONE PINNACLE PEAK/LONE GILA BEND/LIBERTY SRP-PINNACLE PEAK LINCOLN STREET SUNNYSLOPE GRAND TERMINAL SANTA ROSA CASA GRANDE CASA GRANDE WESTWING-EL SOL DEER VALLEY PINNACLE PEAK OCOTILLO ROUND VALLEY/SELIGMAN WHITE TANKS EL SOL PINNACLE PEAK MEADOWBROOK MEADOWBROOK RUDD PALO VERDE PALO VERDE MORGAN TUBA CITY TAP SAGUARO PLANT ORACLE ADAMS SANTA ROSA ASARCO ASARCO WILLOW LAKE UNDERGROUND VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 69.00 115.00 115.00 115.00 115.00 115.00 115.00 115.00 69.00 SAGUARO PLANT CACTUS SUB TAP REACH SUB TAP REACH SUB PANDA SWITCHYARD DEER VALLEY TAP COUNTRY CLUB COUNTRY CLUB COUNTRY CLUB CASA GRANDE SAGUARO SAGUARO SURPRISE ALEXANDER SUNNYSLOPE SANTA ROSA FORT ROCK WEST PHOENIX WHITE TANKS LONE PEAK SUNNYSLOPE COUNTRY CLUB LIBERTY NORTH GILA TAP KYRENE TAP RACEWAY TAP POWELL SUB SAN MANUEL SAN MANUEL MURAL ASARCO VISTA VISTA BAGDAD Designed (d) 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 115.00 115.00 115.00 115.00 115.00 115.00 69.00 (2) WOOD (1) STEEL (1) STEEL (4) U.G. (1) STEEL (1) STEEL (4) U.G. (4) U.G. (4) U.G. (2) WOOD (1) WOOD (2) WOOD (1) STEEL (1) STEEL (1) STEEL (2) WOOD (2) WOOD (1) STEEL (3) STEEL (3) STEEL (4) U.G. (4) U.G. (1) STEEL (1) STEEL (1) STEEL (3) STEEL (2) WOOD (2) WOOD (2) WOOD (2) WOOD (2) WOOD (2) WOOD (1) WOOD (2) WOOD TOTAL 36 FERC FORM NO. 1 (ED. 12-87) LENGTH (Pole miles) (In the case of underground lines report circuit miles) Supporting On Structure On Structures of Another of Line Structure Line Designated (e) (g) (f) Type of Page 422.1 61.50 3.20 0.12 0.63 0.25 3.30 3.50 7.50 2.50 14.95 6.74 38.97 11.25 7.60 16.70 36.30 1.67 12.00 9.00 11.90 0.16 0.17 20.48 3.30 3.30 0.75 60.00 41.50 21.06 47.15 11.00 3.81 3.02 49.00 29.35 5,054.11 Number Of Circuits (h) 1 2 1 1 1 2 1 1 1 1 1 1 1 1 1 1 1 2 1 1 1 1 1 2 2 1 1 1 1 1 1 1 1 1 881.15 80 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION LINE STATISTICS Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. DESIGNATION Line No. From (a) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 69.00 OVERHEAD RELATED TRANSMISSION EHV STRUCTURES TEMP. LIMITED TERM LAND Designed (d) 69.00 TOTAL 36 FERC FORM NO. 1 (ED. 12-87) LENGTH (Pole miles) (In the case of underground lines report circuit miles) Supporting On Structure On Structures of Another of Line Structure Line Designated (e) (g) (f) Type of Page 422.2 Number Of Circuits (h) 2,710.63 1.64 30.58 1 5,054.11 881.15 80 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material (i) 1780 ACSR 1780 ACSR 2156 ACSR 2156 ACSR 2156 ACSR 2156 ACSR 2156 ACSR 1780 ACSR 2156 ACSR 1590 KCM 1590 KCM 954 ACSR 1780 ACSR 1780 ACSR 1780 ACSR 1780 ACSR 2156 ACSR 795 ACSR 954 ACSR 795 ACSR 795 ACSR 1272 ACSR 1272 ACSR 1272 ACSR 795 ACSR 795 ACSR 795 ACSR 795 AA 1431 AA 1361 ACAR 1431 AA 2000 KC 954 ACSR 954A/1113A 1113 AA EXPENSES, EXCEPT DEPRECIATION AND TAXES Land rights, and clearing right-of-way) Land Construction and Other Costs (k) (j) 4,014,277 Total Cost Operation Expenses (m) (l) 19,901,128 5,971,160 39,917,113 8,679,359 1,208,159 5,913,084 60,305,880 5,151,452 4,825,369 17,090,839 626,769 23,915,405 5,971,160 42,238,623 9,175,481 1,208,159 6,216,320 61,965,910 5,159,974 5,320,230 18,266,519 677,379 37,261 29,540,970 776,503 32,504,392 3,178,473 30,653,417 947,577 3,424,030 3,681,055 2,540,948 1,358,866 3,309,278 3,135,075 3,254,748 2,097,188 7,704,155 536,518 3,218,080 6,759,381 1,826,612 3,986,619 17,978 3,283,837 41,778,908 1,061,179 48,123,446 3,178,473 35,497,834 947,577 3,848,673 3,824,179 2,581,669 1,681,133 4,113,080 3,171,019 3,412,073 2,106,157 18,668,946 756,815 3,330,260 7,579,541 1,826,612 5,918,397 17,978 3,321,098 137,629,996 978,658,048 1,116,288,044 2,321,510 496,122 303,236 1,660,030 8,522 494,861 1,175,680 50,610 12,237,938 284,676 15,619,054 4,844,417 424,643 143,124 40,721 322,267 803,802 35,944 157,325 8,969 10,964,791 220,297 112,180 820,160 1,931,778 FERC FORM NO. 1 (ED. 12-87) Page Maintenance Expenses (n) Rents (o) Total Expenses (p) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 22,291,015 423 13,695,238 7,498,643 43,484,896 36 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material (i) 954A/1113A 954 AA 954 ACSR 1750 CU 1272 ACSR 954 AA 1750 CU 1750 CU 1750 CU 1272 ACSR 1272 ACSR 1272 ACSR 954 ACSR 954 AA 1431A/1361 ACSR 795R/1113A 795 AA 954 SSAC 954 ACSR 954 ACSR 1750 ACSR 1750 ACSR 1780 ACSR 954 AA 954 AA 2156 ACSS 954 ACSR 954 ACSR 556 ACSR 556 ACSR 795 ACSR 795 ACSR 795 ACSR 795 ACSR EXPENSES, EXCEPT DEPRECIATION AND TAXES Land rights, and clearing right-of-way) Land (j) Construction and Other Costs (k) Total Cost Operation Expenses (m) (l) 383,722 286,973 171,181 142,671 3,099,176 1,324,874 203,127 667,476 3,482,898 1,611,847 374,308 810,147 68,982 1,021,582 85,094 42,236 390,432 78,429 519,018 381,847 933,461 141,199 352,384 2,785,385 6,122,495 5,672,649 1,663,288 3,775,970 823,686 6,677,369 1,203,882 4,485,834 4,389,119 6,858,518 39,196 16,026,636 6,251,970 7,736,796 618,139 857,317 13,492,925 374,911 383,526 13,930,454 2,380,164 1,687,641 2,519,004 2,085,242 433,334 392,494 229,551 3,027,431 38,063,937 2,854,367 7,144,077 5,757,743 1,705,524 4,166,402 902,115 7,196,387 1,585,729 5,419,295 4,530,318 7,210,902 39,196 23,416,408 7,278,481 11,337,562 618,139 857,317 21,734,711 374,911 383,526 20,624,334 2,380,164 1,734,281 2,593,062 2,520,275 526,444 410,523 241,570 3,392,532 38,063,937 978,658,048 1,116,288,044 7,389,772 1,026,511 3,600,766 8,241,786 6,693,880 46,640 74,058 435,033 93,110 18,029 12,019 365,101 137,629,996 FERC FORM NO. 1 (ED. 12-87) Page Maintenance Expenses (n) Rents (o) Total Expenses (p) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 22,291,015 423.1 13,695,238 7,498,643 43,484,896 36 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material (i) EXPENSES, EXCEPT DEPRECIATION AND TAXES Land rights, and clearing right-of-way) Land (j) 37,849,599 21,621 Construction and Other Costs (k) 495,404,310 5,328,484 315,726 7,228,665 137,629,996 FERC FORM NO. 1 (ED. 12-87) 978,658,048 Total Cost Operation Expenses (m) (l) Maintenance Expenses (n) Rents (o) 533,253,909 5,350,105 315,726 7,228,665 1,116,288,044 Page 22,291,015 13,695,238 7,498,643 22,291,015 13,695,238 7,498,643 423.2 Total Expenses (p) Line No. 1 2 3 4 43,484,896 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 43,484,896 36 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 422.2 Line No.: 2 Column: a INCLUDES MINOR NAVAJO, FOUR CORNERS UNITS 1, 2, 3, PALO VERDE UNITS 1, 2, 3 REDHAWK COMBINED CYCLE AND WEST PHOENIX PLANT TO WEST PHOENIX COMBINED CYCLE RELATED TRANSMISSION Schedule Page: 422.2 Line No.: 4 Column: a INCLUDES LAND AND LAND RIGHTS FOR PALO VERDE TO SUN VALLEY AND SUNDANCE TO PINAL CENTRAL Schedule Page: 422.2 Line No.: 5 Column: a STATEMENT OF CO-OWNERSHIP AS DESCRIBED IN INSTRUCTION #8, PAGE 423 AND AS NOTED ON PAGE 422 NONE OF THE CO-OWNERS IS AN ASSOCIATED COMPANY. (A) CO-OWNERSHIP ON: LINE # 4 - NAVAJO PLANT TO WESTWING LINE # 5 - NAVAJO PLANT TO MOENKOPI LINE # 6 - MOENKOPI TO WESTWING LINE # 8 - PALO VERDE TO WESTWING LINE # 9 - PALO VERDE TO NORTH GILA LINE #10 - WESTWING TO MEAD LINE #11 - MEAD TO MARKET PLACE LINE # 1 - PALO VERDE TO KYRENE LINE # 2 - PALO VERDE TO WESTWING #2 LINE #14 - PALO VERDE TO RUDD LINE #15 - PALO VERDE TO HASSAYAMPA LINE #16 - MORGAN TO PINNACLE PEAK (1) CO-OWNERS OF LINES 4 & 6 ARE SALT RIVER PROJECT, TUCSON ELECTRIC POWER, AND U.S. DEPARTMENT OF ENERGY (2) CO-OWNERS OF LINE 5 ARE SALT RIVER PROJECT, TUCSON ELECTRIC POWER, NEVADA POWER COMPANY, LOS ANGELES DEPARTMENT OF WATER AND POWER, AND U.S. DEPARTMENT OF ENERGY (3) CO-OWNERS OF LINE 8 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC SERVICE OF NEW MEXICO (4) CO-OWNERS OF LINE 9 ARE THE IMPERIAL IRRIGATION DISTRICT AND SAN DIEGO GAS AND ELECTRIC (5) CO-OWNERS OF LINE 10 ARE M-S-R PUBLIC POWER AGENCY, SALT RIVER PROJECT, CITY OF VERNON, SOUTHERN CALIFORNIA PUBLIC AUTHORITY, AND U.S. DEPARTMENT OF ENERGY (6) CO-OWNERS OF LINE 11 ARE M-S-R PUBLIC POWER AGENCY, SALT RIVER PROJECT, CITY OF VERNON, SOUTHERN CALIFORNIA PUBLIC AUTHORITY, AND U.S. DEPARTMENT OF ENERGY (7) CO-OWNERS OF LINE 1 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC SERVICE OF NEW MEXICO (8) CO-OWNERS OF LINE 2 ARE EL PASO ELECTRIC COMPANY, PUBLIC SERVICE OF NEW MEXICO, AND SALT RIVER PROJECT (9) CO-OWNERS OF LINE 14 ARE SALT RIVER PROJECT AND ARIZONA PUBLIC SERVICE COMPANY (10) CO-OWNERS OF LINE 15 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC FERC FORM NO. 1 (ED. 12-87) Page 450.1 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA SERVICE OF NEW MEXICO (11) CO-OWNERS OF LINE 16 ARE SALT RIVER PROJECT AND ARIZONA PUBLIC SERVICE COMPANY (12) EXPENSES TO OPERATE THESE LINES ARE ALLOCATED TO PARTICIPANTS BASED ON OWNERSHIP AS SET FORTH IN OPERATION AND MAINTENANCE AGREEMENTS (13) ARIZONA PUBLIC SERVICE COMPANY'S SHARE OF THE EXPENSES TO OPERATE THESE LINES ARE RECORDED IN TRANSMISSION EXPENSE ACCOUNTS 560, 561, 563, 566, 567, 571, AND 573 (C) A.P.S. DOUBLE CIRCUIT TOWERS WITH ANOTHER UTILITY ON ONE SIDE (D) EXPENSES FOR THE OPERATION, MAINTENANCE AND RENTS ARE NOT SEGREGATED IN THE COMPANY'S BOOKS FOR EACH TRANSMISSION LINE FERC FORM NO. 1 (ED. 12-87) Page 450.2 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Year/Period of Report 2014/Q4 End of (2) X A Resubmission TRANSMISSION LINES ADDED DURING YEAR 1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. 2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the Line No. LINE DESIGNATION From To (a) (b) Line Length in Miles (c) SUPPORTING STRUCTURE Average Type Number per Miles (d) (e) CIRCUITS PER STRUCTURE Present Ultimate (f) (g) 1 OVERHEAD 2 PIONEER GAVILAN 4.89 STEEL 3 COUNTRY CLUB EVANS CHURCHILL 1.30 STEEL 2 2 4 COUNTRY CLUB EVANS CHURCHILL 0.15 STEEL 1 1 5 SALOME EAGLE EYE 0.05 STEEL 1 1 6 LUKE FIELD NORTH EL SOL 0.10 STEEL 1 1 7 REACH BOULEVARD 0.04 STEEL 1 1 8 ROAD RUNNER CENTURY 1.05 STEEL 2 2 9 EL SOL MERIDIAN -0.96 STEEL 12.00 1 1 10 EL SOL MERIDIAN 0.97 STEEL 12.00 1 1 13 SNOWFLAKE SHOWLOW 0.37 STEEL 1.00 14 ZENIFF SHOWLOW 0.37 STEEL 1.00 11 11 1 23.00 1 11 12 UNDERGROUND 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 8.33 44 TOTAL FERC FORM NO. 1 (REV. 12-03) Page 424 49.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION LINES ADDED DURING YEAR (Continued) Year/Period of Report 2014/Q4 End of costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m). 3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic. CONDUCTORS Size Specification (h) (i) Configuration and Spacing (j) Voltage KV (Operating) (k) Land and Land Rights (l) LINE COST Poles, Towers Conductors Asset and Fixtures and Devices Retire. Costs (n) (o) (m) Total Line No. (p) 1 795 ACSS 45/7 69 77,702 3,343,988 662,009 4,083,699 795 ACSS 45/7 69 2 2,393,072 369,902 2,762,974 795 ACSS 45/7 69 3 795 ACSS 45/7 69 204,513 105,649 310,162 5 795 AL 37 69 268,993 115,282 384,275 6 795 ACSS 45/7 69 339,945 145,691 485,636 7 795 ACSS 45/7 69 1,275,768 546,758 1,822,526 8 795 AL 37 69 795 ACSS 45/7 69 136,454 237,334 373,788 10 4 9 11 12 2500 KCMIL 6-6" CONDUIT 69 2500 KCMIL 6-6" CONDUIT 69 304,747 304,747 609,494 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 77,702 FERC FORM NO. 1 (REV. 12-03) Page 425 8,267,480 2,487,372 10,832,554 44 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Name and Location of Substation Character of Substation (a) (b) Secondary (d) 12.00 1 ACOMA-SCOTTSDALE D Primary (c) 69.00 2 ADAMS-BENSON T 115.00 3 ADOBE-PHOENIX D 69.00 12.00 4 AGUA FRIA SWYD-GLENDALE T 230.00 69.00 5 AGUILA-AGUILA D 69.00 12.00 6 AJO-AJO D 69.00 21.00 7 ALEXANDER-PHOENIX T 69.00 8 ALTADENA-SCOTTSDALE D 69.00 12.00 9 ANTELOPE-PRESCOTT D 69.00 12.00 10 ARABY-YUMA D 69.00 12.00 11 ARICA-ELOY D 69.00 12.00 12 ARLINGTON-MARICOPA COUNTY D 69.00 12.00 13 ARROWHEAD-GLENDALE D 69.00 12.00 14 ARROYO-PHOENIX D 69.00 12.00 15 ASARCO PIT-CASA GRANDE D 69.00 12.00 16 ASHFORK-ASHFORK D 69.00 12.00 17 AZTEC-AZTEC D 69.00 12.00 18 BACON-N.W. OF SNOWFLAKE D 69.00 21.00 19 BADGER SUB D 69.00 12.00 12.00 20 BAGDAD-BAGDAD T 115.00 21 BAGDAD-115KV CAP.-BAGDAD T 115.00 22 BAJA-SAN LUIS D 69.00 12.00 23 BALD MOUNTAIN-PRESCOTT VALLEY D 69.00 12.00 24 BASELINE-BUCKEYE D 69.00 12.00 25 BEAR SPRINGS-CAMERON D 69.00 2.30 26 BEARDSLEY-SURPRISE D 69.00 12.00 27 BELL-PEORIA D 69.00 12.00 28 BISCUIT FLATS-PHOENIX D 69.00 29 BLACK MESA #2-GRAY MOUNTAIN D 69.00 30 BLACK PEAK(BOUSE APA) - PARKER T 161.00 69.00 31 BLACK PEAK(BOUSE APA) - PARKER D 69.00 12.00 32 BLUE RIDGE-BLUE RIDGE D 69.00 21.60 33 BLUE WATER-N. OF PARKER D 34.50 12.00 34 BONNYBROOK-FLORENCE D 115.00 12.00 35 BOOTHILL-E. OF TOMBSTONE D 115.00 21.00 36 BOULEVARD-SCOTTSDALE D 69.00 12.00 37 BUCKEYE-BUCKEYE T 230.00 69.00 38 BUCKEYE-BUCKEYE D 69.00 12.00 39 BUFFALO-PHOENIX D 69.00 12.00 40 BUNYAN-NW. OF GILA BEND D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426 Tertiary (e) This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Name and Location of Substation Character of Substation (a) (b) Secondary (d) 12.00 D Primary (c) 69.00 2 CACTUS-SCOTTSDALE T 230.00 69.00 3 CACTUS-SCOTTSDALE D 69.00 12.00 4 CALDERWOOD-PEORIA D 69.00 12.00 5 CAMELBACK-SCOTTSDALE D 69.00 12.00 6 CAMERON-CAMERON D 69.00 12.00 7 CANAL-PHOENIX D 69.00 12.00 8 CAPITAL BUTTE-SEDONA D 69.00 12.00 1 BUTTE-TEMPE 9 CASA GRANDE-CASA GRANDE T 230.00 69.00 10 CASA GRANDE-CASA GRANDE D 230.00 12.00 11 CASA GRANDE-CASA GRANDE D 69.00 12.00 12.00 12 CAVE CREEK-CAVE CREEK D 69.00 13 CEDAR MOUNTAIN-WILLIAMS T 500.00 14 CENTURY-SCOTTSDALE D 69.00 12.00 15 CHANDLER-CHANDLER D 69.00 12.00 16 CHAPARRAL-SCOTTSDALE D 69.00 12.00 17 CHERYL-PHOENIX D 69.00 12.00 18 CHILDS-CAMP VERDE D 69.00 19 CHINO VALLEY-CHINO VALLEY D 69.00 12.00 345.00 20 CHOLLA-JOSEPH CITY A,T 525.00 21 CHOLLA-JOSEPH CITY A,T 525.00 22 CHOLLA-JOSEPH CITY A,T 345.00 230.00 23 CHOLLA-JOSEPH CITY A,T 345.00 69.00 24 CHOLLA-JOSEPH CITY A,T 230.00 69.00 25 CHOLLA-JOSEPH CITY D 69.00 12.00 26 CIELO GRANDE-PHOENIX D 69.00 12.00 27 CLINIC - SCOTTSDALE D 69.00 12.00 28 COCONINO-FLAGSTAFF T 230.00 69.00 29 COCONINO-FLAGSTAFF D 69.00 12.00 30 COCOPAH-W. OF YUMA D 69.00 12.00 31 COLDWATER-GOODYEAR D 69.00 12.00 32 COLORADO-N. OF PARKER D 69.00 12.00 33 COLTER-AVONDALE D 69.00 12.00 34 CONLEY-SNOWFLAKE T 69.00 35 COOLIDGE-N. OF COOLIDGE D 12.40 36 COPPER CANYON-N. OF CAMP VERDE D 69.00 12.00 37 CORDES-CORDES JUNCTION D 69.00 12.00 38 CORNVILLE-CORNVILLE D 69.00 12.00 39 COTTON CENTER-N. OF GILA BEND D 69.00 12.00 40 COTTONWOOD-COTTONWOOD D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.1 Tertiary (e) 12.00 12.00 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Character of Substation Name and Location of Substation (b) Primary (c) Secondary (d) (a) 1 COTTONWOOD-COTTONWOOD D 2 COUNTRY CLUB-PHOENIX D 69.00 12.00 3 COUNTRY CLUB-PHOENIX T 230.00 69.00 4 COUNTY LINE D 69.00 12.00 5 CROSSROADS-N. OF PARKER D 34.50 12.00 6 DALE-SCOTTSDALE D 69.00 12.00 7 DALE-SCOTTSDALE D 69.00 8 DAVENPORT- E. OF WILLIAMS D 69.00 12.00 12.00 9 DEADMAN WASH-PHOENIX D 69.00 10 DEADMAN WASH-PHOENIX D 69.00 11 DEER VALLEY-PHOENIX T 230.00 69.00 12 DEER VALLEY-PHOENIX D 69.00 12.00 13 DEL RIO-PEORIA D 69.00 12.00 14 DELANO-PRESCOTT D 69.00 12.00 15 DESERT RIDGE-SCOTTSDALE D 69.00 12.00 16 DESERT SANDS - YUMA T 69.00 17 DESERT SKY-BUCKEYE D 69.00 12.00 18 DESERT SPRINGS-PHOENIX D 69.00 12.00 19 DEWEY-N. OF DEWEY D 69.00 12.00 20 DIXILETA-N. OF SCOTTSDALE D 69.00 12.00 21 DON LUIS-BISBEE D 69.00 12.00 22 DOUBLETREE-PHOENIX D 69.00 12.00 23 DOVE VALLEY-PHOENIX D 69.00 12.00 24 DOWNING-SCOTTSDALE D 69.00 12.00 25 DRAKE-PAULDEN D 69.00 26 DRY LAKE SUB D 69.00 7.20 27 DUGAS-MAYER T 525.00 69.00 28 DUGAS-MAYER T 29 DURANGO-PHOENIX D 69.00 12.00 30 DYSART-SURPRISE D 69.00 12.00 31 EAGLE EYE-W. OF AGUILA T 230.00 69.00 32 EAST END-SCOTTSDALE D 69.00 12.00 33 EASTERN OFFICE-PHOENIX D 69.00 12.00 34 EASTGATE-CASA GRANDE D 69.00 12.00 35 EHRENBERG-EHRENBERG D 33.00 12.00 36 EL SOL-YOUNGTOWN T 230.00 69.00 37 EL SOL-YOUNGTOWN D 69.00 12.00 38 ELDEN-FLAGSTAFF D 69.00 12.00 39 ENCANTO-PHOENIX D 69.00 12.00 40 ESTRELLITA-GOODYEAR D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.2 Tertiary (e) 12.00 34.50 12.00 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Character of Substation Name and Location of Substation D Primary (c) 69.00 Secondary (d) 12.00 D 69.00 12.00 T 69.00 4 FESTIVAL RANCH-BUCKEYE D 69.00 12.00 5 FILLMORE-PHOENIX D 69.00 12.00 6 FISH SAWMILL-N. OF FLAGSTAFF D 69.00 12.00 7 FLORES-CONGRESS D 69.00 12.00 8 FLYING E-WICKENBURG D 69.00 12.00 9 FOOTHILLS-YUMA 12.00 (a) 1 EVANS CHURCHILL-PHOENIX 2 FAIRVIEW-N. OF DOUGLAS 3 FARMER - SURPRISE (b) Tertiary (e) D 69.00 10 FORTIETH PLACE-PHOENIX D 69.00 12.00 11 FOUR CORNERS-FRUITLAND,NM A,T 525.00 345.00 14.00 12 FOUR CORNERS-FRUITLAND,NM A,T 345.00 230.00 14.00 13 FOUR CORNERS-FRUITLAND,NM A,T 230.00 69.00 14 GARFIELD-PHOENIX D 69.00 12.00 15 GARLAND PRAIRIE-E. OF WILLIAMS D 69.00 12.00 16 GATEWAY - PHOENIX D 69.00 12.00 17 GAVILAN PEAK-PHOENIX T 230.00 69.00 18 GAVILAN PEAK-PHOENIX D 69.00 12.00 19 GILA BEND-GILA BEND T 230.00 69.00 20 GILA BEND-GILA BEND D 69.00 12.00 21 GILBERT-GILBERT D 69.00 12.00 22 GILLESPIE#1-N. OF GILA BEND D 69.00 12.00 23 GLENDALE-GLENDALE D 230.00 12.00 24 GRAND CANYON-GRAND CANYON D 69.00 12.00 25 GRANITE CREEK - CHINO VALLEY T 69.00 26 GRANITE REEF - SCOTTSDALE D 69.00 12.00 27 GRAY MOUNTAIN-S. OF CAMERON D 69.00 12.00 28 GREENBRIER-GLENDALE D 69.00 12.00 29 GREENWAY-GLENDALE D 69.00 12.00 30 GREYBEARS-CHINO VALLEY D 69.00 12.00 31 GRISWOLD-PHOENIX D 69.00 12.00 32 HAMBLIN D 69.00 7.20 33 HANKS-N. OF FLAGSTAFF D 69.00 12.00 34 HAPPY VALLEY TEMP-PEORIA D 69.00 12.00 35 HARBOR-PHOENIX D 69.00 12.00 36 HARQUAHALA-TONOPAH D 69.00 12.00 37 HASHKNIFE-HEBER D 69.00 38 HATFIELD-PEORIA D 69.00 12.00 39 HAVASU- PARKER D 69.00 12.00 40 HAYDEN-HAYDEN D 21.00 7.00 FERC FORM NO. 1 (ED. 12-96) Page 426.3 12.00 12.00 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Name and Location of Substation Character of Substation (a) (b) Secondary (d) 21.00 1 HAYES GULCH-GLOBE D Primary (c) 69.00 2 HEARN-SURPRISE D 69.00 12.00 3 HEDGEPETH HILLS-PHOENIX D 69.00 12.00 4 HOHOKAM-TEMPE D 69.00 12.00 5 HONEYWELL-PHOENIX D 69.00 12.00 6 HOODOO WASH-YUMA T 500.00 7 HORN-HORN D 69.00 12.00 8 HOWARD-MESA-WILLIAMS D 69.00 12.00 9 HUMBUG-PEORIA D 69.00 12.00 10 HYDER-HYDER D 69.00 12.00 11 INDIAN BEND-PHOENIX D 69.00 12.00 12 INDIANOLA-PHOENIX D 69.00 12.00 13 IVALON-YUMA D 69.00 12.00 14 JACKSON STREET-PHOENIX D 69.00 12.00 15 JAVELINA-SURPRISE D 69.00 12.00 16 JOMAX-SCOTTSDALE D 69.00 12.00 17 KACHINA-KACHINA VILLAGE D 69.00 12.00 18 KEAMS CANYON-W. OF KEAMS CANYON D 69.00 21.00 19 KEARNY-KEARNY D 21.00 20 KIRKLAND JUNCTION-SE. OF KIRKLAND D 69.00 12.00 21 LAGUNA-YUMA D 69.00 12.00 22 LE BARRON HILL-FLAGSTAFF D 69.00 7.20 23 LEROUX-N. OF HOLBROOK D 69.00 12.00 24 LEUPP JUNCTION-W. OF WINSLOW D 69.00 21.00 25 LIBERTY IRON-PHOENIX D 69.00 26 LINCOLN STREET (230kV)-PHOENIX T 230.00 69.00 27 LINCOLN STREET NORTH-PHOENIX D 69.00 12.00 28 LINCOLN STREET WEST-PHOENIX D 69.00 12.00 29 LITCHFIELD-LITCHFIELD PARK D 69.00 12.00 30 LOMA VISTA-PHOENIX D 69.00 12.00 31 LONE PEAK-PHOENIX T 230.00 69.00 32 LONE PEAK-PHOENIX D 69.00 12.00 33 LONESOME VALLY-PRESCOTT D 69.00 12.00 34 LOOKOUT-PHOENIX D 69.00 12.00 35 LUKE FIELD NORTH-LUKE AFB D 69.00 12.00 36 MAGNOLIA - STANTON D 69.00 7.20 37 MARINE AIR BASE-YUMA D 69.00 12.00 38 MARINETTE-SUN CITY D 69.00 12.00 39 MARTINEZ WASH-WICKENBURG D 69.00 7.20 40 MAZATAL-RYE D 69.00 21.00 FERC FORM NO. 1 (ED. 12-96) Page 426.4 Tertiary (e) 12.00 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Character of Substation Name and Location of Substation D Primary (c) 69.00 Secondary (d) 12.00 D 69.00 12.00 D 69.00 12.00 D 69.00 12.00 T 230.00 69.00 6 MEADOWBROOK-PHOENIX D 69.00 12.00 7 MERIDIAN-GLENDALE D 69.00 8 MERRILL-FLORENCE D 69.00 12.00 9 METRO-PHOENIX 12.00 (a) 1 MC GUIREVILLE-MC GUIREVILLE 2 MCCORMICK-SCOTTSDALE 3 MCDOWELL-PHOENIX 4 MCMICKEN-SURPRISE 5 MEADOWBROOK-PHOENIX (b) Tertiary (e) 12.00 D 69.00 10 MILLER WASH-VALLE D 69.00 7.20 11 MILLIGAN-ELOY T 230.00 69.00 12 MILLIGAN TEMP-ELOY D 69.00 12.00 13 MINGUS-JEROME D 69.00 7.20 14 MITTRY D 69.00 12.00 15 MOENKOPI-CAMERON T 525.00 16 MOENKOPI-CAMERON T 525.00 17 MONTE CRISTO-PHOENIX D 69.00 18 MOON VALLEY-PHOENIX D 69.00 12.00 19 MORGAN-PEORIA T 525.00 230.00 20 MORRISTOWN-MORRISTOWN D 69.00 12.00 21 MOUNTAIN VIEW-SUN CITY D 69.00 12.00 22 MT. FLOYD-MT. FLOYD D 4.16 12.00 23 MUMMY MOUNTAIN-PARADISE VALLEY D 69.00 12.00 24 MUNDS PARK-S. OF FLAGSTAFF D 69.00 21.00 25 MURAL-E. OF LOWELL D 69.00 12.00 26 MURAL-E. OF LOWELL T 115.00 69.00 27 NADASY-N. OF WILLIAMS D 69.00 7.20 28 NAVAJO-PAGE A,T 500.00 29 NAVAJO-PAGE A,T 500.00 30 NAVAJO ARMY DEPOT-FLAGSTAFF D 69.00 12.00 31 NEW RIVER-NEW RIVER D 69.00 12.00 32 NEWMAN PARK-S. OF FLAGSTAFF D 69.00 7.20 33 NORTH GILA-YUMA T 500.00 230.00 34.50 34.50 12.00 34 NORTH GILA-YUMA T 500.00 69.00 35 NORTH VALLEY-PHOENIX D 69.00 12.00 36 OAK CREAK-OAK CREEK D 69.00 12.00 37 OBERLIN TEMP-WITTMAN D 69.00 12.00 38 OCOTILLO-TEMPE A,T 230.00 69.00 39 OCOTILLO-TEMPE A,T 40 OCOTILLO-TEMPE A,T FERC FORM NO. 1 (ED. 12-96) Page 69.00 426.5 12.00 34.50 12.00 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Character of Substation Name and Location of Substation Secondary (d) (a) 1 OLD HOME MANOR-CHINO VALLEY D Primary (c) 69.00 2 ORANGEWOOD-PHOENIX D 69.00 12.00 3 ORMES-CORDES JUNCTION D 69.00 4.16 4 OSBORNE TANK D 69.00 12.00 5 PADRE - E. OF ANGELL D 69.00 12.00 (b) 6 PALM VALLEY-GOODYEAR T 230.00 69.00 7 PALM VALLEY-GOODYEAR D 69.00 12.00 8 PALOMA-W. OF GILA BEND D 69.00 12.00 69.00 12.00 9 PALOMINAS-PALOMINAS D Tertiary (e) 12.00 10 PANDA - GILA BEND A,T 230.00 11 PAPAGO BUTTE-SCOTTSDALE D 69.00 12.00 12 PARADISE-PHOENIX D 69.00 12.00 13 PARKS-PARKS D 69.00 12.00 14 PATTERSON-OUT OF BUCKEYE D 69.00 12.00 15 PATTON-OUT OF MORRISTON D 69.00 12.00 16 PAULDEN-PAULDEN D 69.00 12.00 17 PEBBLECREEK-GOODYEAR D 69.00 12.00 18 PEORIA-PEORIA D 69.00 12.00 19 PERRYVILLE-N.E. OF BUCKEYE D 69.00 12.00 20 PICKET-SUPERIOR D 115.00 12.00 21 PIMA-GOODYEAR D 69.00 12.00 22 PINAL-GLOBE T 115.00 69.00 23 PINAL-GLOBE D 69.00 21.00 24 PINE SPRINGS-W. OF WILLIAMS D 69.00 7.20 25 PINNACLE PEAK-PHOENIX T 500.00 230.00 34.50 26 PINNACLE PEAK-PHOENIX T 345.00 230.00 14.40 27 PINNACLE PEAK-PHOENIX T 230.00 69.00 12.40 28 PIONEER-PHOENIX D 69.00 12.00 29 PLANET-NE. OF PARKER D 69.00 12.00 30 PLEASANT-GLENDALE D 69.00 12.00 31 POLAND JUNCTION NW. OF MAYER D 69.00 12.00 32 POLK-PHOENIX D 69.00 12.00 33 POLLOCK-SW. OF ASHFORK D 69.00 12.00 34 POPLAR WASH-PEEPLES VALLEY D 69.00 7.20 35 PREACHER CANYON-PAYSON T 345.00 69.00 36 PREACHER CANYON-PAYSON D 69.00 21.00 37 PRESCOTT CHINO WELLS-CHINO VALEY D 69.00 7.20 38 PRESCOTT CHINO WELLS - CHINO VALLEY D 69.00 12.00 39 PRESCOTT CITY-PRESCOTT D 69.00 12.00 40 PYRAMID PEAK-GLENDALE D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.6 21.00 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Character of Substation Name and Location of Substation (a) 1 QUAIL SPRINGS-SE. OF COTTONWOOD 2 QUARTZSITE-QUARTZSITE 3 QUECHAN-YUMA D Primary (c) 69.00 Secondary (d) 12.00 D 69.00 12.00 D 69.00 12.00 (b) 4 RACEWAY-PEORIA T 230.00 69.00 5 RAINBOW VALLEY-SE. OF BUCKEYE D 69.00 12.00 6 RAINTREE-SCOTTSDALE D 69.00 12.00 7 RAMON ASO-RED LAKE, N. OF WILLIAMS D 69.00 12.40 8 RAWHIDE-SCOTTSDALE D 69.00 12.00 T 230.00 69.00 10 RED LAKE-E. OF WILLIAMS 9 REACH-SCOTTSDALE D 69.00 21.00 11 REDONDO-YUMA D 69.00 12.00 12 REIDHEAD-SNOWFLAKE D 69.00 7.20 13 RINCON-WICKENBURG D 69.00 7.20 14 RIO SALADO - TEMPE D 69.00 12.00 15 RIO VISTA-SUN CITY D 69.00 12.00 16 RIVERSIDE-YUMA D 69.00 12.00 17 ROAD RUNNER-PHOENIX D 69.00 12.00 18 ROBBINS BUTTE-OUT OF BUCKEYE D 69.00 7.20 19 ROCK SPRINGS-ROCK SPRINGS D 69.00 12.00 20 ROGERS LAKE-SW. OF FLAGSTAFF D 69.00 7.20 21 ROSE GARDEN-PHOENIX D 69.00 12.00 22 ROUND VALLEY T 230.00 Tertiary (e) 12.40 12.00 23 SADDLE MTN-W. OF TONOPAH D 69.00 24 SADDLEBROOK-ORACLE JUNCTION T 115.00 12.00 25 SAGE VALLEY-VALLE D 69.00 12.00 26 SAGUARO 525kV-RED ROCK A,T 500.00 115.00 34.50 27 SAGUARO 230kv-RED ROCK A,T 230.00 115.00 12.40 28 SAGUARO 115kV-RED ROCK A,T 115.00 12.50 29 SALOME-S.E. OF SALOME D 69.00 12.00 30 SAN LUIS-SAN LUIS D 69.00 12.00 31 SAN LUIS (MEXICO CONN.)-SAN LUIS D 69.00 34.50 32 SAN MANUEL-SAN MANUEL D 115.00 46.00 33 SAN MANUEL-SAN MANUEL D 115.00 12.00 34 SAN PEDRO-W. OF DOUGLAS D 69.00 12.00 35 SANDVIG-FLAGSTAFF D 69.00 12.00 36 SANGUINETTI-YUMA T 69.00 37 SANTA ROSA-SE. OF MARICOPA T 230.00 69.00 38 SARIVAL-GOODYEAR D 69.00 12.00 39 SEDONA-SEDONA D 69.00 12.00 40 SELIGMAN COMPRESSER STATION-SELIGMAN D 230.00 4.20 FERC FORM NO. 1 (ED. 12-96) Page 426.7 12.40 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Character of Substation Name and Location of Substation Secondary (d) (a) 1 SEXTON-E. OF STANFIELD D Primary (c) 69.00 2 SHAW-PHOENIX D 69.00 12.00 3 SHEA-SCOTTSDALE D 69.00 12.00 4 SHERMAN STREET-PHOENIX D 69.00 12.00 5 SHOW LOW-SHOW LOW D 69.00 12.00 6 SHOW LOW-SHOW LOW D 69.00 7 SHUMWAY-SHOW LOW D 69.00 8 SHUMWAY-SHOW LOW D 69.00 (b) 12.00 9 SKUNK CREEK-GLENDALE D 69.00 12.00 10 SNOWFLAKE-SNOWFLAKE D 69.00 12.00 11 SONORA D 69.00 12.00 12 SOUTH O'NEIL - YUMA T 69.00 13 SPANISH GARDENS-SURPRISE D 69.00 12.00 14 SPIDER WEB-S. OF GRAY MOUNTAIN D 69.00 2.30 15 STAGECOACH-SCOTTSDALE D 69.00 12.00 16 STANTON-S. OF YARNELL D 69.00 7.20 17 STARDUST-SUN CITY WEST D 69.00 18 STOUT-PHOENIX D 69.00 12.00 19 STRAWBERRY-STRAWBERRY D 69.00 21.00 20 STURM RUGER-N. OF PRESCOTT D 69.00 4.16 21 STURM RUGER-N. OF PRESCOTT D 69.00 12.40 22 SUGARLOAF-SNOWFLAKE T 525.00 69.00 23 SUNDOG-PRESCOTT D 69.00 12.00 24 SUNNYSLOPE-PHOENIX T 230.00 69.00 25 SUNNYSLOPE-PHOENIX D 69.00 12.00 26 SUNSHINE-WINSLOW D 69.00 12.00 27 SURPRISE-SURPRISE T 230.00 69.00 28 SURPRISE-SURPRISE D 69.00 12.00 29 SWITZER CANYON-FLAGSTAFF D 69.00 12.00 30 SYCAMORE-DUGAS D 69.00 7.20 31 TABLE MESA-NEW RIVER D 69.00 7.20 32 TAPCO-E. OF CLARKDALE D 69.00 2.40 33 TARTESSO-BUCKEYE D 69.00 12.00 34 TAT MOMOLI-CASA GRANDE T 230.00 35 TEMPE-TEMPE D 69.00 12.00 36 TENTH STREET-YUMA D 69.00 12.00 37 THAYER-THAYER D 69.00 12.00 38 THIRTY-SECOND STREET-YUMA D 69.00 12.00 39 THOMPSON PEAK-SCOTTSDALE D 69.00 12.00 40 TOLTEC-ARIZONA CITY D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.8 Tertiary (e) 34.50 12.40 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Name and Location of Substation Character of Substation (a) (b) Secondary (d) 12.00 1 TONALEA-TUBA CITY D Primary (c) 69.00 2 TONOPAH-TONOPAH D 69.00 12.00 3 TONTO-PAYSON D 69.00 21.00 4 TONTO-PAYSON D 5 TUBA CITY-TUBA CITY D 69.00 12.00 6 TURF-PHOENIX D 69.00 12.00 7 TUSAYAN-TUSAYAN D 69.00 12.00 8 TUSAYAN-TUSAYAN D 69.00 9 TUTHILL-BUCKEYE D 69.00 12.00 10 TWENTY-THIRD STREET-PHOENIX D 69.00 12.00 11 TWIN ARROWS - FLAGSTAFF T 69.00 12 UNION HILLS-PHOENIX D 69.00 12.00 13 UTTING-SE. OF BOUSE D 69.00 12.00 14 VALENCIA-BUCKEYE D 69.00 12.00 15 VALLE-WILLIAMS D 69.00 21.00 16 VALLEY FARMS-FLORENCE T 115.00 69.00 17 VALLEY FARMS-FLORENCE D 69.00 12.00 18 VARNEY-SURPRISE D 69.00 12.00 19 VERDE-CLARKDALE T 230.00 69.00 20 VICKSBURG-S. OF VICKSBURG JUNCTION D 69.00 12.00 21 VISTA-CASA GRANDE D 69.00 12.00 22 WADDELL-SURPRISE D 69.00 12.00 23 WALDRIP - YUMA T 69.00 24 WATSON-BUCKEYE D 69.00 12.00 25 WELCH-E. OF ASHBROOK D 69.00 2.40 26 WELLFIELD - PRESCOTT VALLEY D 69.00 12.00 27 WENDON TEMP - LA PAZ D 69.00 12.00 28 WEST PHOENIX-PHOENIX T 230.00 69.00 29 WEST PHOENIX-PHOENIX D 69.00 12.40 30 WESTBROOK-PEORIA D 69.00 12.00 230.00 31 WESTWING-SUN CITY T 525.00 32 WESTWING-SUN CITY T 525.00 33 WESTWING-SUN CITY T 525.00 34 WESTWING-SUN CITY T 230.00 35 WESTWING-SUN CITY T 69.00 12.00 36 WESTWING-SUN CITY T 230.00 69.00 37 WHITE SPAR-PRESCOTT D 69.00 12.00 38 WHITE TANKS-AVONDALE T 230.00 69.00 39 WHY-WHY D 69.00 21.00 40 WICKENBURG-WICKENBURG D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.9 Tertiary (e) 12.40 12.40 12.40 34.50 12.40 12.40 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 04/15/2015 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2014/Q4 End of 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Line No. VOLTAGE (In MVa) Name and Location of Substation Character of Substation (a) (b) Secondary (d) 7.20 1 WILD BURRO-NEW RIVER D Primary (c) 69.00 2 WILD FLOWER-GOODYEAR D 69.00 12.00 3 WILHOIT-PRESCOTT D 69.00 12.00 Tertiary (e) 4 WILLIAMS-WILLIAMS D 69.00 12.00 5 WILLOW LAKE-PRESCOTT T 230.00 115.00 12.40 6 WILLOW LAKE-PRESCOTT T 230.00 69.00 12.40 7 WINDMILL-SEDONA D 69.00 7.20 8 WINONA-WINONA D 69.00 12.00 9 WINSLOW-WINSLOW D 69.00 12.00 10 WINTERSBURG-WINTERSBURG D 69.00 12.00 11 WOODRUFF-HOLBROOK D 69.00 21.00 12 WOODY MOUNTAIN-FLAGSTAFF D 69.00 12.00 13 WUPATKI-FLAGSTAFF D 69.00 12.00 14 YALE-PHOENIX D 69.00 12.00 15 YARNELL-YARNELL D 69.00 12.00 16 YAVAPAI-CHINO VALLEY T 525.00 230.00 12.40 12.40 17 YAVAPAI-CHINO VALLEY T 230.00 69.00 18 YORKSHIRE-PHOENIX D 69.00 12.00 19 YOUNG'S CANYON - DONEY PARK T 345.00 69.00 20 YUCCA-YUMA T 161.00 69.00 21 YUMA PALMS TEMP-YUMA D 69.00 12.00 22 ZENIFF-SNOWFLAKE D 69.00 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 1 (ED. 12-96) Page 426.10 12.00 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 83 2 1 83 2 3 188 1 capacitor bank-69kv 1 48 4 20 1 capacitor bank-69kv 1 5 5 9 1 48 7 83 2 8 20 1 capacitor bank-69kv 1 7 9 57 2 capacitor bank-69kv 1 14 10 20 1 capacitor bank-12kv 2 4 11 12 1 83 2 42 1 14 9 1 15 9 1 16 1 17 2 6 capacitor bank-69kv 20 1 12 capacitor bank-69kv 1 22 13 3 1 18 20 1 19 30 1 20 capacitor bank-115kv 5 49 21 20 1 capacitor bank-69kv 1 14 22 83 2 capacitor bank -12kv 2 10 23 40 2 capacitor bank-69kv 2 22 24 1 25 20 1 26 83 2 27 capacitor bank-69kv 1 14 28 29 112 1 9 1 30 1 31 9 1 32 15 1 33 13 1 34 20 1 35 83 2 36 267 2 37 20 1 38 83 2 39 7 1 FERC FORM NO. 1 (ED. 12-96) capacitor bank-69kv Page 427 1 10 40 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) 167 4 543 3 125 3 Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 2 capacitor bank-69kv 1 48 3 41 1 4 125 3 5 2 1 6 83 2 40 2 100 1 9 50 1 10 20 1 11 40 2 12 83 2 14 83 2 15 83 2 16 40 2 17 38 2 1002 6 203 1 7 capacitor bank-12kV 4 14 8 13 18 19 1 capacitor bank 500kv 1 395 20 reactor 500kV 4 167 21 capacitor bank 345kv 2 870 22 143 1 23 150 2 24 9 1 25 83 2 capacitor bank -12kV 2 7 26 40 2 capacitor bank -12kV 2 7 27 355 2 28 40 2 capacitor bank-69kv 2 36 29 83 2 capacitor bank-69kv 1 14 30 83 2 capacitor bank-69kv 1 29 31 9 1 32 83 2 33 34 35 40 2 20 1 20 1 40 2 40 2 FERC FORM NO. 1 (ED. 12-96) capacitor bank-12kv 4 12 36 37 capacitor bank 69kv 1 7 38 39 capacitor bank-69kV Page 427.1 1 11 40 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service Number of Spare Transformers (f) (g) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Type of Equipment (i) capacitor bank-12kV Line No. Total Capacity (In MVa) (k) Number of Units (j) 2 6 1 125 3 2 355 2 3 40 2 20 83 3 83 14 4 1 5 2 capacity bank-69kV 2 capacitor bank-12kv 2 7 6 capacitor bank 69kV 1 29 7 1 8 2 capacitor bank -12kv 2 7 9 capacitor bank 69kv 1 29 10 11 564 3 125 3 22 1 40 2 14 2 15 83 capacitor bank-69kV 1 48 12 13 capacitor bank-12kv 2 10 16 17 4 1 83 2 capacitor bank-12kv 2 10 40 2 capacitor bank-69kv 1 14 19 7 20 capacitor bank-12kv 2 18 83 2 20 1 42 1 22 83 2 capacitor bank-12kv 2 4 23 123 3 capacitor bank-69kv 1 48 24 capacitor bank-69kv 3 22 25 21 26 1 269 3 4 shunt reactor 525kV 1 190 27 capacitor bank-525kv 1 372 28 capacitor bank-12kV 2 7 29 83 2 125 3 30 100 2 31 41 1 capacitor bank-12kV 2 5 32 41 1 capacitor bank-12kV 1 5 33 41 1 capacitor bank-12kV 2 14 34 20 1 376 2 36 83 2 37 40 2 83 2 39 1 40 41 FERC FORM NO. 1 (ED. 12-96) 35 capacitor bank-69kv 1 48 38 capacitor bank-12kv Page 427.2 1 4 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers CONVERSION APPARATUS AND SPECIAL EQUIPMENT Type of Equipment (h) 83 2 (i) capacitor bank-12kv 41 1 capacitor bank-12kv Number of Units (j) Line Total Capacity No. (In MVa) (k) 1 4 10 2 4 10 3 20 1 83 2 1 4 capacitor bank-69kv 1 29 5 6 2 20 1 capacitor bank-69kv 1 7 7 20 1 capacitor bank-69kv 2 22 8 83 2 capacitor bank-69kv 2 29 9 83 2 capacitor bank-12kv 2 7 10 1025 3 reactor 525kv 3 125 11 12 1400 2 106 2 167 4 1 1 reactor 345kV 4 155 capacitor bank 12kv 4 10 13 14 10 1 15 42 1 16 188 1 17 41 1 18 200 2 19 83 2 capacitor bank-69kv 2 20 83 2 capacitor bank 12kv 2 8 21 20 1 capacitor bank-69kv 1 14 22 100 2 9 1 30 23 24 25 26 41 1 2 27 41 1 28 125 3 20 1 30 41 1 31 1 32 18 capacitor bank-12kV 3 11 29 1 33 1 34 125 3 35 10 1 36 37 41 1 38 20 1 39 10 1 40 FERC FORM NO. 1 (ED. 12-96) Page 427.3 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) 20 1 83 2 83 2 20 1 83 2 Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 2 capacitor bank-69kv capacitor bank-12kv 1 2 29 3 5 4 5 6 10 40 7 1 1 8 2 9 10 9 1 83 2 125 3 12 40 2 13 125 3 14 83 2 15 41 1 16 9 1 17 9 1 capacitor bank-12kV 2 7 11 18 19 9 1 36 2 20 capacitor bank-69kV 2 29 21 1 22 20 1 23 6 1 24 25 188 1 26 83 2 capacitor bank-69kV 1 35 27 167 4 capacitor bank-12kv 8 19 28 83 2 29 83 2 30 376 2 31 41 1 32 40 2 33 83 2 34 40 2 35 1 36 83 2 37 83 2 20 FERC FORM NO. 1 (ED. 12-96) capacitor bank-12kV 2 7 38 1 39 1 40 Page 427.4 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 16 1 1 83 2 2 83 2 3 83 2 4 188 1 5 125 3 capacitor bank-69kV 1 48 6 41 1 capacitor bank-69kv 2 14 8 125 3 capacitor bank -12kv 4 10 9 188 1 20 1 12 1 2 13 7 1 7 10 1 11 1 14 capacitor bank 525kv 4 1,540 shunt reactor 525kv 10 646 15 16 83 2 17 83 2 18 600 1 19 9 1 capacitor bank-69kv 1 11 20 83 2 capacitor bank-69kv 1 48 21 3 1 22 83 2 23 9 1 9 1 50 1 24 capacitor bank-12kv 4 10 25 26 27 1 shunt reactor 525kv 2 380 28 capacitor bank 525kV 2 1,207 29 1 30 20 1 31 600 1 509 6 83 2 40 2 6 32 1 16 1 355 2 FERC FORM NO. 1 (ED. 12-96) 1 shunt reactor 525kV 5 374 33 capacitor bank 500kv 1 489 34 capacitor bank 12kv 2 5 35 36 37 38 Page 427.5 capacitor bank 230kv 2 314 39 capacitor bank 69kv 1 48 40 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service Number of Spare Transformers Type of Equipment Number of Units (f) (g) (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 2 125 3 4 1 3 1 4 1 5 188 1 6 83 2 7 20 1 8 20 1 9 40 2 125 3 1 10 11 capacitor bank-12kV 2 7 12 5 1 13 16 1 14 9 1 15 20 1 16 41 1 17 83 2 18 20 1 19 13 1 20 36 2 21 84 1 22 41 1 23 24 1 1872 3 2025 3 shunt reactor-525kV 1 190 25 26 1 4 83 2 28 4 1 29 20 1 30 9 1 31 83 2 2 3 33 1 34 56 capacitor bank 230kv capacitor bank-69kV 3 2 159 27 752 29 32 162 2 35 16 1 36 3 3 10 1 38 40 2 39 41 1 40 FERC FORM NO. 1 (ED. 12-96) 37 1 Page 427.6 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers CONVERSION APPARATUS AND SPECIAL EQUIPMENT 40 2 16 1 Line Total Capacity No. (In MVa) (k) 1 2 22 2 83 2 3 188 1 4 9 1 5 83 2 6 1 7 83 2 8 376 2 Type of Equipment (h) (i) capacitor bank-69kv capacitor bank-69kV Number of Units (j) 2 48 9 4 1 10 20 1 11 1 12 1 13 83 2 14 83 2 15 9 1 16 83 2 17 3 18 16 1 19 1 20 83 21 2 22 20 1 capacitor bank-69kv 1 7 23 24 1 25 1450 2 896 2 1 22 1 2 20 reactor 525kV 1 42 26 capacitor bank-115kv 2 49 28 1 capacitor bank-69kv 2 7 29 40 2 capacitor bank-69kv 1 7 30 20 1 capacitor bank-34.5k 1 4 31 65 4 138 5 capacitor bank-115kV 4 112 6 1 32 2 27 32 33 34 35 36 37 355 2 capacitor bank 230kv 2 94 83 2 capacitor bank-69kV 2 29 40 2 39 16 1 40 FERC FORM NO. 1 (ED. 12-96) Page 427.7 38 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service Number of Spare Transformers Type of Equipment Number of Units (f) (g) (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 83 2 2 83 2 3 83 2 4 40 2 9 capacitor bank-12kv 1 4 10 5 22 6 capacitor bank-69kV 2 capacitor bank-12kv 2 6 7 capacitor bank-69kV 2 14 8 83 2 9 40 2 10 11 2 12 83 83 13 2 1 14 2 15 1 16 83 2 17 83 2 18 9 1 19 5 3 20 20 1 269 3 21 1 capacitor bank-69kv 1 14 22 capacitor bank-69kv 1 7 23 capacitor bank-69kv 1 43 25 40 2 355 2 83 2 2 3 564 3 125 3 28 2 29 1 30 1 31 2 32 34 9 24 26 capacitor bank-69kv 1 53 27 33 1 34 35 83 2 40 2 36 20 1 37 83 2 38 83 2 39 41 1 FERC FORM NO. 1 (ED. 12-96) capacitor bank 69kv Page 427.8 2 14 40 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Number of Transformers In Service Capacity of Substation (In Service) (In MVa) (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 1 2 16 1 capacitor bank-69kv 1 10 2 40 2 capacitor bank-69kv 1 7 3 capacitor bank-21.6 4 10 4 capacitor bank - 12V 2 6 5 20 1 83 2 9 1 41 1 83 2 6 capacitor bank-12kv 6 7 7 capacitor bank-69kV 1 7 8 9 10 11 83 2 12 11 1 13 40 2 14 2 3 15 188 1 16 41 1 17 41 1 200 2 20 1 83 2 41 1 18 capacitor bank-69kV 4 29 19 20 capacitor bank-12kv 4 14 21 22 23 83 24 2 1 25 20 1 26 10 1 564 3 capacitor bank-69kv 1 35 28 166 3 capacitor bank-12kV 4 10 29 41 1 4500 9 27 30 31 2 reactor 525kV 2 381 32 capacitor bank 525kv 1 236 33 reactor 230kV 2 212 34 35 41 1 376 2 36 37 40 2 376 2 3 1 39 2 40 36 FERC FORM NO. 1 (ED. 12-96) capacitor bank-12kv 4 12 38 capacitor bank-69kv Page 427.9 1 12 This Report Is: Name of Respondent 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 1 83 2 2 3 1 3 16 2 capacitor bank-69kv 1 6 4 166 2 reactor 230kV 1 25 5 376 2 6 1 7 1 8 20 2 9 18 1 10 4 1 11 1 3 18 capacitor bank 69kv 1 7 12 capacitor bank-12kv 4 10 14 13 1 83 2 9 1 15 672 2 16 100 1 17 18 20 1 150 1 capacitor bank 69kV 1 14 19 84 1 capacitor bank-69kv 1 25 20 20 1 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 1 (ED. 12-96) Page 427.10 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 FOOTNOTE DATA Schedule Page: 426 Line No.: 1 Column: a STATEMENT OF CO-OWNERSHIP AS DESCRIBED IN INSTRUCTION #6, PAGE 427 AND AS NOTED ON PAGE 426. NONE OF THE CO-OWNERS IS AN ASSOCIATED COMPANY (A) CO-OWNERSHIP ON: CEDAR MOUNTAIN CHOLLA SWITCHYARD HOODOO WASH FOUR CORNERS SWITCHYARD MORGAN SUBSTATION NAVAJO SWITCHYARD NORTH GILA PINNACLE PEAK WESTWING 525KV SWITCHYARD WESTWING 230KV SWITCHYARD (1) CO-OWNERS OF CEDAR MOUNTAIN ARE SALT RIVER PROJECT, TUCSON ELECTRIC POWER COMPANY, UNITED STATES (2) CO-OWNER OF CHOLLA SWITCHYARD IS PACIFICORP (3) CO-OWNERS OF HOODOO WASH ARE IMPERIAL IRRIGATION DISTRICT, SAN DEIGO GAS & ELECTRIC (4) CO-OWNERS OF FOUR CORNER SWITCHYARD ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, PUBLIC SERVICE OF NEW MEXICO, SOUTHERN CALIFORNIA EDISON, AND TUCSON ELECTRIC POWER COMPANY (5) CO-OWNER OF MORGAN SUBSTATION IS SALT RIVER PROJECT (6) CO-OWNERS OF NAVAJO SWITCHYARD ARE SALT RIVER PROJECT, NEVADA POWER COMPANY, UNITED STATES, TUCSON ELECTRIC POWER COMPANY, AND LOS ANGELES DEPARTMENT OF WATER AND POWER (7) CO-OWNERS OF NORTH GILA SUBSTATION ARE SAN DIEGO GAS & ELECTRIC AND IMPERIAL IRRIGATION DISTRICT (8) CO-OWNER OF PINNACLE PEAK 500KV SUBSTATION AND 230KV NORTH SUBSTATION IS SALT RIVER PROJECT (9) CO-OWNERS OF WESTWING 525KV SWITCHYARD ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, TUCSON ELECTRIC POWER COMPANY, PUBLIC SERVICE COMPNANY OF NEW MEXICO, AND UNITED STATES (10) CO-OWNERS OF WESTWING 230KV SWITCHYARD ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, PUBLIC SERVICE COMPANY OF NEW MEXICO, AND UNITED STATES (B) EXPENSES FOR THE OPERATION, MAINTENANCE, AND RENTS ARE NOT SEGREGATED IN THE COMPANY'S BOOKS FOR EACH SUBSTATION (C) SUBSTATIONS THAT APS DOES NOT OWN THE MAJORITY PORTION AND IS NOT OPERATING AGENT ARE NOT LISTED ON THIS REPORT FERC FORM NO. 1 (ED. 12-87) Page 450.1 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426 Line No.: 1 A-ATTENDED D-DISTRIBUTION T-TRANSMISSION Schedule Page: 426 Line No.: 1 VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 CAPACITY IS EXPRESSED IN MVAR Schedule Page: 426 Line No.: 25 Column: b Column: c Column: d Column: e Column: k Column: f 0.025 MVa Schedule Page: 426.2 Line No.: 26 Column: f 0.25 MV Schedule Page: 426.3 Line No.: 6 Column: f 0.3 MVa Schedule Page: 426.3 Line No.: 27 Column: f Line No.: 32 Column: f Line No.: 33 Column: f 0.7 MVa Schedule Page: 426.3 0.1 MVa Schedule Page: 426.3 0.1 MVa Schedule Page: 426.4 Line No.: 8 Column: f 0.5 MVa Schedule Page: 426.4 Line No.: 22 Column: f Line No.: 36 Column: f Line No.: 39 Column: f Line No.: 10 Column: f Line No.: 27 Column: f Line No.: 32 Column: f 0.1 MVa Schedule Page: 426.4 0.1 MVa Schedule Page: 426.4 0.1 MVa Schedule Page: 426.5 0.1 MVa Schedule Page: 426.5 0.1 MVa Schedule Page: 426.5 0.1 MVa Schedule Page: 426.6 Line No.: 4 Column: f Line No.: 5 Column: f 0.1 MVa Schedule Page: 426.6 0.1 MVa Schedule Page: 426.6 Line No.: 24 Column: f 0.1 MVa Schedule Page: 426.7 Line No.: 7 Column: f 0.56 MVa Schedule Page: 426.7 Line No.: 12 Column: f 0.1 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.7 Line No.: 13 Column: f Line No.: 18 Column: f Line No.: 20 Column: f Line No.: 25 Column: f Line No.: 11 Column: f Line No.: 14 Column: f Line No.: 16 Column: f Line No.: 30 Column: f Line No.: 31 Column: f Line No.: 32 Column: f Line No.: 25 Column: f Line No.: 1 Column: f Line No.: 7 Column: f 0.01 MVa Schedule Page: 426.7 0.75 MVa Schedule Page: 426.7 0.025 MVa Schedule Page: 426.7 0.25 MVa Schedule Page: 426.8 0.5 MVa Schedule Page: 426.8 0.025 MVa Schedule Page: 426.8 0.5 MVa Schedule Page: 426.8 0.1 MVa Schedule Page: 426.8 0.25 MVa Schedule Page: 426.8 0.2 MVa Schedule Page: 426.9 0.15 MVa Schedule Page: 426.10 0.25 MVa Schedule Page: 426.10 0.5 MVa Schedule Page: 426.10 Line No.: 13 Column: f 0.1 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 Name of Respondent This Report Is: 20150811-8000 FERC PDF (Unofficial) 08/11/2015 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 04/15/2015 Year/Period of Report 2014/Q4 End of (2) X A Resubmission TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES 1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. 2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general". 3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote. Account Amount Name of Line Charged or Charged or Associated/Affiliated No. Description of the Non-Power Good or Service Company Credited Credited (a) (b) (c) (d) 1 Non-power Goods or Services Provided by Affiliated 2 Common stock dividends Pinnacle West Capital Corporation 438 253,600,000 3 Share of estimated income taxes Pinnacle West Capital Corporation 236 51,674,267 4 Share of withholding and payroll taxes Pinnacle West Capital Corporation 236,241,408 238,310,805 Pinnacle West Capital Corporation 228.3 175,580,289 Pinnacle West Capital Corporation 228.3,925,926 134,409,937 Pinnacle West Capital Corporation 143,232,242 50,357,478 10 Shared services Pinnacle West Capital Corporation various 26,641,749 11 Compensation paid in stock Pinnacle West Capital Corporation various 39,892,297 Pinnacle West Capital Corporation 228.3 19,677,100 5 Share of pension and other post retirement 6 benefits contributions 7 Share of employee benefits (excluding pension and 8 OPEB contributions) 9 Employee programs payroll deductions 12 13 14 15 16 17 18 19 20 Non-power Goods or Services Provided for Affiliate 21 Share of pension and other post retirement 22 benefits reimbursement 23 Income tax refund Pinnacle West Capital Corporation 165 137,755,146 24 Shared services Pinnacle West Capital Corporation various 12,456,350 25 Miscellaneous Pinnacle West Capital Corporation 131 30,000 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 FERC FORM NO. 1 (New) FERC FORM NO. 1-F (New) Page 429 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 429 Line No.: 4 Column: d Includes employer share of FICA allocated at 7% Schedule Page: 429 Line No.: 8 Column: d Includes benefits allocated at 37% & injuries and damages allocated at 1% Schedule Page: 429 Line No.: 10 Column: d Includes corporate allocations at 100.0% and governance allocations at 99.5% Schedule Page: 429 Line No.: 11 Column: d Includes governance allocations at 99.5% FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2015 2014/Q4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 INDEX Page No. Schedule Accrued and prepaid taxes ........................................................................ 262-263 Accumulated Deferred Income Taxes .................................................................... 234 272-277 Accumulated provisions for depreciation of common utility plant ............................................................................. 356 utility plant .................................................................................... 219 utility plant (summary) ...................................................................... 200-201 Advances from associated companies .................................................................... 256-257 Allowances ....................................................................................... 228-229 Amortization miscellaneous .................................................................................... 340 of nuclear fuel .............................................................................. 202-203 Appropriations of Retained Earnings .............................................................. 118-119 Associated Companies advances from ................................................................................ 256-257 corporations controlled by respondent ............................................................ 103 control over respondent .......................................................................... 102 interest on debt to .......................................................................... 256-257 Attestation ............................................................................................ i Balance sheet comparative .................................................................................. 110-113 notes to ..................................................................................... 122-123 Bonds ............................................................................................ 256-257 Capital Stock ........................................................................................ 251 expense .......................................................................................... 254 premiums ......................................................................................... 252 reacquired ....................................................................................... 251 subscribed ....................................................................................... 252 Cash flows, statement of ......................................................................... 120-121 Changes important during year ........................................................................ 108-109 Construction work in progress - common utility plant .......................................................... 356 work in progress - electric ...................................................................... 216 work in progress - other utility departments ................................................. 200-201 Control corporations controlled by respondent ............................................................ 103 over respondent .................................................................................. 102 Corporation controlled by .................................................................................... 103 incorporated ..................................................................................... 101 CPA, background information on ....................................................................... 101 CPA Certification, this report form ................................................................. i-ii FERC FORM NO. 1 (ED. 12-93) Index 1 20150811-8000 FERC PDF (Unofficial) 08/11/2015 INDEX (continued) Page No. Schedule Deferred credits, other ................................................................................... 269 debits, miscellaneous ............................................................................ 233 income taxes accumulated - accelerated amortization property ........................................................................ 272-273 income taxes accumulated - other property .................................................... 274-275 income taxes accumulated - other ............................................................. 276-277 income taxes accumulated - pollution control facilities .......................................... 234 Definitions, this report form ........................................................................ iii Depreciation and amortization of common utility plant .......................................................................... 356 of electric plant ................................................................................ 219 336-337 Directors ............................................................................................ 105 Discount - premium on long-term debt ............................................................. 256-257 Distribution of salaries and wages ............................................................... 354-355 Dividend appropriations .......................................................................... 118-119 Earnings, Retained ............................................................................... 118-119 Electric energy account .............................................................................. 401 Expenses electric operation and maintenance ........................................................... 320-323 electric operation and maintenance, summary ...................................................... 323 unamortized debt ................................................................................. 256 Extraordinary property losses ........................................................................ 230 Filing requirements, this report form General information .................................................................................. 101 Instructions for filing the FERC Form 1 ............................................................. i-iv Generating plant statistics hydroelectric (large) ........................................................................ 406-407 pumped storage (large) ....................................................................... 408-409 small plants ................................................................................. 410-411 steam-electric (large) ....................................................................... 402-403 Hydro-electric generating plant statistics ....................................................... 406-407 Identification ....................................................................................... 101 Important changes during year .................................................................... 108-109 Income statement of, by departments ................................................................. 114-117 statement of, for the year (see also revenues) ............................................... 114-117 deductions, miscellaneous amortization ........................................................... 340 deductions, other income deduction ............................................................... 340 deductions, other interest charges ............................................................... 340 Incorporation information ............................................................................ 101 FERC FORM NO. 1 (ED. 12-95) Index 2 20150811-8000 FERC PDF (Unofficial) 08/11/2015 INDEX (continued) Page No. Schedule Interest charges, paid on long-term debt, advances, etc ............................................... 256-257 Investments nonutility property .............................................................................. 221 subsidiary companies ......................................................................... 224-225 Investment tax credits, accumulated deferred ..................................................... 266-267 Law, excerpts applicable to this report form .......................................................... iv List of schedules, this report form .................................................................. 2-4 Long-term debt ................................................................................... 256-257 Losses-Extraordinary property ........................................................................ 230 Materials and supplies ............................................................................... 227 Miscellaneous general expenses ....................................................................... 335 Notes to balance sheet ............................................................................. 122-123 to statement of changes in financial position ................................................ 122-123 to statement of income ....................................................................... 122-123 to statement of retained earnings ............................................................ 122-123 Nonutility property .................................................................................. 221 Nuclear fuel materials ........................................................................... 202-203 Nuclear generating plant, statistics ............................................................. 402-403 Officers and officers' salaries ...................................................................... 104 Operating expenses-electric ............................................................................ 320-323 expenses-electric (summary) ...................................................................... 323 Other paid-in capital .................................................................................. 253 donations received from stockholders ............................................................. 253 gains on resale or cancellation of reacquired capital stock .................................................................................... 253 miscellaneous paid-in capital .................................................................... 253 reduction in par or stated value of capital stock ................................................ 253 regulatory assets ................................................................................ 232 regulatory liabilities ........................................................................... 278 Peaks, monthly, and output ........................................................................... 401 Plant, Common utility accumulated provision for depreciation ........................................................... 356 acquisition adjustments .......................................................................... 356 allocated to utility departments ................................................................. 356 completed construction not classified ............................................................ 356 construction work in progress .................................................................... 356 expenses ......................................................................................... 356 held for future use .............................................................................. 356 in service ....................................................................................... 356 leased to others ................................................................................. 356 Plant data ...................................................................................336-337 401-429 FERC FORM NO. 1 (ED. 12-95) Index 3 20150811-8000 FERC PDF (Unofficial) 08/11/2015 INDEX (continued) Page No. Schedule Plant - electric accumulated provision for depreciation ........................................................... 219 construction work in progress .................................................................... 216 held for future use .............................................................................. 214 in service ................................................................................... 204-207 leased to others ................................................................................. 213 Plant - utility and accumulated provisions for depreciation amortization and depletion (summary) ............................................................. 201 Pollution control facilities, accumulated deferred income taxes ..................................................................................... 234 Power Exchanges .................................................................................. 326-327 Premium and discount on long-term debt ............................................................... 256 Premium on capital stock ............................................................................. 251 Prepaid taxes .................................................................................... 262-263 Property - losses, extraordinary ..................................................................... 230 Pumped storage generating plant statistics ....................................................... 408-409 Purchased power (including power exchanges) ...................................................... 326-327 Reacquired capital stock ............................................................................. 250 Reacquired long-term debt ........................................................................ 256-257 Receivers' certificates .......................................................................... 256-257 Reconciliation of reported net income with taxable income from Federal income taxes ...................................................................... 261 Regulatory commission expenses deferred .............................................................. 233 Regulatory commission expenses for year .......................................................... 350-351 Research, development and demonstration activities ............................................... 352-353 Retained Earnings amortization reserve Federal ..................................................................... 119 appropriated ................................................................................. 118-119 statement of, for the year ................................................................... 118-119 unappropriated ............................................................................... 118-119 Revenues - electric operating .................................................................... 300-301 Salaries and wages directors fees ................................................................................... 105 distribution of .............................................................................. 354-355 officers' ........................................................................................ 104 Sales of electricity by rate schedules ............................................................... 304 Sales - for resale ............................................................................... 310-311 Salvage - nuclear fuel ........................................................................... 202-203 Schedules, this report form .......................................................................... 2-4 Securities exchange registration ........................................................................ 250-251 Statement of Cash Flows .......................................................................... 120-121 Statement of income for the year ................................................................. 114-117 Statement of retained earnings for the year ...................................................... 118-119 Steam-electric generating plant statistics ....................................................... 402-403 Substations .......................................................................................... 426 Supplies - materials and ............................................................................. 227 FERC FORM NO. 1 (ED. 12-90) Index 4 20150811-8000 FERC PDF (Unofficial) 08/11/2015 INDEX (continued) Page No. Schedule Taxes accrued and prepaid ......................................................................... 262-263 charged during year ......................................................................... 262-263 on income, deferred and accumulated ............................................................. 234 272-277 reconciliation of net income with taxable income for ............................................ 261 Transformers, line - electric ....................................................................... 429 Transmission lines added during year ..................................................................... 424-425 lines statistics ............................................................................ 422-423 of electricity for others ................................................................... 328-330 of electricity by others ........................................................................ 332 Unamortized debt discount ............................................................................... 256-257 debt expense ................................................................................ 256-257 premium on debt ............................................................................. 256-257 Unrecovered Plant and Regulatory Study Costs ........................................................ 230 FERC FORM NO. 1 (ED. 12-90) Index 5 20150811-8000 FERC PDF (Unofficial) 08/11/2015 Document Content(s) Form120141200007.PDF..................................................1-341