20160317-8000 FERC PDF (Unofficial) 03/17/2016 THIS FILING IS Item 1: X An Initial (Original) Submission OR 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) 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 "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. 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 2015/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, 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, 85004 08 Telephone of Contact Person,Including 09 This Report Is Area Code (1) X An Original (602) 250-2952 (2) A Resubmission 10 Date of Report (Mo, Da, Yr) 03/17/2016 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 03/17/2016 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of LIST OF SCHEDULES (Electric Utility) 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of LIST OF SCHEDULES (Electric Utility) (continued) 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 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) Page 3 Remarks (c) Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of LIST OF SCHEDULES (Electric Utility) (continued) 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: Two copies will be submitted No annual report to stockholders is prepared FERC FORM NO. 1 (ED. 12-96) Page 4 Remarks (c) 20160317-8000 03/17/2016 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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 20160317-8000 03/17/2016 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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, 2015, as filed with the Securities and Exchange Commission. FERC FORM NO. 1 (ED. 12-96) Page 102 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of OFFICERS 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) 1,275,458 Executive Vice President & Chief Operating Officer Mark A. Schiavoni 638,333 Executive Vice President & Chief Nuclear Officer Randall K. Edington Executive Vice President & General Counsel David P. Falck 543,083 Executive Vice President & Chief Financial Officer James R. Hatfield 592,042 Senior Vice President, Site Operations Robert S. Bement 404,583 13 Senior Vice President, Transmission, Distribution & Daniel T. Froetscher 341,771 14 Customers Senior Vice President, Public Policy Jeffrey B. Guldner 381,250 Vice President, Controller & Chief Accounting Officer Denise R. Danner 322,500 Vice President, Transmission and Distribution Operations Patrick Dinkel 284,625 Vice President, Communications John S. Hatfield 288,581 Vice President, Resource Management Tammy D. McLeod 281,967 Vice President & Treasurer Lee R. Nickloy 287,500 Vice President, Human Resources Barbara M. Gomez 335,000 1 Title Name of Officer (a) 2 3 4 5 1,048,542 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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.: 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.: 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.: 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 20, 2015. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of DIRECTORS 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 105 Line No.: 3 Column: b Ms. Clark-Johnson passed away in January 2015. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) (1)03/17/2016 An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/Q4 INFORMATION ON FORMULA RATES FERC Rate Schedule/Tariff Number FERC Proceeding Does the respondent have formula rates? 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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: 20160317-8000 FERC PDF (Unofficial) (1)03/17/2016 An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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 20150515-5146 Document Date \ Filed Date Docket No. Description 05/15/2015 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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: 20160317-8000 FERC PDF (Unofficial) (1)03/17/2016 An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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 Page 106b intentionally left blank FERC FORM NO. 1 (NEW. 12-08) Page 106b Line No Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) (1) 03/17/2016 X An Original Arizona Public Service Company (2) A Resubmission Date of Report 03/17/2016 Year/Period of Report 2015/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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 1. The town of Quartzsite franchise was approved on March 10, 2015. 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. During second quarter 2015, the following transmission line construction was completed and energized: Hassayampa-N.Gila 500kV: Reason for addition: This project will increase the import capability for the Yuma area and export/scheduling capability from the Palo Verde area and to provide access to both solar and gas resources. This project will also allow the system to accommodate generation interconnection requests. Voltage: 500kV End Points: Hassayampa switchyard & North Gila substation Construction Start: September 17, 2013 Line Construction Completed: April 30, 2015 Substation Construction Completed: May 23, 2015 HANG 2 Line Energization: May 26, 2015 Miles Constructed: 113 Arizona Corporation Commission Decision Information: CEC #135 was originally authorized in Decision No. 70127 and modified in Decision No. 74206 (both in Docket No. L-00000D-07-0566-00135) Palm Valley-Trilby Wash 230kV: Reason for addition: This project will serve the need for electric energy in the western Phoenix Metropolitan area and additional import capability into the greater Phoenix Metro area. The Trilby Wash substation will be a new transmission source for the far northwestern part of the valley, which will provide improved system reliability for communities in the area; such as El Mirage, Surprise, Youngtown, Goodyear, and Buckeye. Voltage: 230kV End Points: Palm Valley substation and Trilby Wash substation Construction Start: September 23, 2014 Line Construction Completed: May 8, 2015 Substation Construction Completed: May 21, 2015 Palm Valley – Trilby Wash Energization: May 26, 2015 Miles Constructed: 15 miles FERC FORM NO. 1 (ED. 12-96) Page 109.1 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Arizona Corporation Commission Decision Information: CEC 122 (WVS) – Docket No. L-00000D-03-0122, Decision No. 66646 CEC 127 (WVN) – Docket No. L-00000D-04-0127, Decision No. 67828 No other important extension or reduction of the transmission or distribution system service territory occurred in 2015 for APS. Only our normal additions due to customer and load growth were experienced. 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, to refinance indebtedness, and for other general corporate purposes. The table below presents the credit facilities and the amounts available and outstanding as of December 31, 2015 and 2014 (dollars in thousands): December 31, 2015 Commitments under Credit Facility Outstanding Commercial Paper Borrowings Amount of Credit Facility Available Weighted-Average Commitment Fees 2014 $1,000,000 $1,000,000 — (147,400) $1,000,000 $ 852,600 0.100% 0.125% On September 2, 2015, APS replaced its $500 million revolving credit facility that would have matured in April 2018, with a new $500 million facility that matures in September 2020. At December 31, 2015, APS had two credit facilities totaling $1 billion, including the $500 million credit facility that matures in September 2020 and a $500 million credit facility that matures in May 2019. APS may increase the amount of each facility up to a maximum of $700 million each, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2015, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. Long-Term Debt 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, 2015 and 2014 (dollars in thousands): FERC FORM NO. 1 (ED. 12-96) Page 109.2 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Maturity Interest Dates (a) Rates Variable 2029-2038 (b) Fixed 2024-2034 1.75%-5.75% December 31, 2015 2014 APS Pollution control bonds: $ 92,405 $ 211,150 249,300 303,555 405,705 3,453,695 2,902,578 Total pollution control bonds Other long-term debt 2016-2045 1.02%-8.75% Unamortized discount (10,374) Unamortized premium (a) (b) (9,206) 4,866 4,686 Total Long-Term Debt $ 156,405 3,751,562 $ 3,303,943 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 0.01%-0.24% at December 31, 2015 and 0.03%-0.27% at December 31, 2014. The following table shows principal payments due on APS’s total long-term debt (dollars in thousands): Year APS 2016 $ 357,580 2017 — 2018 82,000 2019 500,000 2020 250,000 Thereafter 2,567,670 Total $ 3,757,250 Credit Facilities and Debt Issuances 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. On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% notes due May 15, 2015. On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness. On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest FERC FORM NO. 1 (ED. 12-96) Page 109.3 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness. On November 6, 2015, APS issued $250 million of 4.35% unsecured senior notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance via redemption and cancellation at par our indebtedness related to the principal amounts of the Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A and 2009 Series C both due June 1, 2034, and repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures. On November 17, 2015, APS redeemed at par and canceled all $38 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A. On November 17, 2015, APS canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series B, purchased in connection with the mandatory tender provision on May 30, 2014. On December 8, 2015, APS redeemed at par and canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series C. Contractual Obligations The following table summarizes APS’s contractual requirements as of December 31, 2015 (dollars in millions): 20172018 20192020 414 $ 1,011 $ 4,422 $ 6,389 643 42 233 15 1,174 80 512 34 1,064 80 37 39 7,559 432 213 262 10,440 634 995 350 2 32 $ 1,509 4 61 $ 2,279 4 57 $ 2,292 62 290 $ 13,240 72 440 $ 19,320 2016 Long-term debt payments, including interest: (a) Fuel and purchased power commitments (b) Renewable energy credits (c) Purchase obligations (d) Coal reclamation Nuclear decommissioning funding requirements Operating lease payments Total contractual commitments $ 542 $ Thereafter Total (a) The long-term debt matures at various dates through 2045 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2015. (b) Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, FERC FORM NO. 1 (ED. 12-96) Page 109.4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) (c) (d) renewable energy, nuclear fuel, and natural gas transportation. These amounts include commitments incurred assuming an additional 7% in the 2016 Coal Supply Agreement. Contracts to purchase renewable energy credits in compliance with the Arizona Renewable Energy Standard and Tariff (“RES”). These contractual obligations include commitments for capital expenditures and other obligations. This table excludes $34 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. Estimated minimum required pension contributions are zero for 2016, 2017 and 2018. Financial Assurances In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of December 31, 2015, standby letters of credit totaled $79 million and will expire in 2016. As of December 31, 2015, surety bonds expiring through 2018 totaled $158 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves. 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. FERC FORM NO. 1 (ED. 12-96) Page 109.5 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 8. The union and non-union annualized wage scale increases during 2015 through December 31, 2015, were as follows: Type of Cost Number of Increases Annualized Costs a. Union Negotiated 1,455 $ b. Non-Union Base Salary Increases 3,783 10,879,983 c. Special Increases 517 1,576,453 d. Total Promotions 856 6,611 5,846,064 20,769,863 $ 2,467,363 COMMENTS: a. There were general wage increases for both the IBEW (averaging 2%) and the USPA (averaging approximately 2%) during second quarter. b. The overall non-union employee merit budget was 3.0%. Actual merit adjustments ranged from 0% to 8% based upon an employee’s performance and their pay position within the salary range. Merit pay awards were added 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 union and 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 whether 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 FERC FORM NO. 1 (ED. 12-96) Page 109.6 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) (“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. 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. APS will generally be required to consider the impact of GHG emissions as part of its traditional New Source Review ("NSR") analysis for new major sources and major modifications to existing plants. On June 2, 2014, EPA issued two 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 August 3, 2015, EPA finalized each of these carbon pollution standards for existing, new, modified, and reconstructed EGUs. EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO2 performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal. With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO2 emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two-year extension provided to states establishing a need for additional time; however, it is expected that this timing will be impacted by the court-imposed stay described below. ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, is presently working to develop a compliance plan for submittal to EPA. In addition to these on-going state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation. The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; FERC FORM NO. 1 (ED. 12-96) Page 109.7 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such delay. With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances. As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation. Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material. Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes. In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output, as an alternative to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains on-going, and additional information or considerations may arise that change our expectations. Company Response to Climate Change Initiatives. We have undertaken a number of initiatives that address emission concerns, including renewable energy procurement and development, promotion of programs and rates that FERC FORM NO. 1 (ED. 12-96) Page 109.8 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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 or otherwise a part of 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 best available retrofit technology (“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. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015), 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. In September 2014, APS met with EPA to propose a compromise BART strategy wherein, pending certain FERC FORM NO. 1 (ED. 12-96) Page 109.9 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) regulatory approvals, APS would permanently close Cholla Unit 2 (which occurred on October 1, 2015) and cease burning coal at Units 1 and 3 by the mid-2020s. APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or 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. APS’s proposal involves state and federal rulemaking processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On October 16, 2015, ADEQ issued the Cholla permit, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. APS is unable to predict when or whether APS's proposal may ultimately be approved by the EPA. 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 approximately $400 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. Completion of the purchase is subject to the receipt of certain regulatory approvals and is expected to occur in July 2016. In December 2015, NTEC notified APS of its intention to exercise its option to acquire the 7% interest from APS. The cost of the controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest. 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, based on EPA's FIP, 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. 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 $8 million for Cholla (excluding costs related to Cholla Unit 2, which was closed on October 1, 2015). No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent FERC FORM NO. 1 (ED. 12-96) Page 109.10 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) for the Navajo Plant, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million. The United States Supreme Court’s recent decision in Michigan vs. EPA reversed and remanded the MATS proceeding back to the DC Circuit Court. The Circuit Court then remanded the MATS rule back to EPA to address rulemaking deficiencies identified by the Supreme Court. Further EPA action on the MATS rule is pending. This proceeding does not materially impact APS. Regardless of how EPA addresses the deficiencies in the MATS rulemaking, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla. 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. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Effluent Limitation Guidelines. On September 30, 2015, EPA finalized revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired EGUs. EPA’s final regulation targets metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and coal ash disposal leachate. Based upon an earlier set of preferred alternatives, the final effluent limitations generally require chemical precipitation and biological treatment for flue gas desulfurization scrubber wastewater, “zero discharge” from fly ash and bottom ash handling, and impoundment for coal ash disposal leachate. Compliance with these limitations will be required in connection with National Pollution Discharge Elimination System ("NPDES") discharge permit renewals, which occur in five-year intervals, that arise between 2018 and 2023. Until a draft NPDES permit for Four Corners is proposed during that timeframe, we are uncertain what will be required to control these discharges in compliance with the finalized effluent limitations at that facility. Cholla and the Navajo Plant do not require NPDES permitting. Ozone National Ambient Air Quality Standards. On October 1, 2015, EPA finalized revisions to the primary ground-level ozone national ambient air quality standards (“NAAQS”) at a level of 70 parts per billion (“ppb”). With ozone standards becoming more stringent, our fossil generation units will come under increasing FERC FORM NO. 1 (ED. 12-96) Page 109.11 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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. EPA is expected to designate attainment and nonattainment areas relative to the new 70 ppb standard by October 1, 2017. Depending on when EPA approves attainment designations for the Arizona and Navajo Nation jurisdictions in which our fossil generation units are located, revisions to SIPs and FIPs, respectively, implementing required controls to achieve the new 70 ppb standard are expected to be in place between 2020 and 2021. At this time, because proposed SIPs and FIPs implementing the revised ozone NAAQSs have yet to be released, APS is unable to predict what impact the adoption of these standards may have on the Company. APS will continue to monitor these standards as they are implemented within the jurisdictions affecting APS. 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 New Source Performance Standards ("NSPS") program. The case was held in abeyance while APS negotiated a settlement with DOJ and environmental plaintiffs. In March 2015, the parties agreed in principle to settle the case, and on June 24, 2015, DOJ lodged the proposed consent decree with the United States District Court for the District of New Mexico. On August 17, 2015, the consent decree was entered by the district court. The settlement requires installation of pollution control technology and implementation of other measures to reduce sulfur dioxide and nitrogen oxide emissions from the two Four Corners units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule requirements. The settlement also requires the Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.7 million for certain environmental mitigation projects to benefit the Navajo Nation. APS is responsible for 15 percent of these costs based on its ownership interest in the units at the time of the alleged violations, which does not result in a material impact on our financial position, results of operations or cash flows. 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 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 FERC FORM NO. 1 (ED. 12-96) Page 109.12 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. We are unable to predict the outcome of these matters; 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, SRP, 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 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 FERC FORM NO. 1 (ED. 12-96) Page 109.13 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 litigation will have a material adverse impact on its financial position, results of operations, or cash flows. Palo Verde Nuclear Generating Station FERC FORM NO. 1 (ED. 12-96) Page 109.14 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 second breach of contract lawsuit against DOE in the United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's 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 Nuclear Waste Policy Act. 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 the amount of current reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016. APS’s first claim made pursuant to the terms of the August 18, 2014 settlement agreement, which was for the period July 1, 2011 through June 30, 2014, and was for $42.0 million (APS’s share of this amount was $12.2 million), was received on June 1, 2015. APS's $12.2 million share was recorded as an adjustment to a regulatory liability and had no impact on the amount of current reported net income. APS’s second claim made pursuant to the terms of the August 18, 2014 settlement agreement, which was for the period July 1, 2014 through June 30, 2015, was filed for $12.0 million (APS's share of this amount would be $3.6 million), and has been submitted to, but not yet approved by, the DOE in the fourth quarter of 2015. Southwest Power Outage 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. 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 United States Court of Appeals for the Ninth Circuit, which heard oral argument on February 9, 2016. A written decision on the case is expected 30-60 days after oral argument. We believe the District Court's decision will be upheld on appeal, but cannot predict the outcome at the appellate court. If the District Court's decision is reversed, the case would be remanded for discovery and trial, and there is insufficient information at this time to reasonably estimate any possible loss or range of loss to APS and Pinnacle West. Notice of Intent to Sue Related to Four Corners On December 21, 2015, several environmental groups filed a notice of intent to sue with the Office of Surface Mining Reclamation and Enforcement (“OSM”) and other federal agencies under the Endangered Species FERC FORM NO. 1 (ED. 12-96) Page 109.15 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Act alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the DOI's review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. We are monitoring this matter and will intervene if a lawsuit is filed. We cannot predict the timing or outcome of this matter. New Mexico Tax Matter On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") 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 NMTRD 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. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed an appeal of the decision on August 31, 2015. The parties are engaged in settlement discussions and 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 Filings with the Arizona Corporation Commission Upcoming Rate Case Filing On January 29, 2016, APS filed a NOI informing the ACC that APS intends to submit a rate case application in June 2016 using an adjusted test year ending December 31, 2015. The NOI provides an overview of the key issues APS expects to address in its formal request such as rate design changes (residential, commercial and industrial), a decoupling mechanism, permission to defer for potential future recovery costs associated with the Company’s Ocotillo Modernization Project, permission to defer for potential future recovery costs associated with environmental standards compliance, inclusion of post-test year plant and modifications to certain adjustor mechanisms, among other items. In its rate application, APS will request that its proposed pricing changes take effect in July 2017. APS is still developing the exact amount of the request. Prior Rate Case Filing 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 FERC FORM NO. 1 (ED. 12-96) Page 109.16 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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. 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; 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 109.17 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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. 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 went into effect on April 21, 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, called the "Solar Partner 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 requested budget to approximately $152 million. On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget. 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. FERC FORM NO. 1 (ED. 12-96) Page 109.18 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS’s resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism. On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%. Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards 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 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 rulemaking 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; FERC FORM NO. 1 (ED. 12-96) Page 109.19 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 (liability) for 2015 and 2014 (dollars in thousands): Year Ended December 31, 2015 Beginning balance $ Deferred fuel and purchased power costs - current period 6,926 2014 $ (14,997) Amounts charged to customers 26,927 (40,756) (1,617) Ending balance $ (9,688) 20,755 $ 6,926 The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year. This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh. On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017. 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. FERC FORM NO. 1 (ED. 12-96) Page 109.20 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 Charges 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. Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 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, 2015. APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future. 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. APS files for a LFCR adjustment every January. 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, which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. Net Metering On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift FERC FORM NO. 1 (ED. 12-96) Page 109.21 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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. 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 electric grid. The fixed charge does not increase APS's revenue because it is credited to the LFCR. 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 electric grid. The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing has been scheduled to commence in April 2016. APS cannot predict the outcome of this proceeding. In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS has also requested intervention in the upcoming Tucson Electric Power Company rate case. The outcomes of these proceedings will not directly impact our financial position. Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB") In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case. The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision. On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument is set for March 22, 2016. If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter. 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 FERC FORM NO. 1 (ED. 12-96) Page 109.22 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 $70 million as of December 31, 2015 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. We cannot predict when or how this matter will be resolved. 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. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS has established a regulatory asset of $12 million at December 31, 2015 in connection with the expiration of the Transmission Agreement, which it expects to recover through its FERC-jurisdictional rates. Cholla On September 11, 2014, APS announced that it would close Cholla Unit 2 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. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and plans to seek recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its next retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($122 million as of December 31, 2015), 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 FERC FORM NO. 1 (ED. 12-96) Page 109.23 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 13. Board and Officer Elections, Retirements, Resignations and Changes During 2015: Directors – Susan Clark-Johnson, passed away on January 28, 2015. Officers – Brad Berryman, Vice President Site Operations and General Plant Manager, Palo Verde Nuclear Generating Station, resigned January 6, 2015. Barbara Lockwood, formerly General Manager of Regulatory Policy and Compliance, became Vice President of Regulation on October 21, 2015. 14. N/A FERC FORM NO. 1 (ED. 12-96) Page 109.24 Name of RespondentFERC PDF (Unofficial) This Report Is: 20160317-8000 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report 03/17/2016 End of 2015/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) 17,080,761,645 713,287,335 17,794,048,980 6,402,411,202 11,391,637,778 99,557,610 845 269,365,593 0 0 146,227,544 222,696,504 11,614,334,282 0 0 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 6,088,897 1,562,163 0 0 5,464,063 1,553,033 0 0 0 0 0 0 0 918,129,534 0 15,959,853 0 938,616,121 0 0 0 713,865,964 0 149,570,873 0 24,809,980 0 892,157,847 0 113,921 0 2,868,225 19,074,143 4 210,352,179 64,070,363 3,124,684 0 5,261 38,345,560 0 0 232,937,102 0 0 0 7,351,348 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 Name of RespondentFERC PDF (Unofficial) This Report Is: 20160317-8000 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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 1,296,535 0 0 32,489,126 0 0 0 96,240,054 51,231,500 53,367,798 15,959,853 0 0 790,658,582 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 27,895,985 0 0 1,334,174,106 5,982,037 0 0 214,803 0 122,124,425 0 0 17,890,348 852,940,853 0 2,361,222,557 15,704,831,542 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 Name of RespondentFERC PDF (Unofficial) This Report is: 20160317-8000 03/17/2016 (1) x An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report Date of Report (mo, da, yr) 03/17/2016 end of 2015/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 2,148,493,189 0 0 0 -27,097,083 4,679,254,873 178,162,368 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 4,478,245,279 303,555,000 0 0 3,453,695,075 4,686,330 10,373,885 3,751,562,520 405,705,000 0 0 2,902,577,791 4,866,574 9,206,464 3,303,942,901 186,209,060 0 515,308 505,338,198 0 294,496 92,213,397 1,613,757 443,576,528 1,229,760,744 193,313,000 0 873,663 467,078,279 0 359,288 80,257,408 2,732,932 390,749,875 1,135,364,445 0 291,567,656 0 84,985,708 73,072,613 154,011,438 56,807,168 0 0 147,400,000 289,929,529 0 92,873,341 72,306,606 142,296,215 53,343,674 0 0 Name of RespondentFERC PDF (Unofficial) This Report is: 20160317-8000 03/17/2016 (1) x An Original Arizona Public Service Company (2) A Resubmission Date of Report (mo, da, yr) 03/17/2016 Year/Period of Report end of 2015/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 6,131 169,328,681 7,103,830 204,130,617 92,213,397 3,268,559 1,613,757 950,455,247 0 422 147,671,684 21,497,000 164,873,458 80,257,408 4,178,126 2,732,932 1,053,379,715 115,609,383 187,080,422 12,760 268,889,494 879,524,513 328,382 0 3,032,795,795 609,557,409 5,093,798,158 15,704,831,542 123,052,363 178,607,210 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 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of STATEMENT OF INCOME 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 3,519,645,174 3,522,222,472 4 Operation Expenses (401) 320-323 1,768,447,876 1,865,748,372 5 Maintenance Expenses (402) 320-323 231,357,405 241,133,018 6 Depreciation Expense (403) 336-337 385,402,361 367,155,333 2 Operating Revenues (400) 3 Operating Expenses 7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337 70,077 -923,459 8 Amort. & Depl. of Utility Plant (404-405) 336-337 70,747,118 71,678,968 9 Amort. of Utility Plant Acq. Adj. (406) 336-337 10,873,443 453,060 55,045 55,045 6,688,721 278,697 10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 11 Amort. of Conversion Expenses (407) 12 Regulatory Debits (407.3) -293,623 31,942,337 14 Taxes Other Than Income Taxes (408.1) 262-263 197,728,627 198,164,185 15 Income Taxes - Federal (409.1) 262-263 21,013,707 39,109,116 13 (Less) Regulatory Credits (407.4) 8,798,827 15,398,957 17 Provision for Deferred Income Taxes (410.1) 234, 272-277 838,754,779 1,152,367,603 18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 608,242,675 960,800,421 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) 22 (Less) Gains from Disposition of Allowances (411.8) 500,880 53,143 23 Losses from Disposition of Allowances (411.9) 447,680 393,324 25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 2,927,361,941 2,953,642,525 26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 592,283,233 568,579,947 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 3,519,645,174 3,522,222,472 1,768,447,876 1,865,748,372 4 231,357,405 241,133,018 5 385,402,361 367,155,333 6 70,077 -923,459 7 70,747,118 71,678,968 8 10,873,443 453,060 9 55,045 55,045 10 6,688,721 278,697 12 2 3 11 -293,623 31,942,337 13 197,728,627 198,164,185 14 21,013,707 39,109,116 15 8,798,827 15,398,957 16 838,754,779 1,152,367,603 17 608,242,675 960,800,421 18 4,573,793 4,573,793 500,880 53,143 22 447,680 393,324 23 2,927,361,941 2,953,642,525 25 592,283,233 568,579,947 26 19 20 21 24 FERC FORM NO. 1 (ED. 12-96) Page 115 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 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) 592,283,233 568,579,947 1,949,265 1,637,402 1,500 26,228 4,731 947,281 915,724 1,500 23,504 75,419 163,181 35,214,865 100,695,289 715,765 137,080,966 688,652 30,789,970 98,193,348 1,196,300 130,953,242 2,219,096 615,446 2,277,953 1,998,442 -274,394 3,147,962 110,346,098 117,716,715 -2,492,000 2,883,694 104,534,926 107,540,508 308,601 -5,702,824 -985,426 722,200 1,718,654 708,811 646,451 199,519 268,954 2,844,230 6,617,182 -13,993,285 33,357,536 5,946,124 -6,966,619 30,379,353 179,563,539 3,574,447 1,441,956 180,243 43,303 183,271,589 2,955,733 1,435,287 180,243 43,303 7,193,611 16,183,284 175,366,723 450,274,046 5,756,428 15,457,061 177,738,430 421,220,870 450,274,046 421,220,870 119 262-263 262-263 262-263 234, 272-277 234, 272-277 262-263 Page 117 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) 1,968,719,143 1,804,398,273 450,274,046 421,220,870 -270,500,000 ( 256,900,000) -270,500,000 ( 256,900,000) 2,148,493,189 1,968,719,143 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) 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 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) 2,148,493,189 1,968,719,143 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of STATEMENT OF CASH FLOWS (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) 450,274,046 421,220,870 4 Depreciation and Depletion 385,472,438 366,231,874 5 Amortization of UTL PLT; ACQ; ADJ; Prop Loss; Reg Study; Nuclear Fuel 165,899,295 119,652,444 3 Noncash Charges (Credits) to Income: 6 7 Deferred Fuel and Purchased Power 8 Deferred Income Taxes (Net) 16,613,022 13,829,926 225,814,123 164,038,909 9 Investment Tax Credit Adjustment (Net) 8,473,212 26,246,228 10 Net (Increase) Decrease in Receivables -16,748,117 -56,202,973 11 Net (Increase) Decrease in Inventory -21,427,295 7,127,553 -2,517,423 -3,403,735 12 Net (Increase) Decrease in Allowances Inventory 13 Net Increase (Decrease) in Payables and Accrued Expenses 14 Net (Increase) Decrease in Other Regulatory Assets 15 Net Increase (Decrease) in Other Regulatory Liabilities 16 (Less) Allowance for Other Funds Used During Construction -46,378,798 21,416,488 -163,062,404 -74,694,494 -27,989,767 66,971,000 35,214,865 30,789,970 105,711,689 17 (Less) Undistributed Earnings from Subsidiary Companies 18 Other (provide details in footnote): 19 Other Current Assets 28,545,473 20 Other Current Liabilities 24,087,552 28,538,220 21 Other Long Term Assets/Liabilities Net 59,769,064 -97,657,825 1,051,609,556 1,078,236,204 -1,024,915,891 -844,836,115 -83,672,189 -76,296,155 16,183,284 15,457,061 46,546,059 20,325,000 -1,078,225,305 -916,264,331 478,813,436 356,194,667 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 (a) 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of STATEMENT OF CASH FLOWS (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 (a) -496,062,379 -373,443,610 36,535,000 11,048,052 -1,093,573 346,784 -1,060,032,821 -922,118,438 842,414,500 606,126,000 842,414,500 606,126,000 -402,150,000 -502,129,000 -147,400,000 -5,725,000 -266,900,000 -253,600,000 25,964,500 -155,328,000 17,541,235 789,766 4,515,054 3,725,288 22,056,289 4,515,054 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) 67 Other (provide details in footnote): 68 69 70 Cash Provided by Outside Sources (Total 61 thru 69) 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) 79 80 Dividends on Preferred Stock 81 Dividends on Common Stock 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 120 Line No.: 19 Risk Management Notes Receivable Prepaids Column: b $ 27,268,231 924,988 352,254 28,545,473 $ Schedule Page: 120 Line No.: 19 Prepaids Risk Management Column: c $ 133,977,797 (28,266,108) 105,711,689 $ Schedule Page: 120 Line No.: 20 Transmission Termination Agreement Accrued Taxes Payroll Accrual SCE Right of Way Four Corners Take or Pay Interest Accrued Other Customer Deposits Palo Verde Sale Leaseback Tolling Agreements Exchange Carbon Allowance Risk Management Employee Benefits PVVIE Capital Lease Column: b $ 18,000,000 11,715,223 8,346,212 6,593,895 4,601,788 3,463,494 1,624,998 766,008 (113,622) (1,814,786) (2,479,935) (2,644,370) (3,063,764) (6,514,419) (14,393,170) 24,087,552 $ Schedule Page: 120 Line No.: 20 Interest Accrued Accrued Taxes Employee Benefits Carbon Allowance SCE Right of Way Tolling Agreements Exchange Palo Verde Sale Leaseback Risk Management Other Payroll Accrual Customer Deposits Column: c $ 9,863,387 9,787,678 9,502,694 3,408,027 2,279,271 1,511,300 1,484,640 (4,634) (75,000) (2,663,184) (2,761,795) (3,794,164) 28,538,220 $ Schedule Page: 120 Line No.: 21 Post-Employment Benefits FERC FORM NO. 1 (ED. 12-87) Column: b $ 114,608,409 Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Risk Management Nuclear Decommissioning Trust Other Carbon Allowances Coal Reclaimation Transmission Debits Software License Agreement High Lonesome Wind Ranch Tax Credit Information Systems Maintenance Palo Verde Water Supply Line of Credit Superfund Rouse Lease Palo Verde Sale/Leaseback Transmission Termination Agreement Tolling Agreements Customer Advances for Construction Regulatory Asset Amortization Depreciation Fund Utility Plant Deferred Fuel MTM 37,737,071 17,248,943 6,997,958 5,189,847 3,691,702 1,808,247 1,195,391 1,083,722 682,660 421,224 (101,516) (157,271) (4,544,333) (4,747,577) (6,000,000) (6,721,746) (7,563,992) (8,377,665) (21,330,474) (27,245,454) (44,106,082) 59,769,064 $ Schedule Page: 120 Line No.: 21 Column: c Depreciation Fund Deferred Fuel MTM Utility Plant Post-Employment Benefits Other Coal Reclaimation Tolling Agreements Palo Verde Sale/Leaseback Rouse Lease Information Systems Maintenance High Lonesome Wind Ranch Tax Credit Superfund Line of Credit Palo Verde Water Supply Transmission Termination Agreement Customer Advances for Construction Nuclear Decommissioning Trust Regulatory Asset Amortization OPEB Risk Management $ $ FERC FORM NO. 1 (ED. 12-87) (71,858,774) (63,672,305) (37,590,372) (32,930,945) (19,674,727) (9,161,037) (6,701,732) (4,747,579) (3,769,372) (2,495,797) (1,083,722) (176,453) 201,002 219,765 6,000,000 10,095,245 17,248,943 30,234,588 28,194,507 64,010,940 (97,657,825) Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 120 Line No.: 54 Grant Street Land Purchase 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) (624,834) (480,267) 11,528 (1,093,573) 385,367 (38,583) 346,784 Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) (1) 03/17/2016 X An Original Arizona Public Service Company (2) A Resubmission Date of Report 03/17/2016 Year/Period of Report End of 2015/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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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, not reporting debt issuance costs as reduction of long term debt, and certain other items. APS’ 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 considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to FERC FORM NO. 1 (ED. 12-88) Page 123.1 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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: material and labor; contractor costs; capitalized leases; construction overhead costs (where applicable); and allowance for funds used during construction. FERC FORM NO. 1 (ED. 12-88) Page 123.2 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2015 were as follows: Fossil plant — 19 years; Nuclear plant — 28 years; Other generation — 25 years; Transmission — 39 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 are now being amortized on the regulatory debits line of the Comparative Statements of Income. Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. For the years 2013 through 2015, the depreciation rates ranged from a low of 0.30% to a high of 12.37%. The weighted-average depreciation rate was 2.74% in 2015, 2.77% in 2014, and 3.00% in 2013. 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 8.02% for 2015, 8.47% for 2014, and 8.56% for 2013. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.3 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 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. FERC FORM NO. 1 (ED. 12-88) Page 123.4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 Postretirement 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 May 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. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.5 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table summarizes supplemental APS cash flow information for each of the last two years (dollars in thousands): Year ended December 31, 2015 2014 Cash paid (received) during the period for: Income taxes, net of refunds $ Interest, net of amounts capitalized 14,831 $ 167,670 (86,054) 173,436 Significant non-cash investing and financing activities: Accrued capital expenditures $ Dividends declared but not paid 83,798 $ 44,712 69,400 65,800 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 $58 million in 2015, and $53 million in 2014. Estimated amortization expense on existing intangible assets over the next five years is $48 million in 2016, $36 million in 2017, $18 million in 2018, $9 million in 2019, and $3 million in 2020. At December 31, 2015, the weighted-average remaining amortization period for intangible assets was 5 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, 2015, 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 19, 2016, 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 March 17, 2016. The accompanying statements contain all adjustments and disclosures necessary for fair presentation. 3. New Accounting Standards FERC FORM NO. 1 (ED. 12-88) Page 123.6 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. The new revenue standard will be effective for us on January 1, 2018. The guidance may be adopted using a 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 FERC financial statements. In February 2015, new consolidation accounting guidance was issued that amends many aspects of the guidance relating to the analysis and consolidation of variable interest entities. We do not expect the issuance of this guidance to have a material impact on our FERC financial statements. In January 2016, new guidance was issued relating to the recognition and measurement of financial instruments. The amended guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new guidance is effective for us on January 1, 2018. Certain aspects of the guidance may require a cumulative-effect adjustment and other aspects of the guidance are required to be adopted prospectively. We are currently evaluating this new accounting standard and the impacts it may have on our FERC financial statements. 4. Regulatory Matters Retail Rate Case Filings with the Arizona Corporation Commission Upcoming Rate Case Filing On January 29, 2016, APS filed a NOI informing the ACC that APS intends to submit a rate case application in June 2016 using an adjusted test year ending December 31, 2015. The NOI provides an overview of the key issues APS expects to address in its formal request such as rate design changes (residential, commercial and industrial), a decoupling mechanism, permission to defer for potential future recovery costs associated with the Company’s Ocotillo Modernization Project, permission to defer for potential future recovery costs associated with environmental standards compliance, inclusion of post-test year plant and modifications to certain adjustor mechanisms, among other items. In its rate application, APS will request that its proposed pricing changes take effect in July 2017. APS is still developing the exact amount of the request. Prior Rate Case Filing 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 FERC FORM NO. 1 (ED. 12-88) Page 123.7 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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; 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. FERC FORM NO. 1 (ED. 12-88) Page 123.8 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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 went into effect on April 21, 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, called the "Solar Partner 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 requested budget to approximately $152 million. On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.9 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS’s resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism. On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%. Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards 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 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 rulemaking 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 FERC FORM NO. 1 (ED. 12-88) Page 123.10 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 (liability) for 2015 and 2014 (dollars in thousands): Year Ended December 31, 2015 Beginning balance $ Deferred fuel and purchased power costs - current period Amounts charged to customers Ending balance $ 6,926 2014 $ 20,755 (14,997) 26,927 (1,617) (40,756) (9,688) $ 6,926 The PSA rate for the PSA year beginning February 1, 2016 is $0.001678 per kWh, as compared to $0.000887 per kWh for the prior year. This new rate is comprised of a forward component of $0.001975 per kWh and a historical component of $(0.000297) per kWh. On October 15, 2015, APS notified the ACC that it was initiating a PSA transition component of $(0.004936) per kWh for the months of November 2015, December 2015, and January 2016. The PSA transition component is a mid-year adjustment to the PSA rate that may be established when conditions change sufficiently to cause high balances to accrue in the PSA balancing account. The transition component expired on February 1, 2016. Any uncollected (overcollected) deferrals during the PSA year, after accounting for the transition component, will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2017. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.11 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 Charges 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. Effective June 1, 2015, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $17.6 million for the twelve-month period beginning June 1, 2015 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, 2015. APS's formula rate protocols have been in effect since 2008. Recent FERC orders suggest that FERC is examining the structure of formula rate protocols and may require companies such as APS to make changes to their protocols in the future. 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. APS files for a LFCR adjustment every January. 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, which was approved on March 2, 2015, effective for the first billing cycle of March. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.12 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. 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 electric grid. The fixed charge does not increase APS's revenue because it is credited to the LFCR. 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 electric grid. The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift. On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing has been scheduled to commence in April 2016. APS cannot predict the outcome of this proceeding. In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS has also requested intervention in the upcoming Tucson Electric Power Company rate case. The outcomes of these proceedings will not directly impact our financial position. Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB") In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case. The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision. On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument is set for March 22, 2016. If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.13 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $70 million as of December 31, 2015 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above, which could have an effect on the outcome of this Four Corners proceeding. We cannot predict when or how this matter will be resolved. 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. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS has established a regulatory asset of $12 million at December 31, 2015 in connection with the expiration of the Transmission Agreement, which it expects to recover through its FERC-jurisdictional rates. Cholla On September 11, 2014, APS announced that it would close Cholla Unit 2 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. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS is currently recovering a return on and of the net book value of the unit in base rates and plans to seek recovery of the unit’s decommissioning and other retirement-related costs over the remaining life of the plant in its next retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($122 million as of December 31, 2015), 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. FERC FORM NO. 1 (ED. 12-88) Page 123.14 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in thousands): December 31, 2015 Pension and other postretirement benefits (a) $ 2014 619,223 $ 485,037 Income taxes - AFUDC equity 139,207 123,209 Deferred fuel and purchased power — mark-to-market (Note 13) 141,549 97,442 Transmission vegetation management 4,543 13,629 Coal reclamation 6,503 6,921 34,751 34,162 — 6,926 Tax expense of Medicare subsidy 13,683 15,284 Prior flow through of tax benefits 3,520 5,500 50,228 47,916 — 4,238 Lost fixed cost recovery 45,507 37,612 Retired power plant costs 137,431 146,095 Four Corners cost deferral 70,271 77,253 Deferred property taxes 50,453 30,283 Mead - Phoenix Transmission Line CIAC 11,372 11,704 5,933 3,874 $ 1,334,174 $ 1,147,085 Deferred compensation Deferred fuel and purchased power (b) (c) Income taxes — investment tax credit basis adjustment Pension and other postretirement benefits deferral Other Total regulatory assets (d) (a) This asset represents the future recovery of pension benefit obligations 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. See Note 8 for further discussion. (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, Transmission Cost Adjustor and Other Transmission Matters.” FERC FORM NO. 1 (ED. 12-88) Page 123.15 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The detail of regulatory liabilities is as follows (dollars in thousands): December 31, 2015 Asset retirement obligations $ 2014 277,554 $ 295,546 Renewable energy standard (a) 48,138 47,273 Income taxes - change in rates 76,553 75,844 Spent nuclear fuel 70,488 69,990 8,063 10,000 100,779 96,232 3,520 5,500 Demand side management (a) 25,194 31,335 Other postretirement benefits 213,621 230,915 8,920 1,200 13,678 12,069 9,688 — Deferred gains on utility property Income taxes — deferred investment tax credit Excess deferred taxes Four Corners coal reclamation Sundance maintenance Deferred fuel and purchased power Other (a) 5. 23,263 23,328 Total regulatory liabilities $ 879,524 $ 899,167 See “Cost Recovery Mechanisms” discussion above. Income Taxes 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 income 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, investment tax credit basis adjustment and tax expense of Medicare subsidy. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.16 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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 2015 Current: Federal State Total current Deferred: Federal State Total deferred Total income tax expense $ $ 15,311 7,813 23,124 199,681 23,217 222,898 246,022 $ $ 39,756 15,598 55,354 166,426 16,620 183,046 238,400 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, 2015 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 2) Investment tax credit amortization Other Income tax expense $ 243,640 2014 $ 20,433 $ (1,710) 837 (9,711) (5,527) (1,940) 246,022 $ 230,503 21,148 — 830 (8,523) (4,928) (630) 238,400 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, APS 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, 2015, APS has recorded a regulatory liability of $75 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, APS 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, 2015, 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 123.17 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The components of the net deferred income tax liability were as follows (dollars in thousands): December 31, 2015 DEFERRED TAX ASSETS Regulatory liabilities: Asset retirement obligation and removal costs Unamortized investment tax credits Other postretirement benefits Other Risk management activities Pension liabilities Renewable energy incentives 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 benefits Retired power plant costs (see Note 4) Other Other Total deferred tax liabilities Deferred income taxes — net 6. $ $ 107,885 100,779 83,034 61,868 80,616 181,787 60,956 176,016 852,941 2014 $ 115,825 96,232 90,496 61,604 66,251 194,541 65,169 161,379 851,497 (3,032,796) (20,744) (70,986) (2,877,990) (20,917) (58,495) (54,110) — (55,020) (240,692) (53,420) (109,601) (4,984) (3,642,353) (2,789,412) $ (48,286) (2,498) (38,187) (191,747) (57,255) (100,318) (5,484) (3,401,777) (2,549,680) 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, to refinance indebtedness, and for other general corporate purposes. The table below presents the credit facilities and the amounts available and outstanding as of December 31, 2015 and 2014 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.18 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) December 31, 2015 Commitments under Credit Facility Outstanding Commercial Paper Borrowings Amount of Credit Facility Available Weighted-Average Commitment Fees 2014 $1,000,000 $1,000,000 — (147,400) $1,000,000 $ 852,600 0.100% 0.125% On September 2, 2015, APS replaced its $500 million revolving credit facility that would have matured in April 2018, with a new $500 million facility that matures in September 2020. At December 31, 2015, APS had two credit facilities totaling $1 billion, including the $500 million credit facility that matures in September 2020 and a $500 million credit facility that matures in May 2019. APS may increase the amount of each facility up to a maximum of $700 million each, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2015, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 11 for a discussion of APS's other outstanding letters of credit. Debt Provisions On February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of 7% of APS’s capitalization, and $500 million (which is required to be used for costs relating to purchases of natural gas and power). This financing order is set to expire on December 31, 2017. See Note 7 for additional long-term debt provisions. 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, 2015 and 2014 (dollars in thousands): Maturity Interest December 31, Dates (a) Rates Variable 2029-2038 (b) Fixed 2024-2034 1.75%-5.75% 211,150 303,555 405,705 2016-2045 1.02%-8.75% 3,453,695 2,902,578 2015 2014 APS Pollution control bonds: $ Total pollution control bonds Other long-term debt 92,405 $ 156,405 249,300 Unamortized discount (10,374) (9,206) Unamortized premium 4,686 4,866 Total Long-Term Debt FERC FORM NO. 1 (ED. 12-88) $ Page 123.19 3,751,562 $ 3,303,943 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) (b) 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 0.01%-0.24% at December 31, 2015 and 0.03%-0.27% at December 31, 2014. The following table shows principal payments due on APS’s total long-term debt (dollars in thousands): Year APS 2016 $ 357,580 2017 — 2018 82,000 2019 500,000 2020 250,000 Thereafter 2,567,670 Total $ 3,757,250 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 thousands): As of December 31, 2015 Carrying Amount Total $ 3,694,971 As of December 31, 2014 Carrying Amount Fair Value $ 3,981,367 $ 3,265,143 Fair Value $ 3,714,108 Credit Facilities and Debt Issuances 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. On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% notes due May 15, 2015. FERC FORM NO. 1 (ED. 12-88) Page 123.20 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness. On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness. On November 6, 2015, APS issued $250 million of 4.35% unsecured senior notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance via redemption and cancellation at par our indebtedness related to the principal amounts of the Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A and 2009 Series C both due June 1, 2034, and repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures. On November 17, 2015, APS redeemed at par and canceled all $38 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A. On November 17, 2015, APS canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series B, purchased in connection with the mandatory tender provision on May 30, 2014. On December 8, 2015, APS redeemed at par and canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series C. See “Lines of Credit and Short-Term Borrowings” in Note 6 and “Financial Assurances” in Note 11 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, 2015, the ratio was approximately 46% 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 FERC FORM NO. 1 (ED. 12-88) Page 123.21 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2015, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.7 billion, and total capitalization was approximately $8.6 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.4 billion, assuming APS’s total capitalization remains the same. 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 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 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. See Note 6 for additional short-term debt provisions. 8. Retirement Plans and Other Postretirement 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. FERC FORM NO. 1 (ED. 12-88) Page 123.22 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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). The 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. 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 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 three years beginning in July 2012. We amortized approximately $5 million in 2015, $8 million in 2014, $8 million in 2013 and $4 million in 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): Other Benefits Pension 2015 Service cost-benefits earned during the $ period Interest cost on benefit obligation Expected return on plan assets 2014 59,627 $ 2015 53,080 $ 16,827 2014 $ 18,139 123,983 129,194 28,102 41,243 (179,231) (158,998) (36,855) (46,400) (37,968) (9,626) 4,881 1,175 Amortization of: Prior service cost (credit) Net actuarial loss 594 869 31,056 10,963 Net periodic benefit cost $ 36,029 $ 35,108 $ (25,013) $ 4,531 Portion of cost charged to expense $ 20,036 $ 21,985 $ (10,391) $ 6,000 FERC FORM NO. 1 (ED. 12-88) Page 123.23 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows the plans’ changes in the benefit obligations and funded status for the years 2015 and 2014 (dollars in thousands): Pension 2015 Other Benefits 2014 2015 2014 Change in Benefit Obligation Benefit obligation at January 1 $ 3,078,648 $ 2,646,530 $ 682,335 $ 890,418 Service cost 59,627 53,080 16,827 18,139 Interest cost 123,983 129,194 28,102 41,243 (137,115) (128,550) (24,988) (29,054) (91,340) 378,394 (55,256) 150,188 Benefit payments Actuarial (gain) loss — — — 3,033,803 3,078,648 647,020 682,335 2,615,404 2,264,121 834,625 748,339 Plan amendments Benefit obligation at December 31 (388,599) Change in Plan Assets Fair value of plan assets at January 1 Actual return on plan assets (44,690) 292,992 Employer contributions 100,000 175,000 791 (127,940) (116,709) — Benefit payments Fair value of plan assets at December 31 Funded Status at December 31 2,615,404 2,542,774 $ (2,399) (491,029) $ 105,223 770 (19,707) 833,017 (463,244) $ 834,625 185,997 $ 152,290 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, 2015 and 2014 (dollars in thousands): 2015 Projected benefit obligation $ 2014 3,033,803 $ 3,078,648 Accumulated benefit obligation 2,873,467 2,873,741 Fair value of plan assets 2,542,774 2,615,404 The following table shows the amounts recognized on the Comparative Balance Sheets as of December 31, 2015 and 2014 (dollars in thousands): Pension 2015 Noncurrent asset $ Current liability Noncurrent liability Other Benefits 2014 — $ 2015 — $ 2014 185,997 $ 152,290 (10,031) (9,508) — — (480,998) (453,736) — — (491,029) $ (463,244) Net amount recognized $ FERC FORM NO. 1 (ED. 12-88) Page 123.24 $ 185,997 $ 152,290 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows the details related to accumulated other comprehensive loss as of December 31, 2015 and 2014 (dollars in thousands): Pension Other Benefits 2015 Net actuarial loss $ 2014 679,501 Prior service cost (credit) $ 577,976 609 APS’s portion recorded as a regulatory (asset) liability Income tax expense (benefit) Accumulated other comprehensive loss 2015 $ 2014 127,124 1,203 $ 148,006 (341,301) (379,269) (619,223) (485,037) 213,621 230,916 (23,663) (36,890) 925 851 $ 37,224 $ 57,252 $ 369 $ 504 The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2016 (dollars in thousands): Other Benefits Pension Net actuarial loss $ 38,923 Prior service cost (credit) $ (37,884) 527 Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2016 $ 39,450 3,784 $ (34,100) 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: Benefit Obligations As of December 31, 2015 Benefit Costs For the Years Ended December 31, 2014 2015 2014 January September October December Discount rate – pension 4.37% 4.02% 4.02% 4.88% 4.88% Discount rate – other benefits 4.52% 4.14% 4.14% 5.10% 4.41% Rate of compensation increase 4.00% 4.00% 4.00% 4.00% 4.00% Expected long-term return on plan assets pension N/A N/A 6.90% 6.90% 6.90% Expected long-term return on plan assets other benefits N/A N/A 4.45% 6.80% 4.25% Initial healthcare cost trend rate (pre-65 participants) 7.00% 7.00% 7.00% 7.50% 7.50% Initial healthcare cost trend rate (post-65 participants) 5.00% 5.00% 5.00% 7.50% 5.00% Ultimate healthcare cost trend rate 5.00% 5.00% 5.00% 5.00% 5.00% Number of years to ultimate trend rate (pre-65 participants) 4 4 4 4 4 Number of years to ultimate trend rate (post-65 participants) 0 0 0 4 0 FERC FORM NO. 1 (ED. 12-88) Page 123.25 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 2016, 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 thousands): 1% Increase 1% Decrease Effect on other postretirement benefits expense, after consideration of amounts capitalized or $ billed to electric plant participants 8,834 $ (5,890) Effect on service and interest cost components of net periodic other postretirement benefit costs 9,069 (6,949) 100,322 (80,332) Effect on the accumulated other postretirement benefit obligation 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 FERC FORM NO. 1 (ED. 12-88) Page 123.26 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 2015, 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, 2015, long-term fixed income assets represented 60% of total pension plan assets, and return-generating assets represented 40% of total pension plan assets. As of December 31, 2015, 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, 2015, investment in fixed income assets represented 40% of the other postretirement benefit plan total assets, and non-fixed income assets represented 60% 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 mutual funds, partnerships and common and collective trusts. Equity 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. Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (NAV) concept or its equivalent. Exchange traded mutual funds, are classified as Level 1, as the valuation for these instruments is based on the active market in which the fund trades. Common and collective trusts, 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). The trust's shares are offered to a limited group of investors, and are not traded in an active market. The NAV for trusts investing in exchange traded equities is derived from the quoted active market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets. As of December 31, 2015, the plans were able to transact in the common and collective trusts at NAV and classifies these investments as Level 2. 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. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerships; as of December 31, FERC FORM NO. 1 (ED. 12-88) Page 123.27 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 2015, approximately $40 million of these commitments have been funded. Partnerships are classified as Level 2 if the plan is able to transact in the partnership at the NAV, otherwise the partnership is classified as Level 3. 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. The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2015, by asset category, are as follows (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.28 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2015 Other (b) Pension Plan: Assets: Cash and cash equivalents $ 1,893 $ — $ — $ — $ 1,893 Fixed income securities: Corporate U.S. Treasury Other (a) — 1,108,736 — — 1,108,736 274,778 — — — 274,778 — 113,008 — — 113,008 233,021 — — — 233,021 14,680 — — — 14,680 — 130,097 — — 130,097 Equities: U.S. companies International companies Common and collective trusts: U.S. equities International equities — 185,892 — — 185,892 Real estate — 150,359 — — 150,359 Partnerships — 127,840 42,097 — 169,937 116,307 — — — 116,307 — 29,599 — 14,467 44,066 Mutual funds - International equities Short-term investments and other Total Pension Plan $ 640,679 $ 1,845,531 $ 42,097 $ 14,467 $ 2,542,774 $ 240 $ — $ — $ — $ 240 Other Benefits: Assets: Cash and cash equivalents Fixed income securities: Corporate — 217,026 — — 217,026 131,435 — — — 131,435 — 31,106 — — 31,106 253,193 — — — 253,193 12,390 — — — 12,390 U.S. equities — 81,516 — — 81,516 International equities — 28,539 — — 28,539 Real estate — 13,512 — — 13,512 52,568 — — — 52,568 5,065 3,331 — 3,096 11,492 U.S. Treasury Other (a) Equities: U.S. companies International companies Common and collective trusts: Mutual funds - International equities Short-term investments and other Total Other Benefits FERC FORM NO. 1 (ED. 12-88) $ 454,891 $ 375,030 Page 123.29 $ — $ 3,096 $ 833,017 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2014 Other (b) Pension Plan: Assets: Cash and cash equivalents $ 387 $ — $ — $ — $ 387 Fixed Income Securities: Corporate U.S. Treasury Other (a) — 1,162,096 — — 1,162,096 291,817 — — — 291,817 — 113,265 — — 113,265 246,387 — — — 246,387 18,069 — — — 18,069 Equities: U.S. Companies International Companies Common and collective trusts: U.S. Equities — 127,336 — — 127,336 International Equities — 317,167 — — 317,167 Real estate — 129,715 — — 129,715 Partnerships — 138,337 27,929 — 166,266 Short-term investments and other — 26,016 — 16,883 42,899 Total Pension Plan $ 556,660 $ 2,013,932 $ 27,929 $ 16,883 $ 2,615,404 $ 318 $ — $ — $ — $ 318 Other Benefits: Assets: Cash and cash equivalents Fixed Income Securities: Corporate U.S. Treasury Other (a) — 187,961 — — 187,961 130,967 — — — 130,967 — 35,291 — — 35,291 Equities: U.S. Companies 265,106 — — — 265,106 17,813 — — — 17,813 U.S. Equities — 88,258 — — 88,258 International Equities — 85,746 — — 85,746 Real Estate — 11,657 — — 11,657 — 7,408 — 4,100 11,508 International Companies Common and collective trusts: Short-term investments and other Total Other Benefits FERC FORM NO. 1 (ED. 12-88) $ 414,204 $ 416,321 Page 123.30 $ — $ 4,100 $ 834,625 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) (b) This category consists primarily of debt securities issued by municipalities. Represents plan receivables and payables. 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, 2015 and 2014 (dollars in thousands): Pension Partnerships 2015 Beginning balance at January 1 $ Actual return on assets still held at December 31 2014 27,929 $ 8,660 2,789 927 Purchases 13,187 19,984 Sales (1,808) (1,642) Transfers in and/or out of Level 3 — — Ending balance at December 31 $ 42,097 $ 27,929 Contributions Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. Pinnacle West made contributions to the pension plan totaling $100 million in 2015, and $175 million in 2014. The minimum required contributions for the pension plan are zero for the next three years. Pinnacle West expects to make voluntary contributions up to a total of $300 million during the 2016-2018 period. With regard to contributions to the other postretirement benefit plans, Pinnacle West made a contribution of $1 million in 2015, and $1 million in 2014. 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 $100 million in 2015, and $175 million in 2014. APS’s share of the contributions to the other postretirement benefit plan was $1 million in 2015, and $1 million in 2014. 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 2016 $ Other Benefits 152,146 $ 26,468 2017 171,005 28,444 2018 170,534 30,490 2019 180,700 32,438 2020 188,988 33,982 1,023,451 184,335 Years 2021-2025 Electric plant participants contribute to the above amounts in accordance with their respective participation agreements. FERC FORM NO. 1 (ED. 12-88) Page 123.31 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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 2015, 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 2015, and $9 million for 2014. 9. Leases We lease 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 $59 million in 2015, and $60 million in 2014. Estimated future minimum lease payments for APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands): Year APS 2016 $ 31,797 2017 31,317 2018 29,880 2019 28,961 2020 27,680 Thereafter 290,101 Total future lease commitments $ 439,736 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 which are included in the corresponding operating expenses on our comparative statement of income. We are also responsible 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, 2015 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.32 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Percent Owned Plant in Service Accumulated Depreciation Construction Work in Progress Generating facilities: Palo Verde Units 1 and 3 29.1% Palo Verde Unit 2 (a) 16.8% Palo Verde Common 28.0% Palo Verde Sale Leaseback $ 1,744,137 $ 1,067,376 $ 22,228 583,633 356,767 4,142 (b) 643,201 231,609 64,069 (a) 351,050 233,665 — Four Corners Generating Station 63.0% 857,555 577,321 77,317 Navajo Generating Station Units 1, 2 and 3 14.0% 274,640 168,132 4,460 Cholla common facilities (c) 63.3% (b) 158,623 53,777 1,390 ANPP 500kV System 33.4% (b) 109,348 36,576 1,594 Navajo Southern System 22.7% (b) 62,139 19,361 397 Transmission facilities: Palo Verde — Yuma 500kV System 19.3% (b) 14,043 5,226 133 Four Corners Switchyards 49.8% (b) 38,420 9,833 1,687 Phoenix — Mead System 17.1% (b) 39,089 13,173 151 Palo Verde — Estrella 500kV System 50.0% (b) 89,832 18,359 1,008 Morgan — Pinnacle Peak System 64.6% (b) 129,855 11,087 2,592 Round Valley System 50.0% (b) 703 286 — Palo Verde — Morgan System 87.7% (b) 12 — 133,813 Hassayampa - North Gila System 80.0% (b) 164,854 1,159 — Cholla 500 Switchyard 85.7% (b) 547 15 — Saguaro 500 Switchyard 75.0% (b) 773 26 — (a) (b) (c) 11. 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 second breach of contract lawsuit against DOE in the United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's 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 Nuclear Waste Policy Act. On August 18, 2014, APS and FERC FORM NO. 1 (ED. 12-88) Page 123.33 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 the amount of current reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through 2016. APS’s first claim made pursuant to the terms of the August 18, 2014 settlement agreement, which was for the period July 1, 2011 through June 30, 2014, and was for $42.0 million (APS’s share of this amount was $12.2 million), was received on June 1, 2015. APS's $12.2 million share was recorded as an adjustment to a regulatory liability and had no impact on the amount of current reported net income. APS’s second claim made pursuant to the terms of the August 18, 2014 settlement agreement, which was for the period July 1, 2014 through June 30, 2015, was filed for $12.0 million (APS's share of this amount would be $3.6 million), and has been submitted to, but not yet approved by, the DOE in the fourth quarter of 2015. 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 $13.5 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers ("ANI"). The remaining balance of $13.1 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 $16.6 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 $2.8 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 $23.1 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 $61.7 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 FERC FORM NO. 1 (ED. 12-88) Page 123.34 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2016 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $876 million in 2016; $949 million in 2017; $737 million in 2018; $603 million in 2019; $498 million in 2020; and $7.8 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 thousands): Years Ended December 31, Coal take-or-pay commitments (a) (a) $ 2016 2017 2018 2019 2020 Thereafter 170,714 $ 195,428 $ 189,588 $ 193,818 $ 198,160 $ 2,270,974 Total take-or-pay commitments are approximately $3.2 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 thousands): Year Ended December 31, 2015 Total payments $ 211,327 $ 2014 236,773 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 $42 million in 2016; $40 million in 2017; $40 million in 2018; $40 million in 2019; $40 million in 2020; and $432 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. 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 $202 million at December 31, 2015 and $198 million at December 31, 2014. Under our current coal supply agreements, we expect to make payments for the final mine reclamation as follows: $15 million in 2016; $16 million in 2017; $18 million in 2018; FERC FORM NO. 1 (ED. 12-88) Page 123.35 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) $19 million in 2019; $20 million in 2020; and $262 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements. 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. 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. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. We are unable to predict the outcome of these matters; 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 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. 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 Westfiled 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 United States Court of Appeals for the Ninth Circuit, which heard oral argument on February 9, 2016. A written decision on the case is expected 30-60 days after oral argument. We believe the District Court's decision will be upheld on appeal, but cannot predict the outcome at the appellate court. If the District Court's decision is reversed, the case would be remanded for discovery and trial, and there is insufficient information at this time to reasonably estimate any possible loss or range of loss to APS. FERC FORM NO. 1 (ED. 12-88) Page 123.36 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. The case was held in abeyance while APS negotiated a settlement with DOJ and environmental plaintiffs. In March 2015, the parties agreed in principle to settle the case, and on June 24, 2015, DOJ lodged the proposed consent decree with the United States District Court for the District of New Mexico. On August 17, 2015, the consent decree was entered by the district court. The settlement requires installation of pollution control technology and implementation of other measures to reduce sulfur dioxide and nitrogen oxide emissions from the two Four Corners units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule requirements. The settlement also requires the Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.7 million for certain environmental mitigation projects to benefit the Navajo Nation. APS is responsible for 15 percent of these costs based on its ownership interest in the units at the time of the alleged violations, which does not result in a material impact on our financial position, results of operations or cash flows. 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 BART to lessen the impacts of emissions on visibility surrounding the plants. Four Corners. 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 approximately $400 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. When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. APS is negotiating a definitive purchase agreement with NTEC for the purchase of the 7% interest. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest. Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s FIP, could be up to approximately $200 million. In October 2014, a coalition of environmental groups, an Indian tribe FERC FORM NO. 1 (ED. 12-88) Page 123.37 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. Cholla. APS believes that EPA’s final rule as it applies to Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015), 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. 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 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/or 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. APS’s proposal involves state and federal rulemaking processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On October 16, 2015, ADEQ issued the Cholla permit, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. APS is unable to predict when or whether APS's proposal may ultimately be approved by the EPA. Mercury and Air Toxic Standards ("MATS"). 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 $8 million for Cholla (excludes costs related to Cholla Unit 2 which was closed on October 1, 2015). 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, estimates that APS's share of costs for equipment necessary to comply with the rules is approximately $1 million. The United States Supreme Court’s recent decision in Michigan vs. EPA reversed and remanded the MATS proceeding back to the DC Circuit Court. The Circuit Court then remanded the MATS rule back to EPA to address rulemaking deficiencies identified by the Supreme Court. Further EPA action on the MATS rule is pending. This proceeding does not materially impact APS. Regardless of how EPA addresses the deficiencies in the MATS rulemaking, the Arizona State Mercury Rule, the stringency of which is roughly equivalent to that of MATS, would still apply to Cholla. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.38 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for existing, new, modified, and reconstructed EGUs. EPA’s final rules require newly built fossil fuel-fired EGUs, along with those undergoing modification or reconstruction, to meet CO2 performance standards based on a combination of best operating practices and equipment upgrades. EPA established separate performance standards for two types of EGUs: stationary combustion turbines, typically natural gas; and electric utility steam generating units, typically coal. With respect to existing power plants, EPA’s recently finalized “Clean Power Plan” imposes state-specific goals or targets to achieve reductions in CO2 emission rates from existing EGUs measured from a 2012 baseline. In a significant change from the proposed rule, EPA’s final performance standards apply directly to specific units based upon their fuel-type and configuration (i.e., coal- or oil-fired steam plants versus combined cycle natural gas plants). As such, each state’s goal is an emissions performance standard that reflects the fuel mix employed by the EGUs in operation in those states. The final rule provides guidelines to states to help develop their plans for meeting the interim (2022-2029) and final (2030 and beyond) emission performance standards, with three distinct compliance periods within that timeframe. States were originally required to submit their plans to EPA by September 2016, with an optional two-year extension provided to states establishing a need for additional time; however, it is expected that this timing will be impacted by the court-imposed stay described below. ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, is presently working to develop a compliance plan for submittal to EPA. In addition to these on-going state proceedings, EPA has taken public comments on proposed model rules and a proposed federal compliance plan, which included consideration as to how the Clean Power Plan will apply to EGUs on tribal land such as the Navajo Nation. The legality of the Clean Power Plan is being challenged in the U.S. Court of Appeals for the D.C. Circuit; the parties raising this challenge include, among others, the ACC. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. We cannot predict the extent of such delay. With respect to our Arizona generating units, we are currently evaluating the range of compliance options available to ADEQ, including whether Arizona deploys a rate- or mass-based compliance plan. Based on the fuel-mix and location of our Arizona EGUs, and the significant investments we have made in renewable generation FERC FORM NO. 1 (ED. 12-88) Page 123.39 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) and demand-side energy efficiency, if ADEQ selects a rate-based compliance plan, we believe that we will be able to comply with the Clean Power Plan for our Arizona generating units in a manner that will not have material financial or operational impacts to the Company. On the other hand, if ADEQ selects a mass-based approach to compliance with the Clean Power Plan, our annual cost of compliance could be material. These costs could include costs to acquire mass-based compliance allowances. As to our facilities on the Navajo Nation, EPA has yet to determine whether or to what extent EGUs on the Navajo Nation will be required to comply with the Clean Power Plan. EPA has proposed to determine that it is necessary or appropriate to impose a federal plan on the Navajo Nation for compliance with the Clean Power Plan. In response, we filed comments with EPA advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA reaches a determination that is consistent with our preferred approach for the Navajo Nation, we believe the Clean Power Plan will not have material financial or operational impacts on our operations within the Navajo Nation. Alternatively, if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation, and depending on our need for future operations at our EGUs located there, we may be unable to comply with the federal plan unless we acquire mass-based allowances or emission rate credits within established carbon trading markets, or curtail our operations. Subject to the uncertainties set forth below, and assuming that EPA establishes a federal plan for the Navajo Nation that requires carbon allowances or credits to be surrendered for plan compliance, it is possible we will be required to purchase some quantity of credits or allowances, the cost of which could be material. Because ADEQ has not issued its plan for Arizona, and because we do not know whether EPA will decide to impose a plan or, if so, what that plan will require, there are a number of uncertainties associated with our potential cost exposure. These uncertainties include: whether judicial review will result in the Clean Power Plan being vacated in whole or in part or, if not, the extent of any resulting compliance deadline delays; whether any plan will be imposed for EGUs on the Navajo Nation; the future existence and liquidity of allowance or credit compliance trading markets; the applicability of existing contractual obligations with current and former owners of our participant-owned coal-fired EGUs; the type of federal or state compliance plan (either rate- or mass-based); whether or not the trading of allowances or credits will be authorized mechanisms for compliance with any final EPA or ADEQ plan; and how units that have been closed will be treated for allowance or credit allocation purposes. In the event that the incurrence of compliance costs is not economically viable or prudent for our operations in Arizona or on the Navajo Nation, or if we do not have the option of acquiring allowances to account for the emissions from our operations, we may explore other options, including reduced levels of output, as an alternative to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains on-going, and additional information or considerations may arise that change our expectations. Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard, greenhouse gas emissions, and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and 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. FERC FORM NO. 1 (ED. 12-88) Page 123.40 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Notice of Intent to Sue Related to Four Corners On December 21, 2015, several environmental groups filed a notice of intent to sue with OSM and other federal agencies under the Endangered Species Act alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the DOI's review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. We are monitoring this matter and will intervene if a lawsuit is filed. We cannot predict the timing or outcome of this matter. New Mexico Tax Matter On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") 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 NMTRD 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. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed an appeal of the decision on August 31, 2015. The parties are engaged in settlement discussions and we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Financial Assurances In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of December 31, 2015, standby letters of credit totaled $79 million and will expire in 2016. As of December 31, 2015, surety bonds expiring through 2018 totaled $158 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.41 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 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 2015, a revision to the estimated cash flows for the decommissioning study was completed for the Four Corners coal-fired plant, which resulted in an increase to the ARO in the amount of $24 million. Also in 2015, Four Corners spent $32 million in actual decommissioning costs. In addition, APS recognized an ARO for Cholla as a result of new CCR environmental rules that were published in the Federal Register in the second quarter of 2015. See Note 11 for additional information related to the CCR environmental rules. This resulted in an increase to the ARO in the amount of $39 million, an increase in plant in service of $23 million and a reduction of the regulatory liability of $16 million. Finally, in 2015 there was a revision in estimated cash flows for the Cholla decommissioning, which resulted in a decrease of the ARO in the amount of $3 million. 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. The following table shows the change in our asset retirement obligations for 2015 and 2014 (dollars in thousands): 2015 Asset retirement obligations at the beginning of year $ 390,750 2014 $ 346,729 Changes attributable to: Accretion expense Settlements 25,163 23,567 (32,048) (29,497) Estimated cash flow revisions 17,556 43,899 Newly incurred obligation 42,155 6,052 Asset retirement obligations at the end of year FERC FORM NO. 1 (ED. 12-88) $ Page 123.42 443,576 $ 390,750 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) As mentioned above, decommissioning activities for Four Corners Units 1-3 began in January 2014. Decommissioning activities for Cholla ash ponds began in January 2015. Thus, $29 million of the total ARO of $444 million at December 31, 2015, is classified as a current liability on the balance sheet. At December 31, 2014, $32 million of the total ARO of $391 million was classified as a current liability on the balance sheet. 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: 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, exchange traded mutual funds, 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 certain investments that are valued and redeemable 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 FERC FORM NO. 1 (ED. 12-88) Page 123.43 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 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 FERC FORM NO. 1 (ED. 12-88) Page 123.44 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. We classify these investments as Level 2. The commingled 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 1 represent investments held in a short-term investment exchange-traded mutual fund, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper. Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are typically 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. FERC FORM NO. 1 (ED. 12-88) Page 123.45 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Fair Value Tables The following table presents the fair value at December 31, 2015 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Balance at December 31, 2015 Other Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 22,992 $ 30,364 $ 12 $ 53,368 Nuclear decommissioning trust: U.S. commingled equity funds — 314,957 — — 314,957 12,260 — — (335) 11,925 117,245 — — — 117,245 Corporate debt — 96,243 — — 96,243 Mortgage-backed securities — 99,065 — — 99,065 Municipal bonds — 72,206 — — 72,206 Other — 23,555 — — 23,555 Fixed income securities: Cash and cash equivalent funds U.S. Treasury Subtotal nuclear decommissioning trust Total 129,505 606,026 $ 129,505 $ $ — $ 629,018 — $ (335) 30,364 $ (63,343) $ (323) 735,196 $ 788,564 Liabilities Risk management activities — derivative instruments: Commodity contracts (144,044) $ (12) $ (a) Primarily consists of heat rate options and other long-dated electricity contracts. FERC FORM NO. 1 (ED. 12-88) Page 123.46 (207,399) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (a) (Level 3) Balance at December 31, 2014 Other Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 20,769 $ 32,598 $ 6 $ 53,373 Nuclear decommissioning trust: U.S. commingled equity funds — 309,620 — — 309,620 118,843 — — — 118,843 Cash and cash equivalent funds — 11,453 — Corporate debt — 109,379 — — 109,379 Mortgage-backed securities — 88,465 — — 88,465 Fixed income securities: U.S. Treasury (7,245) 4,208 Municipal bonds — 69,139 — — 69,139 Other — 14,212 — — 14,212 118,843 602,268 — Subtotal nuclear decommissioning trust Total $ 118,843 $ 623,037 $ $ — $ (95,061) $ (7,245) 713,866 767,239 32,598 $ (7,239) $ (73,984) $ (7) $ Liabilities Risk management activities — derivative instruments: Commodity contracts (a) (169,052) 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 123.47 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The significant unobservable inputs at December 31, 2015 for these instruments include electricity prices, and volatilities. The significant unobservable inputs at December 31, 2014 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, 2015 and December 31, 2014: December 31, 2015 Fair Value (millions) Commodity Contracts Assets Liabilities $ 24,543 $ 54,679 — 5,628 Valuation Technique Significant Unobservable Input Range WeightedAverage Discounted cash flows Electricity forward price (per MWh) $15.92 - $40.73 $ 26.86 Option model Electricity forward price (per MWh) $23.87 - $44.13 $ 33.91 Electricity: Forward Contracts (a) Option Contracts (b) Electricity price volatilities 40% - 59% 52% Natural gas price volatilities 32% - 40% 35% Natural gas forward price (per MMBtu) $2.18 - $3.14 Natural Gas: Forward Contracts (a) Total (a) (b) 5,821 3,036 $30,364 $ 63,343 Discounted cash flows $ 2.61 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 123.48 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) December 31, 2014 Fair Value (millions) Commodity Contracts Assets Liabilities Valuation Technique Significant Unobservable Input Range WeightedAverage Discounted cash flows Electricity forward price (per MWh) $19.51 - $56.72 $ 35.27 Option model Electricity forward price (per MWh) $32.14 - $66.09 $ 45.83 Natural gas forward price (per MMBtu) $3.18 - $3.29 $ 3.25 Electricity: Forward Contracts (a) $ 29,471 $ 55,894 — 15,035 Option Contracts (b) Electricity price volatilities 23% - 63% 41% Natural gas price volatilities 23% - 41% 31% Natural gas forward price (per MMBtu) $2.98 - $4.13 Natural Gas: Forward Contracts (a) Total (a) (b) 3,127 3,055 $ 32,598 $ 73,984 Discounted cash flows $ 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. 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, 2015 and 2014 (dollars in thousands): Year Ended December 31, Commodity Contracts 2015 Net derivative balance at beginning of period $ 2014 (41,386) $ (49,165) Total net gains (losses) realized/unrealized: Included in earnings Included in OCI Deferred as a regulatory asset or liability — 102 (452) (239) (4,009) (482) Settlements 14,809 12,080 Transfers into Level 3 from Level 2 (6,256) (2,090) Transfers from Level 3 into Level 2 4,315 (1,592) 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 123.49 (32,979) — $ $ (41,386) — 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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 has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan authorizes up to 4.6 million common shares to be available for grant. As of December 31, 2015, 2.8 million common shares were available for issuance under the 2012 Plan. During 2015, 2014, and 2013, the Company has granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. The Company has not granted stock options since 2004 and has no stock options outstanding. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan. Stock-Based Compensation Expense and Activity Compensation cost included in net income for stock-based compensation plans was $19 million in 2015, and $33 million in 2014. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $7 million in 2015, and $13 million in 2014. As of December 31, 2015, there were approximately $14 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. These costs are expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $21 million in 2015, and $20 million in 2014. The following table is a summary of awards granted and the weighted-average fair value for the three years ended 2015, and 2014. FERC FORM NO. 1 (ED. 12-88) Page 123.50 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b) Units granted Weighted-average grant date fair value (a) (b) $ 2015 2014 2015 2014 152,651 179,291 151,430 166,244 64.12 $ 54.89 $ 64.97 $ 54.86 Units granted includes awards that will be cash settled of 45,104 in 2015, and 49,018 in 2014. Reflects the target payout level. The following table is a summary of the status of non-vested awards as of December 31, 2015 and changes during the year. Restricted Stock Units, Stock Grants, and Stock Units WeightedAverage Grant Date Fair Value Shares Nonvested at January 1, 2015 Granted Forfeited 51.27 324,230 $ 54.92 152,651 64.12 151,430 64.97 — — 40,496 54.98 (198,424) 49.20 (202,480) 54.98 (6,873) 56.78 (7,844) 57.89 Nonvested at December 31, 2015 428,287 Vested Awards Outstanding at December 31, 2015 106,712 (a) (b) Shares (b) WeightedAverage Grant Date Fair Value 480,933 (a) $ Change in performance factor Vested Performance Shares 56.69 305,832 59.78 202,480 Includes 127,634 of awards that will be cash settled and 353,299 of awards that will be settled in shares. Nonvested performance 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. Share-based liabilities paid relating to restricted stock unit awards was $10 million, and $9 million in 2015, and 2014, respectively. This includes cash used to settle restricted stock units of $3 million, and $3 million in 2015, and 2014, respectively. Share-based liabilities paid relating to performance share awards was $16 million, and $12 million in 2015, and 2014, respectively. Restricted Stock Units, Stock Grants, and Stock Units Restricted stock units have been granted to officers and key employees. Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date. Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee's retirement. Awardees elect to receive payment in either 100% stock, or 50% in cash and 50% FERC FORM NO. 1 (ED. 12-88) Page 123.51 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award to accrue dividend rights, 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. If the award is forfeited the employee is not entitled to the dividends on those shares. In December 2012, a retention award of 50,617 restricted stock units was granted to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West. This 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 can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met. Restricted stock unit 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. Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant. The members of the Board of Directors who elect to defer may elect to receive payment in either 100% stock, or 50% in cash and 50% in stock. The 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. Performance Share Awards Performance share awards have been granted to officers and key employees. 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 performance 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. If the award is forfeited or if the performance criteria are not achieved the employee is not entitled to the dividends on those shares. 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. Management 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. 15. Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of FERC FORM NO. 1 (ED. 12-88) Page 123.52 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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 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. FERC FORM NO. 1 (ED. 12-88) Page 123.53 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) As of December 31, 2015, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 2,487 GWh Gas 182 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, 2015, and 2014 (dollars in thousands): Financial Statement Location Commodity Contracts Loss recognized in OCI on derivative OCI — derivative instruments instruments (effective portion) Loss reclassified from accumulated OCI into income (effective portion realized) (a) Fuel and purchased power (b) (a) (b) Year Ended December 31, 2015 2014 $ (615) $ (5,988) (372) (21,415) During the years ended December 31, 2015, and 2014, we had no 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 $4 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, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings. The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2015 and 2014 (dollars in thousands): Year Ended December 31, Commodity Contracts Net gain recognized in income Operating revenues Net loss recognized in income Fuel and purchased power (a) Total $ 574 (108,973) 2014 $ 324 (66,367) $(108,399) $ (66,043) (a) Amounts are before the effect of PSA deferrals. FERC FORM NO. 1 (ED. 12-88) 2015 Financial Statement Location Page 123.54 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 offset and 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, 2015 and December 31, 2014, include gross liabilities of $3 million and $4 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 potential impacts of offsetting relating to transactions executed under master netting arrangements. While certain amounts may be eligible for offsetting, under master netting arrangements, for FERC reporting purposes we do not offset on the balance sheet. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Comparative Balance Sheets. As of December 31, 2015: (dollars in thousands) Gross Recognized Derivatives (a) Current Assets Investments and Other Assets Total Assets $ Current Liabilities Deferred Credits and Other Total Liabilities Total (113,560) (93,827) (207,387) $ (154,031) (a) (b) 37,396 15,960 53,356 Eligible for Offsetting Derivatives Cash Collateral (b) $ (22,163) (3,854) (26,017) $ 22,163 3,854 26,017 — $ $ — — — 18,060 — 18,060 18,060 Net Derivatives After Impacts of Offsetting $ $ 15,233 12,106 27,339 (73,337) (89,973) (163,310) (135,971) All of our gross recognized derivative instruments were subject to master netting arrangements. We had total cash collateral and margin provided to counterparties of $18,060; this amount is reflected in miscellaneous current and deferred credits. We had total cash collateral received from counterparties of $4,379 and cash margin provided to counterparties of $672; this amount is reflected in miscellaneous current and accrued liabilities. Certain cash collateral is not eligible for offsetting as it does not relate to recognized derivatives. FERC FORM NO. 1 (ED. 12-88) Page 123.55 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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 Eligible for Offsetting Derivatives Cash Collateral (b) $ (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 $43,900; this amount is reflected in miscellaneous current and deferred credits. We had total cash collateral received from counterparties of $7,443 and cash margin provided to counterparties of $350; this amount is reflected in miscellaneous current and accrued liabilities. Certain cash collateral is not eligible for offsetting as it does not relate to recognized derivatives. Credit Risk and Credit Related Contingent Features 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 87% of APS’s $28 million of risk management assets as of December 31, 2015. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.56 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) contingent features at December 31, 2015 (dollars in thousands): December 31, 2015 Aggregate fair value of derivative instruments in a liability position Cash collateral posted 207,387 18,060 Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) (a) $ 112,301 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 $161 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 trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. The original lease was scheduled to end on December 31, 2015; however, the lease agreements include fixed rate renewal options which APS exercised on July 7, 2014. As a result, APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases 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 could be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease extension period, APS may be required to pay the noncontrolling equity participants approximately $288 million beginning in 2016, and up to $465 million over the lease extension term. 17. Nuclear Decommissioning Trusts FERC FORM NO. 1 (ED. 12-88) Page 123.57 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2015 and December 31, 2014 (dollars in thousands): Total Unrealized Gains Fair Value Total Unrealized Losses December 31, 2015 Equity securities $ Fixed income securities 314,957 $ 420,574 Net payables (a) 157,098 11,955 $ 735,196 $ 169,053 — $ Total Unrealized Gains Fair Value (115) (2,645) — (335) Total $ (2,760) Total Unrealized Losses December 31, 2014 Equity securities $ Fixed income securities $ 411,491 Net payables (a) 159,274 $ 713,866 $ 17,260 $ 176,534 (15) (1,073) — (7,245) Total (a) 309,620 — $ (1,088) 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 thousands): Year Ended December 31, 2015 Realized gains $ Realized losses (6,225) Proceeds from the sale of securities (a) FERC FORM NO. 1 (ED. 12-88) 5,189 $ 478,813 Page 123.58 2014 4,725 (4,525) 356,195 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) Proceeds are reinvested in the trust. The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2015 is as follows (dollars in thousands): Fair Value Less than one year $ 14,001 1 year – 5 years 117,356 5 years – 10 years 114,769 Greater than 10 years 174,448 Total 18. $ 420,574 Changes in Accumulated Other Comprehensive Loss The following table shows the changes in APS's accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2015 and 2014 (dollars in thousands): Year Ended December 31, 2015 $ Balance at beginning of period 2014 (48,333) $ (53,372) Derivative Instruments OCI (loss) before reclassifications (957) (809) Amounts reclassified from accumulated other comprehensive loss (a) 4,187 13,483 Net current period OCI (loss) 3,230 12,674 14,726 (10,415) 3,280 2,780 18,006 (7,635) Pension and Other Postretirement Benefits OCI (loss) before reclassifications Amounts reclassified from accumulated other comprehensive loss (b) Net current period OCI (loss) $ Balance at end of period (a) (b) (27,097) $ (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. FERC FORM NO. 1 (ED. 12-88) Page 123.59 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) ( 2 Preceding Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 30,313,461) 2,780,792 3 Preceding Quarter/Year to Date Changes in Fair Value ( 10,414,982) 4 Total (lines 2 and 3) ( 7,634,190) 5 Balance of Account 219 at End of Preceding Quarter/Year ( 37,947,651) 6 Balance of Account 219 at Beginning of Current Year ( 37,947,651) 7 Current Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 3,279,529 8 Current Quarter/Year to Date Changes in Fair Value 14,726,301 9 Total (lines 7 and 8) 18,005,830 10 Balance of Account 219 at End of Current Quarter/Year FERC FORM NO. 1 (NEW 06-02) ( Page 122a 19,941,821) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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 ( Totals for each category of items recorded in Account 219 (h) 23,058,959) 2 ( 53,372,420) ( 11,224,156) 13,483,153 3 ( 4 809,174) 12,673,979 5,039,789 ( 10,384,980) ( 48,332,631) 6 ( 10,384,980) ( 48,332,631) 8 4,187,494 7,467,023 ( 957,776) 13,768,525 ( 7,155,262) 9 10 FERC FORM NO. 1 (NEW 06-02) 3,229,718 Page 122b Total Comprehensive Income (i) (j) 421,220,870 426,260,659 450,274,046 471,509,594 16,263,945 5 7 Net Income (Carried Forward from Page 117, Line 78) 21,235,548 ( 27,097,083) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION 20160317-8000 FERC PDF (Unofficial) (1) 03/17/2016 X An Original Arizona Public Service Company Year/Period of Report 2015/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 16,119,467,895 16,119,467,895 193,312,890 193,312,890 460,983,004 460,983,004 16,773,763,789 16,773,763,789 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) 51,471,935 51,471,935 713,287,335 713,287,335 255,525,921 255,525,921 17,794,048,980 17,794,048,980 6,402,411,202 6,402,411,202 11,391,637,778 11,391,637,778 5,678,404,960 5,678,404,960 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) 712,679,738 712,679,738 6,391,084,698 6,391,084,698 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 11,326,504 11,326,504 6,402,411,202 6,402,411,202 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 15,977,379 36,095,177 3 Nuclear Materials 66,073,042 39,673,667 4 Allowance for Funds Used during Construction 5 (Other Overhead Construction Costs, provide details in footnote) 6 SUBTOTAL (Total 2 thru 5) 9,170,405 6,100,955 -155,306 1,801,051 91,065,520 7 Nuclear Fuel Materials and Assemblies 8 In Stock (120.2) 75,276,604 9 In Reactor (120.3) 268,754,495 10 SUBTOTAL (Total 8 & 9) 268,754,495 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) 143,553,701 14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 216,266,314 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 75,178,760 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) Amortization (d) Balance End of Year (f) Changes during Year Other Reductions (Explain in a footnote) (e) Line No. 1 34,454,952 17,617,604 2 31,856,733 73,889,976 3 7,083,060 8,188,300 4 1,784,015 -138,270 5 99,557,610 6 7 75,275,759 845 74,567,662 269,365,593 8 9 269,366,438 10 11 12 -77,241,505 74,567,662 146,227,544 13 222,696,504 14 15 16 17 18 19 20 21 22 FERC FORM NO. 1 (ED. 12-89) Page 203 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) 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 form 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 03/17/2016 2015/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) 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 3,493,100 23,889 4 (303) Miscellaneous Intangible Plant 648,478,838 39,775,729 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 651,971,938 39,799,618 6 2. PRODUCTION PLANT 7 A. Steam Production Plant 8 (310) Land and Land Rights 5,793,509 9 (311) Structures and Improvements 159,820,125 14,768,454 10 (312) Boiler Plant Equipment 1,176,686,374 -13,414,111 11 (313) Engines and Engine-Driven Generators 12 (314) Turbogenerator Units 211,794,966 895,990 13 (315) Accessory Electric Equipment 123,412,173 5,143,357 14 (316) Misc. Power Plant Equipment 94,239,796 1,960,089 15 (317) Asset Retirement Costs for Steam Production 4,877,201 37,810,094 16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 1,776,624,144 47,163,873 17 B. Nuclear Production Plant 18 (320) Land and Land Rights 4,417,789 19 (321) Structures and Improvements 789,134,431 30,893,093 20 (322) Reactor Plant Equipment 1,257,374,596 -14,095,883 21 (323) Turbogenerator Units 382,538,957 22,638,882 22 (324) Accessory Electric Equipment 282,962,874 7,499,150 23 (325) Misc. Power Plant Equipment 166,807,494 30,730,377 24 (326) Asset Retirement Costs for Nuclear Production -53,660,218 25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 2,829,575,923 77,665,619 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 15,722,863 43,806 38 (341) Structures and Improvements 107,546,244 7,945,779 39 (342) Fuel Holders, Products, and Accessories 54,831,437 817,542 40 (343) Prime Movers 667,231,770 2,928,422 41 (344) Generators 1,229,504,103 180,869,002 42 (345) Accessory Electric Equipment 190,761,332 19,763,086 43 (346) Misc. Power Plant Equipment 25,353,749 3,259,414 44 (347) Asset Retirement Costs for Other Production 6,052,254 2,803,813 45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 2,297,003,752 218,430,864 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 6,903,203,819 343,260,356 FERC FORM NO. 1 (REV. 12-05) Page 204 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Account Balance Beginning of Year (a) (b) 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) Year/Period of Report 2015/Q4 End of 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 (c) 153,274,790 91,126,916 978,521,546 105,328,472 459,350,543 358,514,688 20,946,613 34,517,731 959,119 24,191,083 68,379,251 46,093,765 21,489,714 95,909,657 370,485 88,633 2,201,581,299 257,481,707 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 4,422,088 2,506,907 32,581,012 73,537,459 1,466,691 5,336,396,181 243,884,657 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 25,345,405 747,795,375 206 Additions 28,661,792 35,110,452 18,667,497 69,029,324 27,184,306 14,847,014 8,489,415 918,159 20,644,837 45,822,474 3,814,969 29,297 2,589,474 438,030 32,989,614 -7,984,149 98,344,546 747,795,375 15,840,948,612 98,344,546 982,770,884 15,840,948,612 982,770,884 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) 1,303,909 1,303,909 1,062,387 1,062,387 5,793,509 169,959,505 1,156,581,622 4,629,074 6,690,641 396,443 1,408,431 1,142,254 212,294,513 127,147,099 95,057,631 42,687,295 1,809,521,174 14,266,843 4,417,789 816,786,489 1,239,997,477 400,230,928 289,890,908 194,436,793 -53,660,218 2,892,100,166 3,241,035 3,281,236 4,946,911 571,116 3,101,078 15,141,376 231,262 427,691 17,497,704 115,114,718 1,127,095 205,628 -1,062,387 134,604,098 164,012,317 -1,062,387 -1,062,387 FERC FORM NO. 1 (REV. 12-05) 3,516,989 688,013,045 691,530,034 Page 205 15,766,669 115,260,761 55,221,288 652,662,488 1,295,258,387 209,397,323 27,345,148 8,856,067 2,379,768,131 7,081,389,471 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 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Adjustments Transfers Balance at End of Year (e) (f) (g) Retirements (d) 1,764,699 97,251 6,319,306 1,478 1,655,361 340,460 152,469,210 115,220,748 1,040,581,491 151,420,759 479,184,896 454,083,885 21,317,098 34,606,364 10,178,555 2,448,884,451 1,148,643 105,002 4,620,455 4,881,033 2,329,727 1,792,910 9,727,135 5,946,179 675,204 7,854,895 161,881 62,532,920 82,466,661 494,771,283 2,123,630 593,108,591 355,117,541 685,513,670 1,646,381,071 833,455,083 375,644,742 291,363,329 43,555,103 402,364 74,601,786 39,645,428 5,540,635,410 44,688 5,980,472 2,884,897 4,930,166 23,879 1,550,861 968,369 11,715,300 29,201 28,127,833 114,182 -554 14,600,073 216,121,974 228,209,122 40,843,126 242,515 37,140,670 810,563 10,151,197 252,446,057 17,446,237 818,011,534 28,127,833 243,268,042 -554 -554 818,011,534 16,580,450,900 243,268,042 -554 16,580,450,900 FERC FORM NO. 1 (REV. 12-05) -554 -114,182 64,167 -64,167 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: 20160317-8000 FERC PDF (Unofficial) (1) 03/17/2016 X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/Q4 ELECTRIC PLANT LEASED TO OTHERS (Account 104) Line No. Name of Lessee (Designate associated companies with a double asterisk) (a) 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) Page 213 Commission Authorization (c) Expiration Date of Lease (d) Balance at End of Year (e) Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) 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 12/31/2025 592,651 10/31/2006 12/31/2025 401,192 12/31/2014 12/31/2025 320,827 12/31/2008 3/31/2016 14,677,520 12/31/2008 12/31/2016 18,696,646 12/31/2008 6/01/2016 4,020,354 5/31/2008 12/31/2017 653,352 12/31/1999 12/31/2025 281,561 12/31/1999 12/31/2025 92,023 12/31/1999 12/31/2025 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 12/31/2025 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) 51,471,935 Page 214 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) 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 6/01/2016 4,825,172 10/31/2008 12/31/2020 1,929,113 5/01/2009 12/31/2025 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 6/01/2016 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) 51,471,935 Page 214.1 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) 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) 90,439,655 (a) 1 Palo Verde Nuclear Plant Improvements 2 Cholla Plant Improvements 7,960,080 3 Four Corners Plant Improvements 79,006,717 4 Navajo Plant Improvements 4,460,358 5 Gas & Oil Plant Improvements 100,532,030 6 Solar Additions 9,723,027 7 8 Transmission Land and Land Rights 5,839,397 9 Transmission Substations - Add/Improvements 16,992,140 10 Overhead Transmission Lines - Add/Improvements 42,747,198 11 Underground Transmission Lines - Add/Improvements 11,493,433 12 Other Transmission 686,526 13 ANPP 500 KV Transmission System 1,594,148 14 Navajo Southern Transmission System 396,602 15 PV/YUMA 500 KV Transmission System 133,034 16 Morgan - Pinnacle Peak Transmission System 2,591,729 17 Palo Verde - Morgan 500kV Transmission System 133,813,037 18 Phoenix - Mead Transmission System 150,908 19 20 Distribution Land and Land Rights 327,572 21 Distribution Substation - Add/Improvements 9,420,141 22 Overhead Distribution Lines - Add/Improvements 25,876,619 23 Underground Distribution Lines - Add/Improvements 19,746,477 24 Other Distribution 7,587,737 25 26 General Computer/Communications 113,594,914 27 Buildings & Equip/Land & Land Rights 28,173,856 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 TOTAL FERC FORM NO. 1 (ED. 12-87) 713,287,335 Page 216 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 5,520,859,057 5,520,859,057 385,402,361 385,402,361 70,077 70,077 1,852,644 1,852,644 506,214 506,214 387,831,296 387,831,296 232,771,289 232,771,289 13 Cost of Removal 33,160,314 33,160,314 14 Salvage (Credit) 68,094,492 68,094,492 15 TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14) 197,837,111 197,837,111 16 Other Debit or Cr. Items (Describe, details in footnote): -32,448,282 -32,448,282 5,678,404,960 5,678,404,960 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 1,126,134,742 1,126,134,742 21 Nuclear Production 1,532,908,333 1,532,908,333 24 Other Production 567,646,629 567,646,629 25 Transmission 722,951,477 722,951,477 1,526,576,630 1,526,576,630 202,187,149 202,187,149 5,678,404,960 5,678,404,960 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) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 FOOTNOTE DATA Schedule Page: 219 Line No.: 12 Column: b FERC Page 219 Column (b), Line 12 232,771,289 Cholla Unit 2 - NBV of Retirement moved to Regulatory Asset (182.3) Gain/(Loss) on Disposition of Assets 491,054 (493,858) FERC Page 204-207 Column (d), Line 5 1,303,909 FERC Page 204-207 Column (d), Line 48 1,764,699 FERC Page 204-207 Column (d), Line 60 1,148,643 General Plant Retirements 6,256,596 Other 25,710 FERC Page 204-207 Column (d), Line 104 Schedule Page: 219 Line No.: 16 243,268,042 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/Liability Saguaro Steam Regulatory Asset Amortization Reserve Transfers-- Accounts 1110,1112, & 1220 & Other Entities FERC FORM NO. 1 (ED. 12-87) Page 450.1 (15,663,590) (3,880,699) (332,041) 441,067 (2,791,073) (7,417,361) (2,936,533) 131,948 (32,448,282) 2015/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/Q4 INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/Q4 INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued) 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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) 32,263,222 38,345,560 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 114,840,074 120,438,920 8 Transmission Plant (Estimated) 7 Production Plant (Estimated) 30,450,516 34,331,669 9 Distribution Plant (Estimated) 73,808,775 77,675,882 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) 455,476 490,631 219,554,841 232,937,102 -666,160 1,296,535 251,151,903 272,579,197 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) (1) 03/17/2016 X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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) 2016 Current Year No. (b) Amt. (c) No. (d) 209,943.00 Amt. (e) 48,487.00 7,366.00 202,577.00 48,487.00 533.00 533.00 533.00 533.00 533.00 Page 228a 62 62 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Allowances (Accounts 158.1 and 158.2) Year/Period of Report End of 2015/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. 2017 No. (f) 48,487.00 2018 Amt. (g) No. (h) 48,487.00 Amt. (i) Future Years No. Amt. (k) (j) 1,260,662.00 Totals No. (l) 1,616,066.00 48,487.00 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 48,487.00 7,366.00 48,487.00 48,487.00 1,309,149.00 1,657,187.00 533.00 533.00 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 17 17 1,066.00 79 79 36 37 38 39 40 41 42 43 44 45 46 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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 $7,351,348 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) (1) 03/17/2016 X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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) 2016 Current Year No. (b) Amt. (c) Page 228b No. (d) Amt. (e) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Allowances (Accounts 158.1 and 158.2) Year/Period of Report End of 2015/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. 2017 No. (f) Future Years 2018 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of EXTRAORDINARY PROPERTY LOSSES (Account 182.1) 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) 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 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2) Line No. 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 WRITTEN OFF DURING YEAR Balance at Account Charged Amount End of Year (d) (e) (f) Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) (1)03/17/2016 An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/Q4 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 FACIL STDY,WA131362 ( 23 FACIL STDY,WA144239 ( 2) 143 143 45) 143 143 24 FACIL STDY,WA183634 730 143 25 SMG FESSTD,WA310886 431 143 ( 1,000) 143 193 143 ( 50,000) 143 26 SMG SISSTD,WA310005 143 27 SYSIMPTSTD,W502466 ( 3) 143 143 28 SYSIMPTSTD,WA158156 ( 10) 143 143 29 SYSIMPTSTD,WA173723 ( 702) 143 143 30 SYSIMPTSTD,WA201230 938 143 143 31 SYSIMPTSTD,WA205085 109 143 143 32 SYSIMPTSTD,WA223536 362 143 143 3,475) 143 143 2,114 143 143 33 SYSIMPTSTD,WA305310 ( 34 SYSIMPTSTD,WA307280 35 SYSIMPTSTD,WA307466 ( 203) 143 36 SYSIMPTSTD,WA309370 37 SYSIMPTSTD,WA309377 ( 143 781 143 ( 160,000) 143 164) 143 ( 250,000) 143 38 SYSIMPTSTD,WA85636 ( 1) 143 143 39 SYSIMPTSTD,WA92332 ( 10) 143 143 40 SYSIMPTSTD,WA95638 ( 13) 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of OTHER REGULATORY ASSETS (Account 182.3) 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) 34,162,184 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) 34,750,848 588,664 2 Amortize through 2036 3 4 Capital Contribution on Phoenix-Mead Transmission 108 11,704,442 332,042 11,372,400 4,748,533 139,206,635 5 U-1345-90-269 Amortize through 2050 6 7 Income Taxes - AFUDC Equity 20,745,899 283, 410.1 123,209,269 8 E-01345A-03-0437 Amortize through 2045 9 10 Palo Verde Rent Levelization 762,791 525 762,791 60,331 407 55,045 5,286 5,499,900 190 1,979,901 3,519,999 6,925,515 various 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 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 21 Amortize through 2015 22 23 Deferred Fuel and Purchased Power Mark-to-Market 97,442,048 141,548,130 44,106,082 24 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 25 Amortize through 2018 26 27 Navajo Coal Reclamation 6,920,553 501 417,890 6,502,663 13,629,492 571 9,086,328 4,543,164 25,883,494 619,222,919 28 E-01345A-08-0172 Amortize through 2026 29 30 Transmission Vegetation Management 31 ER11-3468-000 Amortize through 2016 32 33 Pension Benefits 160,069,622 421, 908 485,036,791 34 E-01345A-08-0172 35 36 Pension and Other Postretirement Benefits Deferral 4,237,507 926 3,049,996 283, 410.1 64,132 2,985,864 15,284,238 283, 410.1 1,600,431 13,683,807 112,541,373 1,334,174,106 4,237,507 37 E-01345A-08-0172 38 Amortize through 2015 39 40 Income Taxes - Change in Rates 41 Amortize through 2045 42 43 Income Taxes - Medicare Subsidy 44 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 1,147,084,875 Page 299,630,604 232 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of OTHER REGULATORY ASSETS (Account 182.3) 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 Amortize through 2024 2 3 Income Taxes - Investment Tax Credit Basis Adjustmt 4,062,799 283 47,916,218 1,750,604 50,228,413 4 Amortize through 2045 5 6 Property Tax Deferral 30,282,583 20,169,839 37,612,494 45,987,954 142 50,452,422 7 E-01345A-11-0224 8 9 Lost Fixed Cost Recovery 38,093,998 45,506,450 10 Amortize through 2016 11 E-01345A-11-0224 12 13 FERC Transmission Cost Adjustor 2,942,299 2,942,299 14 Amortize through 2017 15 E-01345A-11-0224 16 17 Retired Power Plant Costs 146,095,252 1,251,069 403 9,914,441 137,431,880 293,623) 407 6,688,721 70,270,927 112,541,373 1,334,174,106 18 Amortize through 2033 19 20 Four Corners Cost Deferral 77,253,271 ( 21 Amortize through 2024 22 E-01345A-11-0224 23 24 25 26 27 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) 1,147,084,875 Page 299,630,604 232.1 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 232 Line No.: 19 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) 03/17/2016 2015/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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) 154,166 131 77,085 Amount (e) 231,251 Balance at End of Year (f) 89,280,343 8,064,846 931 3,443,429 93,901,760 200,000 143,750 232 143,750 200,000 Information Sys Leases & Maint. 7,941,626 88,635,308 165 89,317,968 7,258,966 Unamortized Arrangement Fees 3,691,195 2,884,228 3,662,428 Redhawk Effluent Water Prepaid Training (03/2011 to 03/2016) 2,855,461 431, 525 48,250 232 48,250 High Lonesome Wind Ranch Tax Cr 1,083,722 142 1,083,722 Transmission Debits (11/2014 to 03/2016) 9,350,838 2,630,788 565 4,439,035 Prepaid Payroll Agreements Prepaid Water Supply Agreements Through 2050 294,601 7,542,591 294,601 7,689,648 165 7,268,424 Debt Shelf Registration 290,349 Freight in Transit 837,424 1,057,611 232 1,810,802 84,233 Prepaid Monitoring Services (2014 to 2023) 757,985 165 44,388 713,597 -8 5,672,931 165 5,672,923 Long Term Prepaid Insurance 115,899 various 421,224 Rapid Response Center Equipment Minor Items 406,248 790,494 232 296,955 396,052 various 790,494 285,676 407,331 47 Misc. Work in Progress Deferred Regulatory Comm. 48 Expenses (See pages 350 - 351) 49 TOTAL FERC FORM NO. 1 (ED. 12-94) 121,840,013 122,124,425 Page 233 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 233 Line No.: 26 Column: d 181, 428, 431 FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 66,251,274 80,616,150 3 Pension and Other Post Retirement Liabilities 2 Risk Management Activities 194,541,344 181,786,916 4 Regulated Liabilities - Asset Retirement Obligation 115,824,489 107,885,455 5 Regulated Liabilities - Other 248,332,195 245,681,167 6 Other 226,548,062 236,971,165 851,497,364 852,940,853 851,497,364 852,940,853 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: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of CAPITAL STOCKS (Account 201 and 204) 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of CAPITAL STOCKS (Account 201 and 204) (Continued) 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of OTHER PAID-IN CAPITAL (Accounts 208-211, inc.) 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of CAPITAL STOCK EXPENSE (Account 214) 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. Series 1998 16,870,000 538,817 5 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 12,850,000 544,829 6 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series B 26,710,000 653,379 7 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 38,150,000 749,617 8 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series C 32,000,000 282,336 9 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series D 32,000,000 411,777 10 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series E 32,000,000 391,683 11 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series A 35,975,000 576,013 12 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series B 32,000,000 758,122 13 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series C 32,000,000 445,268 405,705,000 7,729,490 200,000,000 2,049,339 14 Subtotal 15 16 Other Long Term Debt Account 224 17 5.625% Unsecured Senior Note 18 2,288,000 D 19 4.650% Unsecured Senior Note 300,000,000 2,529,839 250,000,000 2,362,692 250,000,000 1,659,703 20 2,208,000 D 21 5.500% Unsecured Senior Note 22 2,147,500 D 23 6.250% Unsecured Senior Note 24 1,355,000 D 25 6.875% Unsecured Senior Note 150,000,000 1,333,769 500,000,000 4,301,413 300,000,000 3,096,550 26 226,500 D 27 8.750% Unsecured Senior Note 28 275,000 D 29 5.05% Unsecured Senior Note 30 2,022,000 D 31 4.50% Unsecured Senior Note 325,000,000 32 3,074,500 D 33 TOTAL FERC FORM NO. 1 (ED. 12-96) 3,321,373 4,159,400,075 Page 256 52,724,392 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) 1 4.50% Unsecured Senior Note Principal Amount Of Debt issued (b) 100,000,000 2 Total expense, Premium or Discount (c) 1,148,640 -5,182,000 P 3 4.7% Unsecured Senior Note 250,000,000 4 2,501,050 1,000,000 D 5 3.35% Unsecured Senior Note 250,000,000 2,080,950 250,000,000 2,103,800 300,000,000 2,384,360 6 230,000 D 7 2.20% Unsecured Senior Note 8 35,000 9 3.15% Unsecured Senior Note 10 1,578,000 11 4.35% Unsecured Senior Note 250,000,000 12 2,518,924 335,000 13 14 APS Term Loan 50,000,000 10,000 15 16 COLI LOANS (Option II Benefits) 28,695,075 17 18 Subtotal 3,753,695,075 44,994,902 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 TOTAL FERC FORM NO. 1 (ED. 12-96) 4,159,400,075 Page 256.1 52,724,392 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) 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 11/16/98 11/01/33 11/16/98 11/01/33 16,870,000 166,729 4 5/28/09 6/01/34 5/28/09 6/01/34 12,850,000 39,014 5 9/22/09 4/01/38 9/22/09 4/01/38 26,710,000 263,169 6 5/28/09 6/01/34 5/28/09 6/01/34 149,739 7 5/28/09 6/01/34 5/28/09 6/01/34 232,669 8 5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 1,840,000 9 5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 1,840,000 10 6/26/09 5/01/29 6/26/09 5/01/29 35,975,000 120,632 11 6/26/09 5/01/29 6/26/09 5/01/29 87,980 12 6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 560,000 13 303,555,000 10,711,982 14 15 16 5/07/03 5/15/33 5/07/03 5/15/33 200,000,000 11,250,000 17 18 5/07/03 5/15/15 5/07/03 5/15/15 8/22/05 9/01/35 8/22/05 9/01/35 8/03/06 8/01/16 8/03/06 8/01/16 5,231,250 19 250,000,000 13,750,000 21 250,000,000 15,625,000 23 20 22 24 8/03/06 8/01/36 8/03/06 8/01/36 150,000,000 10,312,500 25 2/26/09 3/01/19 2/26/09 3/01/19 500,000,000 43,750,000 27 8/25/11 9/01/41 8/25/11 9/01/41 300,000,000 15,150,000 29 26 28 30 1/13/12 4/01/42 1/13/12 4/01/42 325,000,000 14,625,000 31 32 3,757,250,075 FERC FORM NO. 1 (ED. 12-96) Page 257 178,395,658 33 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) 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) 1/13/12 Date of Maturity (e) 4/01/42 AMORTIZATION PERIOD Date From (f) 1/13/12 Date To (g) 4/01/42 Outstanding (Total amount outstanding without reduction for amounts held by respondent) (h) 100,000,000 Line Interest for Year No. Amount (i) 4,500,000 1 2 1/10/14 1/15/44 1/10/14 1/15/44 250,000,000 11,750,000 3 4 6/18/14 6/15/24 6/18/14 6/15/24 250,000,000 8,375,000 5 6 1/12/15 1/15/20 1/12/15 1/15/20 250,000,000 5,500,000 5/19/15 5/15/25 5/19/15 5/15/25 300,000,000 5,880,000 7 8 9 10 11/06/15 11/15/45 11/06/15 11/15/45 250,000,000 1,776,250 11 12 13 6/26/15 6/26/18 6/26/15 6/26/18 50,000,000 208,676 14 15 28,695,075 16 17 3,453,695,075 167,683,676 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 3,757,250,075 FERC FORM NO. 1 (ED. 12-96) Page 257.1 178,395,658 33 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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.: 16 Column: h The change in the loan balance for the Coli Loan is as follows: Total outstanding balance @ 12/31/14 2015 death repayments 2015 net premiums 2015 net interest Balance outstanding @ 12/31/15 Schedule Page: 256.1 Line No.: 18 $ 27,577,791 (539,091) 521,842 1,134,533 $ 28,695,075 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 follow: 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) $ 179,563,539 (1,060,365) (97,515) (10,000) $ 178,395,659 Page 450.1 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) 450,274,046 2 3 4 Taxable Income Not Reported on Books 5 Contributions in Aid of Construction 43,468,266 6 Tax Gain/Loss on Sale of Business Property -29,603,211 7 Other Taxable Income Not Reported on Books 12,412,514 8 9 Deductions Recorded on Books Not Deducted for Return 10 Book Depreciation and Amortization 552,712,170 11 Income Tax Per Books 246,022,753 12 Pension and Other Post-Retirement Benefits -516,615 13 Other Deductions Recorded on Books Not Deducted for Return 226,907,566 14 Income Recorded on Books Not Included in Return 15 Book Gain/Loss on Sale of Business Property 1,503,253 16 Mark-to-Market Adjustments -380,716 17 Cash Surrender Value -1,134,553 18 Other Income Recorded on Books Not Included in Return -1,493,647 19 Deductions on Return Not Charged Against Book Income 20 Tax Depreciation and Amortization -820,958,164 21 Expenditures Capitalized for Book Not Tax -260,341,446 22 Other Deductions on Return Not Charged Against Book Income -312,163,353 23 24 25 26 27 Federal Tax Net Income 106,708,863 28 Show Computation of Tax: 29 ($106,708,863) * 35% 37,348,102 30 31 Tax Attributes Utilized -18,648,856 32 33 Net Current Year Federal Tax Expense 18,699,246 34 35 Other (includes 2014 Return-to-Provision) -3,388,363 36 37 Net Federal Tax Expense per Income Statement 15,310,883 38 39 40 41 42 43 44 FERC FORM NO. 1 (ED. 12-96) Page 261 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 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 $ $ 198,115,157 18,320,277 10,472,132 226,907,566 Column: b Other Deductions on Return Not Charged Against Book Income consists of the following: Book Accrued Expenses - Beginning of Year $ (172,957,792) Pension and Other Post Retirement Benefits (74,442,645) Regulatory Accounting Adjustments (34,203,283) Contributions to Qualified Decomissioning Fund (17,248,943) State Taxes (5,086,351) Other (8,224,339) Total $ (312,163,353) FERC FORM NO. 1 (ED. 12-87) Page 450.1 2015/Q4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR 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) 13,485,795 2 FICA 3 Unemployment Taxes Charged During Year (d) 15,310,883 Taxes Paid During Year (e) 7,841,954 50,166,332 50,166,332 295,018 295,018 73,727 86,762 4 Heavy Vehicle Use -37,340 5 Fuel Tax -24,415 6 Subtotal 13,424,040 65,845,960 58,391,825 7,803,549 16,448,738 15,875,295 21,791 477,477 180,622 Adjustments (f) 1,759 7 8 New Mexico: State and Local 9 Real and Personal Property 10 Income 11 Unemployment 12 Sales 13 Use 3,288 53,494 53,494 146,668 164,409 -95 11,179 11,370 7,828,533 17,137,556 16,285,190 87,638,164 178,162,090 176,766,037 444,418 6,794,954 6,200,000 16,767,805 264,154,556 263,920,314 965,091 17,201,515 16,653,984 5,977,153 1,435,134 766,302 1,479,763 1,479,763 111,792,631 469,228,012 465,786,400 30,202 117,105 147,306 30,202 117,105 147,306 31 Real and Personal Property 13,940 28,269 42,210 32 Income 69,601 540,970 608,083 83,541 569,239 650,293 142,296,215 552,897,872 541,261,014 14 Subtotal 15 16 Arizona: State and Local 17 Real and Personal Property 18 Income 19 Diesel Fuel 20 State and City Sales 21 State and City Use 22 State and City Tax Reserve 23 Unemployment 24 Subtotal -190,000 -190,000 25 26 NV Real and Personal 27 Unemployment 28 Subtotal 29 30 California: State and Local 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 78,223 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR 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 9,137,268 268,223 9 Subtotal 9,137,268 268,223 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) 142,296,215 552,897,872 Page 262.1 541,261,014 78,223 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) 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) 20,954,724 DISTRIBUTION OF TAXES CHARGED Extraordinary Items Electric (Account 408.1, 409.1) (Account 409.3) (i) (j) 21,013,707 26,229,310 -50,375 Adjustments to Ret. Earnings (Account 439) (k) Other (l) -5,702,824 1 23,937,022 2 295,018 3 73,727 -26,174 20,878,175 Line No. 4 5 47,243,017 18,602,943 6 7 8 8,376,992 16,448,738 318,646 511,574 9 -34,097 -14,453 -286 8,680,899 16,960,312 10 53,494 11 146,668 12 11,179 13 177,244 14 15 16 89,034,216 155,002,981 23,159,110 17 1,039,372 7,734,403 -939,449 18 264,154,556 20 19 17,002,047 17,201,515 21 6,455,985 1,512,753 -97,776 1,342,909 22 1,479,763 23 115,044,373 162,639,608 306,398,404 24 25 117,105 26 117,105 28 27 29 30 28,269 31 2,488 552,850 -11,880 32 2,488 581,119 -11,880 34 33 35 36 37 38 39 40 154,011,438 FERC FORM NO. 1 (ED. 12-96) 227,541,161 Page 325,434,934 263 41 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) 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 9,405,503 268,223 8 9,405,503 268,223 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 40 154,011,438 FERC FORM NO. 1 (ED. 12-96) 227,541,161 Page 325,434,934 263.1 41 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) (2) A Resubmission 03/17/2016 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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% 265,395 255 6 30% 178,341,815 255 15,090,394 420 81,816 420 6,535,366 7 8 TOTAL 178,607,210 15,090,394 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 6,617,182 Date of Report Year/Period of Report (Mo, Da, Yr) 2015/Q4 End of Arizona Public Service Company (2) A Resubmission 03/17/2016 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued) Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Balance at End of Year (h) 183,579 186,896,843 Average Period of Allocation to Income (i) ADJUSTMENT EXPLANATION Line No. 1 2 3 4 5 6 7 8 9 2.2 years 27.3 years 187,080,422 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 266 Line No.: 8 Column: b $33,587 is associated with transmission investments. Schedule Page: 266 Line No.: 8 Column: h $23,099 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) 03/17/2016 2015/Q4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 5,906,506 Contra Account (c) 182.3 4,747,577 242, 411.6 4,747,577 232 1,470,235 (b) Amount (d) 1,148,634 Credits Balance at End of Year (e) (f) 49,083 4,806,955 5,475,749 194,313,384 2 3 Palo Verde Unit II Rent 4 Levelization (1/2000 to 12/2015 5 6 Coal Reclamation 190,307,870 7 8 Navajo Retiree Health Care Costs 7,984,308 182.3, 501 313,811 7,670,497 6,631,850 131 1,006,524 354,253 5,979,579 4,534,314 143 22,403,053 23,141,284 5,272,545 179,547 701,638 1,195,391 2,378,107 9 10 Legal Reserves 11 12 Construction Advances 13 14 Land Lease Obligations 15 522,091 165, 555 Through 2048 16 17 Transmission Termination Agreemnts 6,000,000 242 1,182,716 930.2 6,000,000 18 19 License Fees 20 21 Leasehold Improvements 85,444 131 205,124 171,011 51,331 50,875 131 42,223 37,338 45,990 19,960,113 232, 567 290,640 26,641,345 232 1,922,000 501 22 23 Escheated Funds 24 25 SCE Right of Way 19,669,473 26 27 Tolling Agreements 26,194,533 19,472,788 19,919,600 28 29 Coal Severance Surtax Reserve 1,922,000 30 31 Carbon Allowance 509, 242 493,655 5,683,502 5,189,847 268,548 268,548 50,000 750,000 700,000 64,366,009 56,778,494 268,889,494 32 33 OCC Modernization Overland Retentn 34 107 Through 2018 35 36 House Warranty Program 37 456 Through 2020 38 39 40 41 42 43 44 45 46 47 TOTAL FERC FORM NO. 1 (ED. 12-94) 276,477,009 Page 269 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282) 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 2,844,422,368 601,832,113 438,382,734 2,844,422,368 601,832,113 438,382,734 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 33,567,715 -8,643,667 2,877,990,083 593,188,446 438,382,734 2,404,272,915 566,006,339 277,694,051 473,717,168 27,182,107 160,688,683 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (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) Amount (h) Credits Account Debited (i) Amount (j) Balance at End of Year Line No. (k) 1 3,007,871,747 2 3 4 3,007,871,747 5 6 7 24,924,048 8 3,032,795,795 9 10 2,692,585,203 11 340,210,592 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283) 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 48,285,714 10,356,261 4,532,356 4 Reg Assets - Mark to Market 38,187,540 18,346,292 1,514,074 5 Reg Assets - Pension and Other 191,746,602 54,628,463 5,683,116 6 Reg Assets - Other 160,071,551 95,322,271 82,808,594 7 Mark to Market 20,916,759 8,952,993 5,895,753 8 Other 63,978,469 17,632,203 15,204,098 523,186,635 205,238,483 115,637,991 523,186,635 205,238,483 115,637,991 437,070,114 177,797,974 84,435,911 86,116,521 27,440,509 31,202,080 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued) 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 3,229,718 3,229,718 54,109,619 3 55,019,758 4 240,691,949 5 172,585,228 6 20,744,281 7 66,406,574 8 609,557,409 9 10 11 12 13 14 15 16 17 18 609,557,409 19 2,908,159 527,524,018 21 321,559 82,033,391 3,229,718 20 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 X An Original (1) Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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 (b) DEBITS Account Credited (c) Amount Credits (d) (e) Balance at End of Current Quarter/Year (f) 10,000,000 456 2,000,000 8,000,000 295,546,022 230 17,991,469 277,554,553 69,990,113 518 842,083 1,340,275 70,488,305 96,231,975 190 3,573,590 8,120,830 100,779,215 1,609,200 13,678,200 1,872,696 76,552,911 2 U-1345-90-269 Amortize through 2019 3 4 Asset Retirement Obligation 5 FERC Order #552 Amortize through 2057 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 2045 14 15 Sundance Maintenance 12,069,000 16 E-01345A-05-0816,-0826,-0827 17 Amortize through 2030 18 19 Income Tax - Change in Rates 75,844,021 283 1,163,806 20 Amortize through 2045 21 22 Amonix Promissory Note 6,161,929 6,161,929 23 24 Renewable Energy Standard 45,975,945 549 126,253,481 127,615,209 47,337,673 25 E-01345A-03-0437,E-01345A-05-0816,-0826, 26 -0827 Amortize through 2017 27 28 Star Center Patent Rights 1,125,393 1,125,393 29 E-01345A-09-0357 30 31 AZ Sun Program 1,296,595 400 496,465 800,130 5,499,900 190 1,979,900 3,520,000 31,334,718 908 56,912,075 50,770,665 25,193,308 253,649,996 234,007,460 879,524,513 32 E-01345A-09-0338 Amortize through 2016 33 34 Excess Deferred Taxes 35 Amortize through 2019 36 37 Demand Side Management 38 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 39 Amortize through 2017 40 41 TOTAL FERC FORM NO. 1/3-Q (REV 02-04) 899,167,049 Page 278 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 X An Original (1) Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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 Other Postretirement Benefits Balance at Begining of Current Quarter/Year (b) Balance at End of Current Quarter/Year DEBITS Account Credited (c) 230,915,494 Amount Credits (d) (e) (f) 228.3 33,008,940 15,713,896 213,620,450 400 4,119,219 3,495,000 1,642,430 439,873 13,542,657 14,996,475 9,687,507 551,028 312,978 864,006 1,200,127 7,719,624 8,919,751 55,356 739 56,095 234,007,460 879,524,513 2 E-01345A-08-0172 3 4 FERC Transmission True Up 2,266,649 5 Amortize through 2016 6 7 Removal costs Cholla 13,102,784 8 Amortize through 2033 9 10 Power Supply Adjuster various 5,308,968 11 Amortize through 2016 12 E-01345A-05-0816,-0826,-0827 13 14 Power Supply Adjuster Interest 15 Amortize through 2016 16 E-01345A-05-0816,-0826,-0827 17 18 Four Corners Coal Reclamation 19 E-013454A-05-0816, -0826, -0827 20 Amortize through 2031 21 22 Minor Items 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) 899,167,049 Page 278.1 253,649,996 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 278.1 Line No.: 10 Column: c 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) 03/17/2016 2015/Q4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 1,701,967,569 1,639,833,740 1,375,003,302 1,349,585,933 186,410,252 187,964,502 22,444,231 21,012,878 187,560 182,742 3,286,012,914 3,198,579,795 176,840,127 258,829,659 3,462,853,041 3,457,409,454 3,462,853,041 3,457,409,454 16 (450) Forfeited Discounts 8,400,013 8,113,649 17 (451) Miscellaneous Service Revenues 9,290,021 9,321,356 -1,185,197 10,564,649 5,519,062 5,882,123 34,768,234 30,931,241 56,792,133 64,813,018 3,519,645,174 3,522,222,472 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 14 TOTAL Revenues Net of Prov. for Refunds 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of ELECTRIC OPERATING REVENUES (Account 400) 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 13,159,754 12,837,752 1,046,989 1,033,728 2 3 12,364,153 12,337,218 125,579 124,460 4 2,275,533 2,269,263 3,744 3,728 5 148,229 137,571 1,028 1,007 6 2,822 2,729 154 156 7 8 9 27,950,491 27,584,533 1,177,494 1,163,079 10 5,678,363 5,366,855 47 55 11 33,628,854 32,951,388 1,177,541 1,163,134 12 13 33,628,854 Line 12, column (b) includes $ Line 12, column (d) includes FERC FORM NO. 1/3-Q (REV. 12-05) 32,951,388 -4,300,886 1,648 of unbilled revenues. MWH relating to unbilled revenues Page 301 1,177,541 1,163,134 14 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 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 $ $ 2,596,707 2,000,000 985,646 946,676 682,764 650,822 269,874 218,840 124,722 50,084 (9,426) (1,446,105) (1,551,542) 5,519,062 Column: c PCS Project PacifiCorp CT Deferred Gain Amortization Facility Charges Fuel Loading Management/Administration Fees Participant Station Power Revenue FERC FORM NO. 1 (ED. 12-87) 9,186,485 134,871 9,321,356 Column: b PCS Project PacifiCorp CT Deferred Gain Amortization Fuel Loading Facility Charges Effluent Water Rights Fee Management/Administration Fees Other Call Center Referrals Participant Station Power Revenue Home Warranty Program Redhawk Miscellaneous Revenue Risk Management Surepay and Autopay Discount Total Schedule Page: 300 9,287,522 $2,499 9,290,021 $ 2,629,500 2,000,000 710,904 976,120 727,288 136,363 Page 450.1 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Surepay and Autopay Discount Risk Management Renewable Energy Misc Revenue Effluent Water Rights Fee Other Total FERC FORM NO. 1 (ED. 12-87) $ (1,509,350) (802,409) 50,000 646,001 317,706 5,882,123 Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of SALES OF ELECTRICITY BY RATE SCHEDULES 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 3,679,589 519,663,383 466,329 7,891 0.1412 3 ET-1 2,129,322 272,689,926 133,692 15,927 0.1281 4 ET-2 4,299,349 555,257,808 293,586 14,644 0.1291 5 ECT-2 2,130,107 246,471,622 92,478 23,034 0.1157 6 ECT-1R 667,386 77,430,213 26,272 25,403 0.1160 7 ECT-SP 22,584 2,871,559 1,559 14,486 0.1272 8 E-12 EPR-2,6 33,613 5,548,405 12,018 2,797 0.1651 9 ET-1 EPR-2,6 40,462 4,789,604 5,584 7,246 0.1184 10 ET-2 EPR-2,6 114,735 13,736,332 14,019 8,184 0.1197 12,285 1,751,250 883 13,913 0.1426 12 ECT-1R EPR-2,6 5,856 824,707 351 16,684 0.1408 13 ET-EV 5,287 609,890 218 24,252 0.1154 14 E-47 1,702 540,066 11 ECT-2 EPR-2,6 15 Green Power 16 Total Residential 0.3173 144,757 13,142,277 1,702,329,522 1,046,989 12,552 0.1295 19 E-20 38,617 20 E-30 4,972 4,939,546 393 98,262 0.1279 1,281,885 4,348 1,144 21 E-32 XS 0.2578 1,444,763 235,430,207 97,331 14,844 0.1630 22 E-32 S 2,500,461 333,409,187 16,128 155,039 0.1333 23 E-32 M 2,842,734 306,934,665 3,636 781,830 0.1080 24 E-32 L 2,287,045 208,334,549 618 3,700,720 0.0911 5,605 857,946 239 23,452 0.1531 26 E-32 TOU S 29,184 3,654,592 124 235,355 0.1252 27 E-32 TOU M 68,203 7,083,445 69 988,449 0.1039 28 E-32 TOU L 175,275 15,507,244 39 4,494,231 0.0885 17 18 442 Commercial 25 E-32 TOU XS 29 SCHOOL TOU RATE M 40,800 5,095,290 59 691,525 0.1249 30 SCHOOL TOU RATE L 27,051 3,139,659 20 1,352,550 0.1161 31 E-34 413,609 33,443,264 16 25,850,563 0.0809 32 E-35 831,971 57,936,625 19 43,787,947 0.0696 6,615 723,094 9 735,000 0.1093 34 E-47 20,552 8,396,353 35 E-56 1,056 749,249 1 1,056,000 36 E-221 323,537 33,315,122 1,357 238,421 0.1030 37 EPR-2 7,442 764,258 24 310,083 0.1027 38 EPR-6 369,588 45,313,330 954 387,409 0.1226 33 E-36 M 39 Green Power 40 E-56R 41 42 43 TOTAL Billed Total Unbilled Rev.(See Instr. 6) TOTAL FERC FORM NO. 1 (ED. 12-95) 0.4085 0.7095 637,987 307,007 24,562,721 45 6,822,378 0.0800 27,948,843 1,648 27,950,491 3,290,313,800 -4,300,886 3,286,012,914 1,172,568 4,926 1,177,494 23,836 335 23,737 0.1177 -2.6098 0.1176 Page 304 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of SALES OF ELECTRICITY BY RATE SCHEDULES 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 M & L 451,707 34,800,506 143 3,158,790 0.0770 2 AG-1 M & L TOU 3 AG-1 XL 4 AG-1 XL TOU 5 Total Commercial 11,958 724,277 1 11,958,000 121,391 8,066,118 4 30,347,750 0.0606 0.0664 41,350 2,720,799 2 20,675,000 0.0658 12,372,493 1,377,821,918 125,579 98,524 0.1114 6 7 442 Industrial and Irrigation 8 E-30 58 17,486 72 806 0.3015 43,615 7,736,718 2,654 16,434 0.1774 10 E-32 S 75,484 10,956,507 440 171,555 0.1452 11 E-32 M 189,644 23,108,491 297 638,532 0.1219 12 E-32 L 427,586 39,181,624 102 4,192,020 0.0916 249 34,230 8 31,125 0.1375 1,295 145,811 3 431,667 0.1126 9 E-32 XS 13 E-32 TOU XS 14 E-32 TOU S 15 E-32 TOU M 2,420 333,330 4 605,000 0.1377 16 E-32 TOU L 45,278 4,601,325 11 4,116,182 0.1016 17 E-34 156,022 11,831,910 6 26,003,667 0.0758 18 E-35 723,288 50,411,801 14 51,663,429 0.0697 19 E-36 M 2,051 213,055 1 2,051,000 0.1039 20 E-36 XL 78,745 5,703,259 5 15,749,000 0.0724 714 176,844 22 E-221 9,997 1,054,511 95 105,232 0.1055 23 EPR-6 23,619 2,784,845 23 1,026,913 0.1179 1,020 121,712 2 510,000 0.1193 413,900 21,527,240 2 206,950,000 0.0520 88,052 7,590,089 5 17,610,400 0.0862 2,283,037 187,530,788 3,744 609,786 0.0821 29 444 Public Street Lighting 148,213 2,244,017 1,028 144,176 0.0151 30 Total Public Street Lighting 148,213 2,244,017 1,028 144,176 0.0151 32 445 Other Public Authorities 2,822 187,560 154 18,325 0.0665 33 Total Other Public Authorities 2,822 187,560 154 18,325 0.0665 21 E-47 24 AG-1 M & L 25 AG-1 XL TOU 26 Special Contracts 27 Total Industrial & Irrigation 0.2477 28 31 34 35 Unbilled MWh & Revenue 36 Residential Unbilled 17,477 -361,953 -0.0207 37 Commercial Unbilled -8,340 -2,818,613 0.3380 38 Ind & Irrig. Unbilled -7,505 -1,120,534 0.1493 16 214 0.0134 27,948,843 1,648 27,950,491 3,290,313,800 -4,300,886 3,286,012,914 39 Public Str Lighting Unbilled 40 Other Public Auth Unbilled 41 42 43 TOTAL Billed Total Unbilled Rev.(See Instr. 6) TOTAL FERC FORM NO. 1 (ED. 12-95) Page 304.1 1,172,568 4,926 1,177,494 23,836 335 23,737 0.1177 -2.6098 0.1176 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of SALES OF ELECTRICITY BY RATE SCHEDULES 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 Total Unbilled Mwh & Revenue 1,648 -4,300,886 -2.6098 2 3 449.1 Provision for Rate Refunds 4 Residential PRR 5 Commercial PRR 6 Industrial & Irrigation PRR 7 Public Street Lighting PRR 8 Sales For Resale - Traditional 9 Other Public Authorities PRR 10 Total Provision for Rate Refunds 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) 27,948,843 1,648 27,950,491 3,290,313,800 -4,300,886 3,286,012,914 Page 304.2 1,172,568 4,926 1,177,494 23,836 335 23,737 0.1177 -2.6098 0.1176 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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) 0.343 0.343 0.342 (a) 1 Aguila Irrigation District Statistical Classification (b) RQ 2 Buckeye Irrigation District RQ 86306 0.214 0.214 0.214 3 City of Williams RQ MRT Vol 1 5.603 5.566 4.671 4 Electrical District No. 6 RQ 86307 0.000 0.000 0.000 5 Electrical District No. 7 RQ 86304 0.230 0.230 0.230 6 Electrical District No. 8 RQ 86310 3.971 3.971 3.971 7 Harquahala Valley Irrigation District RQ 86309 1.447 1.447 1.447 8 Maricopa County Municipal Water Conser RQ 86058 0.058 0.058 0.058 9 McMullen Valley Irrigiation District RQ 86311 1.582 1.582 1.582 10 Roosevelt Irrigation District RQ 86305 0.133 0.133 0.132 11 Tohono O'Odham Utility Authority RQ 87975 8.571 8.571 6.974 12 Tonopah Irrigation District RQ 86312 0.067 0.067 0.067 13 Town of Wickenburg RQ 85726 0.001 0.001 0.001 14 Valley Electric Association IF WSPP 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 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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) LF 2 Arizona Electric Power Cooperative SF WSPP 3 BP Energy Company 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 Citigroup Energy Inc. SF MRT Vol 3 8 ConocoPhillips Company SF WSPP 9 Constellation NewEnergy, Inc. SF WSPP 10 Direct Energy Business, LLC SF WSPP 11 EDF Trading North America LLC SF WSPP 12 El Paso Electric Company SF WSPP 13 Exelon Generation Company, LLC SF WSPP 14 Freeport-McMoRan Copper & Gold Energy 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 Guzman Power Markets, LLC Statistical Classification (b) SF 2 IBERDROLA Renewables, Inc. SF MRT Vol 3 3 Idaho Power Company SF WSPP 4 Imperial Irrigation District SF WSPP 5 J. Aron & Company SF WSPP 6 Los Angeles Dept of Water and Power SF WSPP 7 Macquarie Energy LLC SF MRT Vol 3 8 Morgan Stanley Capital Group, Inc. SF MRT Vol 3 9 Nevada Power Company SF WSPP 10 NextEra Energy Power Marketing, LLC SF WSPP 11 Noble Americas Energy Solutions LLC SF WSPP 12 PacifiCorp SF MRT Vol 3 13 Powerex Corp. SF WSPP 14 Public Service Co of New Mexico 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 310.2 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 Rainbow Energy Marketing Corporation Statistical Classification (b) SF 2 Salt River Project SF 3 Sempra Generation SF WSPP 4 Shell Energy North America (US), L.P. SF MRT Vol 3 5 Southern California Edison Company SF WSPP 6 Talen Energy Marketing, LLC SF WSPP 7 Tenaska Power Services Company SF WSPP 8 TransAlta Energy Marketing, US, Inc. SF WSPP 9 TransCanada Energy Sales, LTD SF WSPP 10 Tri-State Generation and Transmission SF WSPP 11 Tucson Electric Power Co. SF WSPP 12 Twin Eagle Resource Management, LLC SF WSPP 13 UNS Electric, Inc. SF WSPP 14 WAPA, Colorado River Storage Project 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) WSPP Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.3 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 WAPA, Desert Southwest Region Statistical Classification (b) SF 2 California Independent System Operator OS 3 Direct Energy Business, LLC OS WSPP 4 PacifiCorp Supplemental Coal OS RS # 182 5 PacifiCorp Supplemental Other OS RS # 182 6 Southwest Reserve Sharing Group OS SRSG1 7 Transmission Losses AD 8 Change in Estimate AD 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 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 310.4 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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) 2,999 Demand Charges ($) (h) 41,642 REVENUE Energy Charges ($) (i) 101,865 Other Charges ($) (j) 346,838 Line No. Total ($) (h+i+j) (k) 490,345 1 2 1,875 26,026 63,942 245,642 335,610 36,794 951,912 772,682 39,600 1,764,194 3 30,361 30,361 4 2,014 27,971 67,851 392,575 488,397 5 33,991 471,189 1,155,691 1,806,896 3,433,776 6 12,583 175,886 430,887 688,336 1,295,109 7 8 499 7,018 16,809 404,150 427,977 13,970 196,119 476,859 688,285 1,361,263 9 1,165 39,238 404,975 460,315 10 2,596,322 491,710 3,088,032 11 19,373 165,783 193,247 12 406 154,901 155,479 13 1,050 14 16,102 43,851 575 8,091 12 172 15 1,050 150,328 1,922,128 5,741,925 5,860,052 13,524,105 5,528,035 0 158,144,038 5,171,984 163,316,022 5,678,363 1,922,128 163,885,963 11,032,036 176,840,127 FERC FORM NO. 1 (ED. 12-90) Page 311 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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 21,206,328 21,206,328 1 115,378 2,660,772 2,660,772 2 232,742 6,488,734 6,488,734 3 6,650 154,870 154,870 4 1,647,211 46,101,195 46,101,195 5 186,440 5,292,099 5,292,099 6 35,027 762,335 762,335 7 2,000 54,200 54,200 8 12 324 324 9 8 202 202 10 28,118 948,318 948,318 11 5,400 178,185 178,185 12 170,858 4,479,551 4,479,551 13 622 20,072 20,072 14 150,328 1,922,128 5,741,925 5,860,052 13,524,105 5,528,035 0 158,144,038 5,171,984 163,316,022 5,678,363 1,922,128 163,885,963 11,032,036 176,840,127 FERC FORM NO. 1 (ED. 12-90) Page 311.1 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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) 6,313 209,484 209,484 1 45,200 1,403,316 1,403,316 2 33,846 1,045,016 1,045,016 3 65,764 1,854,518 1,854,518 4 188,400 4,668,088 4,668,088 5 1,408 43,646 43,646 6 42,203 1,103,427 1,103,427 7 483,865 11,959,537 11,959,537 8 14,780 418,690 418,690 9 4,810 112,690 112,690 10 174 4,338 4,338 11 274,397 6,381,655 6,381,655 12 63,110 1,466,077 1,466,077 13 45,713 1,322,081 1,322,081 14 150,328 1,922,128 5,741,925 5,860,052 13,524,105 5,528,035 0 158,144,038 5,171,984 163,316,022 5,678,363 1,922,128 163,885,963 11,032,036 176,840,127 FERC FORM NO. 1 (ED. 12-90) Page 311.2 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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 15,400 15,400 1 111,410 2,678,409 2,678,409 2 142,708 3,209,377 3,209,377 3 47,040 1,335,249 1,335,249 4 109,275 2,564,800 2,564,800 5 6,227 189,510 189,510 6 332,778 8,004,057 8,004,057 7 172,159 4,411,255 4,411,255 8 5,600 143,100 143,100 9 800 18,800 18,800 10 340,603 9,050,773 9,050,773 11 42,041 1,358,450 1,358,450 12 21,609 528,600 528,600 13 60,888 2,351,110 2,351,110 14 150,328 1,922,128 5,741,925 5,860,052 13,524,105 5,528,035 0 158,144,038 5,171,984 163,316,022 5,678,363 1,922,128 163,885,963 11,032,036 176,840,127 FERC FORM NO. 1 (ED. 12-90) Page 311.3 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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) 8,112 295,442 295,442 1 2 7 -20,470 -20,470 3 60 60 3 24,450 399,572 399,572 4 56,380 1,269,746 5,036 1,269,746 5 115,680 115,680 6 5,257,618 5,257,618 7 -201,314 -201,314 8 9 10 11 12 13 14 150,328 1,922,128 5,741,925 5,860,052 13,524,105 5,528,035 0 158,144,038 5,171,984 163,316,022 5,678,363 1,922,128 163,885,963 11,032,036 176,840,127 FERC FORM NO. 1 (ED. 12-90) Page 311.4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 FOOTNOTE DATA Schedule Page: 310.4 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.: 6 Column: c 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: 310.4 Rates are set per the Southwest Reserve Sharing Group participation agreement. Schedule Page: 310.4 Line No.: 7 Column: b Adjustment for transmission losses. Schedule Page: 310.4 Line No.: 8 Column: a 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: 310.4 Line No.: 8 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. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) 14,158,948 273,234,222 28,399,409 13,091,699 313,774,272 28,447,926 5,688,711 16,305,917 1,263,460 7,439,715 346,490,382 5,401,512 13,164,889 1,344,400 3,880,172 379,104,870 8,094,353 5,483,435 40,944,344 8,863,236 15,559,791 78,945,159 425,435,541 7,972,993 3,799,286 51,427,942 14,168,312 15,575,593 92,944,126 472,048,996 25,826,204 78,581,781 13,082,524 11,964,589 25,890,446 83,733,824 12,317,679 9,759,065 8,420,379 39,909,231 45,199,895 222,984,603 8,606,521 33,647,188 45,367,801 219,322,524 6,008,938 2,171,342 14,171,173 16,342,376 3,397,129 42,090,958 265,075,561 8,092,140 2,377,507 12,504,993 15,826,106 3,671,813 42,472,559 261,795,083 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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) 3,181,199 333,179,096 7,661,080 54,658,422 565,997 399,245,794 4,672,333 361,678,254 7,841,540 55,181,306 598,483 429,971,916 310,174 1,601,118 27,779,648 4,351,060 34,042,000 433,287,794 357,661 800,851 27,426,301 4,971,094 33,555,907 463,527,823 410,042,292 -4,144,485 4,794,609 410,692,416 1,534,491,312 422,679,819 -2,913,482 3,080,675 422,847,012 1,620,218,914 3,012,840 3,156,313 2,536,052 2,505,276 870,424 2,261,264 995,559 120,381 54,860 2,820,686 1,591,414 2,452,456 60,874 25,848,955 9,499,928 7,550,709 62,181,678 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 59,770,462 577,318 867,467 569,389 709,655 164,338 164,443 4,925,411 14,524,379 24,693 70,007 21,153,613 83,335,291 5,115,203 12,980,510 308,883 19,364 19,867,447 79,637,909 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) 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) 4,803,283 2,200,293 1,576,261 2,630,964 1,797,421 2,337 5,616,656 680,181 32,083,855 629,407 52,020,658 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 2,739,119 252,338 3,383,396 20,411,819 9,902,185 2,724,211 539,741 3,198,813 1,202,145 2,085,061 18,584,504 9,234,082 2,422,117 727,857 3,495,143 43,447,952 95,468,610 3,236,446 40,691,025 92,228,606 1,922,661 2,173,367 44,012,091 4,073,429 273,867 52,455,415 2,263,316 3,086,747 42,902,342 3,942,074 349,460 52,543,939 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) 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) 308,352 54,040,463 277,941 383,462 55,010,218 573,659 59,068,309 279,125 239,041 60,160,134 6,569,688 5,707,899 4,726,228 11,295,916 4,266,430 9,974,329 92,038,668 9,150,693 22,860,000 37,023,948 5,201,486 7,566,536 52,261,312 96,813,137 10,138,062 22,370,000 25,038,368 5,438,796 8,907,704 75,334,711 16,926,157 17,228,362 3,572,429 -51,254,320 6,443,887 156,070,796 8,390,441 -51,466,697 7,062,721 180,515,605 11,677,723 167,748,519 1,999,805,281 11,601,954 192,117,559 2,106,881,390 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 Dynegy Arlington - Tolling Agreement RQ 257,035 N/A N/A 2 Gila River Power - Tolling Agreement RQ 173,748 N/A N/A 3 Salt River Project RQ 11,071 N/A N/A 4 Citigroup Energy Inc. LF N/A N/A N/A 5 Morgan Stanley Capital Group, Inc. 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 Morgan Stanley Capital Group, Inc. IF N/A N/A N/A 13 AG-1 Contracts SF N/A N/A N/A 14 Arizona Electric Power Cooperative SF N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 BP Energy Company 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 Guzman Power Markets, LLC SF N/A N/A N/A 11 IBERDROLA Renewables, Inc SF N/A N/A N/A 12 Idaho Power Company SF N/A N/A N/A 13 Imperial Irrigation District SF N/A N/A N/A 14 J. Aron & Company SF N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.1 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 Los Angeles Dept of Water & Power SF N/A N/A N/A 2 Macquarie Energy LLC SF N/A N/A N/A 3 Morgan Stanley Capital Group, Inc. SF N/A N/A N/A 4 Nevada Power Company SF N/A N/A N/A 5 Overton Power District #5 SF N/A N/A N/A 6 PacifiCorp SF N/A N/A N/A 7 Portland General Electric Co. SF N/A N/A N/A 8 Powerex Corp. SF N/A N/A N/A 9 Public Service Co of New Mexico SF N/A N/A N/A 10 Rainbow Energy Marketing Corporation SF N/A N/A N/A 11 Salt River Project SF N/A N/A N/A 12 Sempra Generation SF N/A N/A N/A 13 Shell Energy North America (US), L.P. SF N/A N/A N/A 14 Southern California Edison SF N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.2 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 Talen Energy Marketing, LLC SF N/A N/A N/A 2 Tenaska Power Service Company SF N/A N/A N/A 3 TransAlta Energy Marketing, US, Inc. SF N/A N/A N/A 4 Tri-State Generation and Transmissio SF N/A N/A N/A 5 Tucson Electric Power Co SF N/A N/A N/A 6 Twin Eagle Resource Management, LLC SF N/A N/A N/A 7 UNS Electric, Inc. SF N/A N/A N/A 8 Vitol Inc. SF N/A N/A N/A 9 WAPA, Desert Southwest Region SF N/A N/A N/A 10 Aragonne Wind, LLC LU N/A N/A N/A 11 Arizona Solar One, LLC LU N/A N/A N/A 12 CE Turbo LLC LU N/A N/A N/A 13 Desert Sky Solar LLC LU N/A N/A N/A 14 Glendale Energy 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 High Lonesome Wind Ranch, LLC LU N/A N/A N/A 2 Novo BioPower LLC LU N/A N/A N/A 3 Perrin Ranch Wind LLC LU N/A N/A N/A 4 RE Ajo 1 LLC LU N/A N/A N/A 5 RE Bagdad Solar 1 LLC LU N/A N/A N/A 6 RE Gillespie 1, LLC LU N/A N/A N/A 7 SunE AZ 1 LLC LU N/A N/A N/A 8 SunE AZ 2 LLC LU N/A N/A N/A 9 Waste Management Renewable Energy, LLC LU N/A N/A N/A 10 Aguila Irrigation District EX 141 N/A N/A N/A 11 Buckeye Water Conservation & Drainage EX 155 N/A N/A N/A 12 City of Azusa Exchange EX N/A N/A N/A 13 Electric District #6 EX 126 N/A N/A N/A 14 Electric District #7 EX 128 N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.4 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 Electric District #8 EX 140 N/A N/A N/A 2 Harquahala Valley Power District EX 153 N/A N/A N/A 3 Maricopa City Municipal Water Conservt EX 168 N/A N/A N/A 4 McMullen Valley Water Conservt Dist EX 142 N/A N/A N/A 5 PacifiCorp Exchange EX 182 N/A N/A N/A 6 Roosevelt Irrigation District EX 158 N/A N/A N/A 7 Tonopah Irrigation District EX 143 N/A N/A N/A 8 AG-1 Contracts OS N/A N/A N/A 9 BP Energy Company OS N/A N/A N/A 10 Banked Energy OS N/A N/A N/A 11 California Independent System Operator OS N/A N/A N/A 12 Central Arizona Water Conservation Dit OS N/A N/A N/A 13 EDF Trading North America LLC OS N/A N/A N/A 14 Imperial Irrigation District OS N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.5 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 Los Angeles Dept of Water & Power OS N/A N/A N/A 2 Options and Hedges OS N/A N/A N/A 3 PacifiCorp OS N/A N/A N/A 4 Power Supply Adjuster OS N/A N/A N/A 5 Salt River Project OS N/A N/A N/A 6 San Diego Gas & Electric Co OS N/A N/A N/A 7 SFAS 133 OS N/A N/A N/A 8 Southwest Reserve Sharing Group OS N/A N/A N/A 9 Tenaska Power Service Company OS N/A N/A N/A 10 WAPA, Desert Southwest Region OS N/A N/A N/A 11 Change in Estimate AD N/A N/A N/A 12 Various counterparties - prior yrs adt AD N/A N/A N/A 13 14 Total FERC FORM NO. 1 (ED. 12-90) Page 326.6 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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 ($) (j) 1,542,211 59,089,200 2,084,981 37,819,068 179,105 1,800,000 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) Total (j+k+l) of Settlement ($) (m) 59,089,200 Line No. 1 39,746,852 2 4,955,042 6,755,042 3 339,845 20,730,545 20,730,545 4 21,600 1,172,451 1,172,451 5 12 483,754 483,754 6 1,927,784 7 25 326 8 107 9 10 -3,846 20 1,099 1,099 11 1,000 61,740 61,740 12 1,158,180 41,202,717 41,202,717 13 5,835 230,540 230,540 14 7,772,414 796,496 FERC FORM NO. 1 (ED. 12-90) 953,698 98,708,268 Page 327 261,617,529 49,716,495 410,042,292 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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 ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 10,866 401,766 271 9,315 Total (j+k+l) of Settlement ($) (m) 401,766 4,238,173 Line No. 1 9,315 2 4,238,173 3 4 74,987 2,445,501 2,445,501 6,862 220,765 220,765 5 330 10,560 10,560 6 57,837 2,587,607 2,587,607 7 2,960 68,667 68,667 8 1,712 60,196 60,196 9 824 26,897 26,897 10 800 29,600 29,600 11 4,150 62,000 62,000 12 3,277 75,386 75,386 13 7,600 249,300 249,300 14 7,772,414 796,496 FERC FORM NO. 1 (ED. 12-90) 953,698 98,708,268 Page 327.1 261,617,529 49,716,495 410,042,292 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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 ($) (j) 5,527 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 259,945 Total (j+k+l) of Settlement ($) (m) Line No. 259,945 1 1,296 46,586 46,586 2 7,074 296,261 296,261 3 31,205 1,198,807 1,198,807 4 330 20,592 20,592 5 55,909 1,609,369 1,609,369 6 1,300 68,800 68,800 7 15,333 1,116,646 1,116,646 8 9,274 244,243 244,243 9 200 2,600 2,600 10 21,038 851,189 851,189 11 4,440 136,340 136,340 12 152,455 4,369,494 4,369,494 13 626 13,313 13,313 14 7,772,414 796,496 FERC FORM NO. 1 (ED. 12-90) 953,698 98,708,268 Page 327.2 261,617,529 49,716,495 410,042,292 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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 ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) Total (j+k+l) of Settlement ($) (m) Line No. 20,250 491,204 491,204 1 14,426 418,951 418,951 2 15,217 601,627 601,627 3 960 45,600 45,600 4 8,482 234,002 234,002 5 8,400 310,200 310,200 6 1,318 33,884 33,884 7 400 16,000 16,000 8 74 1,225 1,225 9 236,859 14,204,224 14,204,224 10 718,834 91,961,151 91,961,151 11 73,864 5,378,297 5,378,297 12 39,708 3,397,017 3,397,017 13 19,306 1,611,112 1,611,112 14 7,772,414 796,496 FERC FORM NO. 1 (ED. 12-90) 953,698 98,708,268 Page 327.3 261,617,529 49,716,495 410,042,292 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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 ($) (j) 243,521 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 14,508,620 Total (j+k+l) of Settlement ($) (m) Line No. 14,508,620 1 100,901 9,381,687 9,381,687 2 191,913 16,168,670 16,168,670 3 9,231 1,226,789 1,226,789 4 34,116 5,106,483 5,106,483 5 42,787 4,082,308 4,082,308 6 25,621 3,253,712 3,253,712 7 35,828 4,043,889 4,043,889 8 22,855 1,878,452 1,878,452 9 7,772,414 2,606 1,918 1,723 1,392 175,475 324,347 10 11 -2,491,943 -2,491,943 12 493 467 13 1,341 5,084 14 796,496 953,698 FERC FORM NO. 1 (ED. 12-90) 98,708,268 Page 327.4 261,617,529 49,716,495 410,042,292 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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 ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) Total (j+k+l) of Settlement ($) (m) Line No. 26,058 16,246 1 2,963 5,408 2 4,282 9,103 3 6,563 8,905 4 571,373 571,030 2,793 5,045 6 826 4,753 7 -2,107,788 -2,107,788 5 44,210 897,530 897,530 8 1 14 14 9 5,810,800 5,810,800 10 2 20,010 1,675,303 1,695,313 11 310 10,700 10,700 12 33,600 873,600 873,600 13 7,868 295,603 295,603 14 7,772,414 796,496 FERC FORM NO. 1 (ED. 12-90) 953,698 98,708,268 Page 327.5 261,617,529 49,716,495 410,042,292 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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 ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (k) (l) 790 15,800 75 2,100 22,007,200 Total (j+k+l) of Settlement ($) (m) Line No. 15,800 1 22,007,200 2 2,100 3 19,505,567 4 10 220 220 5 2,431 91,903 91,903 6 19,505,567 -4,691,981 7 1,626 86,166 86,166 8 165 3,536 3,536 9 8,571 245,341 -4,691,981 245,341 10 -847,231 -847,231 11 90,880 90,880 12 13 14 7,772,414 796,496 FERC FORM NO. 1 (ED. 12-90) 953,698 98,708,268 Page 327.6 261,617,529 49,716,495 410,042,292 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 FOOTNOTE DATA Schedule Page: 326 Line No.: 3 Column: a Eastern Area Schedule Page: 326.5 Line No.: 8 Column: b Line No.: 9 Column: b Represents nonfirm Schedule Page: 326.5 Represents nonfirm Schedule Page: 326.5 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: 326.5 Represents nonfirm Schedule Page: 326.5 Represents nonfirm Schedule Page: 326.5 Represents nonfirm Schedule Page: 326.5 Represents nonfirm 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.: 11 Column: a Represents nonfirm Schedule Page: 326.6 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: 326.6 Line No.: 11 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. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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 Electrical District 3 Various Various FNO 11 EDF Trading North America, LLC Not Available Not Available LFP 12 Electrical District 3 Not Available Not Available LFP 13 CSE Operating 1, LLC Not Available Not Available LFP 14 NOVO BioPower LLC Not Available Not Available LFP 15 PacifiCorp Not Available Not Available LFP 16 Public Service Company of New Mexico Not Available Not Available LFP 17 Salt River Project Not Available Not Available LFP 18 Salt River Project (OATT General Srvs) Not Available Not Available LFP 19 Arizona Public Service Company Not Available Not Available SFP 20 Arizona Electric Power Cooperative, Inc Not Available Not Available SFP 21 City of Aneheim Not Available Not Available SFP 22 EDF Trading North America, LLC Not Available Not Available SFP 23 Iberdrola Renewables Not Available Not Available SFP 24 Macquire Energy LLC Not Available Not Available SFP 25 PacifiCorp Not Available Not Available SFP 26 Powerex Not Available Not Available SFP 27 Public Service Company of New Mexico Not Available Not Available SFP 28 Salt River Project Not Available Not Available SFP 29 Salt River Project (OATT General Service) Not Available Not Available SFP 30 Sempra Generation Not Available Not Available SFP 31 Shell Energy North America LP Not Available Not Available SFP 32 Sundevil Power Holdings Not Available Not Available SFP 33 Tenaska Power Services Co. Not Available Not Available SFP 34 TransAlta Energy Marketing U.S. Inc 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) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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 SFP 2 Yuma Cogeneration Associates Not Available Not Available SFP 3 Arizona Public Service Company Not Available Not Available NF 4 Arizona Electric Power Cooperative, Inc Not Available Not Available NF 5 Cargill Power Markets, LLC Not Available Not Available NF 6 City of Anaheim Not Available Not Available NF 7 EDF Trading North America, LLC Not Available Not Available NF 8 El Paso Electric Co Not Available Not Available NF 9 Iberdrola Renewables Not Available Not Available NF 10 Imperial Irrigation District Not Available Not Available NF 11 Macquire Energy LLC Not Available Not Available NF 12 Mag Energy Solutions, Inc Not Available Not Available NF 13 Morgan Stanley Not Available Not Available NF 14 Nevada Power Company Not Available Not Available NF 15 NV Energy Not Available Not Available NF 16 PacifiCorp Not Available Not Available NF 17 Powerex Not Available Not Available NF 18 Public Service Company of New Mexico Not Available Not Available NF 19 Pudget Sound Energy Inc Not Available Not Available NF 20 Salt River Project Not Available Not Available NF 21 Salt River Project (OATT General Service) Not Available Not Available NF 22 Sempra Generation Not Available Not Available NF 23 Shell Energy North America LP Not Available Not Available NF 24 Southern California Edison Company Not Available Not Available NF 25 Tenaska Power Services Co. Not Available Not Available NF 26 TransAlta Energy Marketing U.S Inc. Not Available Not Available NF 27 Tucson Electric Power Company Not Available Not Available NF 28 WestConnect Not Available Not Available NF 29 Yuma Cogeneration Associates Yuma Cogeneration Assoc. San Diego Gas and Elect. NF 30 Arizona Public Service Company Not Available Not Available OLF 31 Imperial Irrigation District Not Available Not Available OS 32 Luke AFB Main Field DOE WAPA Lower Luke Air Force Base OS 33 Marine Corps. Air Station DOE WAPA Lower Marine Corp Air Station OS 34 NOVO BioPower LLC Not Available Not Available OS TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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 PacifiCorp Not Available Not Available OLF 2 Public Service Company of New Mexico Public Serv of New Mexico Public Serv of New Mexico OLF 3 Salt River Project (Schedule F) Salt River Project Salt River Project OS 4 Salt River Project (Schedule Q) Pinnacle Peak Ocotillo 230 OS 5 Tucson Electric Power Company Tucson Electric Power Tucson Electric Power OLF 6 Unit B Irrigation and Drainage District Arizona Power Authority Unit B Irrigation District OS 7 Western Area Power Administration (DSW) Not Available Not Available OLF 8 Yuma Cogeneration Associates Yuma Cogeneration Assoc. San Diego Gas and Elect. OLF 9 Yuma Mesa Irrigation and Drainage District DOE WAPA Lower Yuma-Mesa Irrigation Dist OS Not Available Not Available AD 10 Other 11 12 13 14 15 16 17 18 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) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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) MegaWatt Hours Delivered (j) Line No. OATT Various Various 887,126 887,126 1 OATT Various Various 29,506,158 29,506,158 OATT Various Various 3 OATT Various Various 4 OATT Cholla Ajo Customers OATT West Wing Substation Various OATT Various Various 4 OATT Various Various 56 OATT Various Various 5 OATT Various Various 170 OATT N/A N/A OATT Various Various OATT Various Various 1 OATT Various Various 14 OATT Various Various 37 206,039 OATT Various Various 10 OATT Various Various 275 OATT Various Various 280 OATT Various Various OATT Various Various OATT Various OATT Various OATT 2 3 14,181 14,181 5 45 325,379 325,379 6 54,111 54,111 7 649,571 649,571 8 21,232 21,232 9 460,563 460,563 3 134,291 12 4,365 4,365 13 110,721 110,721 14 206,039 15 77,968 77,968 16 214,998 214,998 17 560,952 560,952 18 8,648 41,569 41,569 19 1,725 6,919 6,919 20 Various 6,952 239,973 239,973 21 Various 3,420 4,130 4,130 22 Various Various 80 139 139 23 OATT Various Various 1,442 1,382 1,382 24 OATT Various Various 22,726 69,820 69,820 25 OATT Various Various 1,899 5,497 5,497 26 OATT Various Various 4,678 15,425 15,425 27 OATT Various Various 384 452 452 28 OATT Various Various 2,685 20,109 20,109 29 OATT Various Various 275 526 526 30 OATT Various Various 200 200 200 31 OATT Various Various 3,894 8,337 8,337 32 OATT Various Various 3,142 5,571 5,571 33 OATT Various Various 219 489 489 34 219,020 42,282,561 42,261,873 FERC FORM NO. 1 (ED. 12-90) 90 10 11 Page 329 134,291 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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) OATT Various Various 82,955 OATT Various Various 44 OATT Various Various 4,015 OATT Various Various 234 OATT Various Various OATT Various Various OATT Various OATT Various OATT Line No. MegaWatt Hours Delivered (j) 141,220 141,220 1 29 29 2 56,175 56,175 3 744 744 4 1,959 2,853 2,853 5 5,919 8,257 8,257 6 Various 788 163 163 7 Various 142 125 125 8 Various Various 119 178 178 9 OATT Various Various 72 36 36 10 OATT Various Various 670 1,313 1,313 11 OATT Various Various 40 41 41 12 OATT Various Various 4,530 8,850 8,850 13 OATT Various Various 200 1,100 1,100 14 OATT Various Various 204 329 329 15 OATT Various Various 19,313 62,071 62,071 16 OATT Various Various 1,192 2,157 2,157 17 OATT Various Various 1,174 3,722 3,722 18 OATT Various Various 1 OATT Various Various 944 1,281 1,281 20 OATT Various Various 4,518 86,894 86,894 21 OATT Various Various 515 575 575 22 OATT Various Various 519 641 641 23 OATT Various Various 1,515 1,525 1,525 24 OATT Various Various 449 1,851 1,851 25 OATT Various Various 1,613 8,185 8,185 26 OATT 21,620 65,662 65,662 27 6,620 6,620 28 94 94 29 378,733 378,733 30 19 Various Various Tariff Volume 6 Various Various OATT Various Various RS 183 Not Available Not Available OATT Not Available Not Available 31 RS 162 Pinnacle Peak Sub Luke Substation 32 RS 166 Gila Substation Marine Corp Air Stn 33 OATT Not Available Not Available 34 113 219,020 FERC FORM NO. 1 (ED. 12-90) Page 329.1 42,282,561 42,261,873 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2015/Q4 End of 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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) 130 MegaWatt Hours Delivered (j) Line No. RS 183 Not Available Not Available 6,335,077 6,335,077 1 RS 73 Palo Verde Four Corners RS 3 West Phoenix Sub West Phoenix Sub 855,861 855,861 2 RS 3 Pinnacle Peak Ocotillo 230 RS 32 Four Corners Saguaro Plant RS 181 Gila Substation District Customer RS 33 Not Available Not Available RS 198 Riverside Substation North Gila Sub 8 RS 31 Gila Substation Yuma Mesa Load 9 NA Not Available Not Available 100 3 4 51 601,903 581,215 5 6 103 103 7 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 219,020 FERC FORM NO. 1 (ED. 12-90) Page 329.2 42,282,561 42,261,873 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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 ($) (k) 8,631,657 95,614 -43,705 1,435,556 266,885 8,631,657 1 2 -8,631,657 -8,631,657 -263,883,812 -263,883,812 3 263,883,812 263,883,812 4 -376 51,533 5 -10,633 1,424,923 6 52,643 264,437 7 2,012,086 36,624 2,048,710 8 158,956 10,339 169,295 9 -23,683 2,428,759 10 2,777,095 -55,091 Line No. Total Revenues ($) (k+l+m) (n) -324,653 8,978 1,911,943 344,199 22,882 4,841 8,978 11 2,256,142 12 60,961 88,684 13 506,935 -3,377 503,558 14 1,339,573 -1,602 1,337,971 15 362,047 -2,419 359,628 16 2,469,019 2,469,019 17 7,608,433 -12,421 7,596,012 18 279,379 193,783 473,162 19 37,587 20 37,587 1,834,666 -8,376 1,826,290 21 79,824 143,584 223,408 22 1,053 23 24 1,053 10,102 -4 10,098 523,693 -18,893 504,800 25 44,074 -166 43,908 26 167,826 403,555 571,381 27 2,890 2,890 28 71,970 71,970 29 2,170 -3 820 81,458 2,167 30 820 31 81,458 32 36,440 -14 36,426 33 3,973 -95 3,878 34 2,611,159 34,768,234 32,230,440 FERC FORM NO. 1 (ED. 12-90) -73,365 Page 330 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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 ($) (k) 1,562,829 -1,754 Line No. Total Revenues ($) (k+l+m) (n) 1,561,075 1 327 -9 318 2 298,746 67,161 365,907 3 4,580 4 21,974 5 53,164 6 4,580 21,992 -18 53,164 6,984 10,123 17,107 7 979 20,242 21,221 8 1,617 -19 1,598 9 536 7,970 8,506 10 11,275 -10 11,265 11 305 12 305 60,568 -81 60,487 13 12,651 -12 12,639 14 2,030 15 2,030 283,004 283,004 16 17,504 -315 17,189 17 24,370 -80,298 -55,928 18 7 19 12,400 8,168 20,568 20 98,258 5,468 103,726 21 3,790 -28 3,762 22 4,740 -45 4,695 23 13,770 -33 13,737 24 11,822 -164 11,658 25 50,129 -302 49,827 26 478,764 1,766 480,530 27 1,113 229 1,342 29 4,416 48,581 52,997 31 174,623 32 7 28 30 173,579 1,044 77,652 32,230,440 FERC FORM NO. 1 (ED. 12-90) -73,365 Page 330.1 77,652 33 2,716 2,716 34 2,611,159 34,768,234 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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) 1 1,415,030 1,415,030 2 23,352 23,352 3 1,112,647 4 1,824,000 1,824,000 5 540 540 6 1,515,190 1,515,190 8 4,500 4,500 9 589,749 10 1,112,647 7 589,749 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 32,230,440 FERC FORM NO. 1 (ED. 12-90) -73,365 Page 330.2 2,611,159 34,768,234 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company 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.: 5 Column: m Line No.: 6 Column: m Line No.: 7 Column: m Unreserved use credit Schedule Page: 328 Unreserved use credit Schedule Page: 328 Direct assignment charges and unreserved use credit Schedule Page: 328 Line No.: 8 Column: m Unreserved use credit and penalty Schedule Page: 328 Line No.: 9 Column: m Unreserved use credit and penalty Schedule Page: 328 Line No.: 10 Column: m Line No.: 11 Column: d Line No.: 12 Column: d Unreserved use credit Schedule Page: 328 Termination 2/1/2015 Schedule Page: 328 Termination date 5/31/2025 Schedule Page: 328 Line No.: 13 Column: d Termination date 5/15/2020 Schedule Page: 328 Line No.: 13 Column: m Direct assignment charges and unreserved use credit Schedule Page: 328 Line No.: 14 Column: d 10 MW Terminates 1/1/2028 and 4 MW Terminates 10/1/2031 Schedule Page: 328 Line No.: 14 Column: m Line No.: 15 Column: d Unreserved use credit Schedule Page: 328 Termination date 7/15/2041 Schedule Page: 328 Line No.: 15 Column: m Line No.: 16 Column: d Unreserved use credit Schedule Page: 328 Can renew annually FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 FOOTNOTE DATA Schedule Page: 328 Line No.: 16 Column: m Line No.: 17 Column: d Unreserved use credit 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.: 18 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.: 18 Column: m Unreserved use credit and penalty Schedule Page: 328 Line No.: 19 Column: a APS Merchant is an affiliate of Arizona Public Service Company Schedule Page: 328 Line No.: 19 Column: m Unreserved use penalty Schedule Page: 328 Line No.: 21 Column: m Line No.: 22 Column: m Unreserved use credit Schedule Page: 328 Unreserved use credit and penalty Schedule Page: 328 Line No.: 24 Column: m Line No.: 25 Column: m Unreserved use credit Schedule Page: 328 Out of period adjustment and unreserved use credit Schedule Page: 328 Line No.: 26 Column: m Line No.: 27 Column: m Unreserved use credit Schedule Page: 328 Unreserved use penalty Schedule Page: 328 Line No.: 30 Column: m Line No.: 33 Column: m Line No.: 34 Column: m Line No.: 1 Column: m Line No.: 2 Column: m Line No.: 3 Column: a Unreserved use credit Schedule Page: 328 Unreserved use credit Schedule Page: 328 Unreserved use credit Schedule Page: 328.1 Unreserved use penalty Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 APS Merchant is an affiliate of Arizona Public Service Company Schedule Page: 328.1 Line No.: 3 Column: m Line No.: 5 Column: m Line No.: 7 Column: m Line No.: 8 Column: m Line No.: 9 Column: m Unreserved use penalty Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use penalty Schedule Page: 328.1 Unreserved use penalty Schedule Page: 328.1 Unreserved use credit FERC FORM NO. 1 (ED. 12-87) Page 450.2 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 FOOTNOTE DATA Schedule Page: 328.1 Line No.: 10 Column: m Line No.: 11 Column: m Line No.: 13 Column: m Line No.: 14 Column: m Line No.: 17 Column: m Line No.: 18 Column: m Line No.: 20 Column: m Line No.: 21 Column: m Line No.: 22 Column: m Line No.: 23 Column: m Line No.: 24 Column: m Line No.: 25 Column: m Line No.: 26 Column: m Line No.: 27 Column: m Line No.: 28 Column: n Line No.: 29 Column: m Line No.: 30 Column: a Unreserved use penalty Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use penalty Schedule Page: 328.1 Unreserved use penalty Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use credit Schedule Page: 328.1 Unreserved use penalty Schedule Page: 328.1 Regional pricing Schedule Page: 328.1 Unreserved use penalty Schedule Page: 328.1 APS Merchant is an affiliate of Arizona Public Service Company Schedule Page: 328.1 Line No.: 30 Column: d Termination date 10/31/2020 Schedule Page: 328.1 Line No.: 30 Column: n Exchange agreement pursuant to Pre888 contract Schedule Page: 328.1 Line No.: 31 Column: d Terminates upon mutual agreement Schedule Page: 328.1 Line No.: 31 Column: m Direct assignment charges Schedule Page: 328.1 Line No.: 32 Column: d Termination date 10 years or longer with a three year termination notice by either party. Schedule Page: 328.1 Line No.: 33 Column: d Termination date - Indefinite term subject to a three year termination notice by either party. Schedule Page: 328.1 Line No.: 34 Column: d Termination date 1/1/2028 FERC FORM NO. 1 (ED. 12-87) Page 450.3 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 FOOTNOTE DATA Schedule Page: 328.1 Line No.: 34 Column: m Direct assignment charges Schedule Page: 328.2 Line No.: 1 Column: d Termination date 10/31/2020 Schedule Page: 328.2 Line No.: 1 Column: n Exchange agreement pursuant to Pre888 contract Schedule Page: 328.2 Line No.: 2 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.: 3 Column: d Termination date - Good until terminated with a three year advance written notice. Schedule Page: 328.2 Line No.: 4 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.: 4 Column: m Direct assignment charges (O&M/Lease payment) Schedule Page: 328.2 Line No.: 5 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.: 6 Column: d Termination date - indefinite term subject to three year termination notice by either party. Schedule Page: 328.2 Line No.: 7 Column: d Termination date 6/1/2046. Subject to three year termination notice. Schedule Page: 328.2 Line No.: 7 Column: n Exchange agreement pursuant to Pre888 contract Schedule Page: 328.2 Line No.: 8 Column: d Termination date 12/31/2024 Schedule Page: 328.2 Line No.: 9 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.: 10 Column: d FERC transmission rate true up, change in estimate, and timing difference. Schedule Page: 328.2 Line No.: 10 Column: m FERC transmission rate true up, change in estimate, and timing difference. FERC FORM NO. 1 (ED. 12-87) Page 450.4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/Q4 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling") 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) EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Energy Other Total Cost of Charges Charges Charges Transmission ($) ($) ($) ($) (e) (f) (g) (h) 1 Arizona Public Service LFP 839,070 2 Bureau of Indian Affair OLF 3 Department of Energy OS 9,094 9,094 4 Department of Energy OS 124,337 124,337 272,022 175,552 2,623 450,197 5 Department of Energy FNS 312,155 312,155 934,325 519,467 -24,491 1,429,301 6 Department of Energy OS 1,143,170 1,143,170 3,632,493 879,931 -104,593 4,407,831 7 Department of Energy LFP 543,234 543,234 50,505 409,718 63,628 523,851 8 Department of Energy LFP 112,305 112,305 1,446,319 339,750 505,826 2,291,895 9 Department of Energy LFP 62,855 62,855 6,602,639 49,418 2,589 6,654,646 10 Department of Energy FNS 143,600 7,162 92,066 11 Department of Energy OS 160,745 160,745 289,369 LFP 2,583 2,583 82,363 13 Electric District # 4 OLF 466 466 14,064 14 Salt River Project OLF 39,694 39,694 182,078 15 Salt River Project OLF 339,432 339,432 16 Salt River Project LFP 177,735 177,735 5,419,454 5,419,454 21,651,190 FERC FORM NO. 1/3-Q (REV. 02-04) 143,600 208,801 12 Electric District # 3 TOTAL 839,070 Page 332 215,963 92,066 2,639 1 292,009 -1,184 81,179 17,619 31,683 31,272 -29,774 183,576 1,306,785 267,511 -267,511 1,306,785 1,230,153 142,797 -1,960 1,370,990 4,281,551 -83,786 25,848,955 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling") 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) 1 Salt River Project FNS 2 Salt River Project OLF 3 Salt River Project OS 371 371 485,396 EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Energy Other Total Cost of Charges Charges Charges Transmission ($) ($) ($) ($) (e) (f) (g) (h) 485,396 1,918,785 107,915 107,915 238,498 1,716,132 1,716,132 4 Salt River Project FNS 5 Salt River Project OS 6 Southern Cal Edison LFP 101 101 179,297 7 Southwester Transmissio SFP 43,951 43,951 175,040 8 Tucson Electric Power OS 286 286 1,698 9 Public Srvs Co of NM 10 SRP Misc AR 1,784,755 385,789 -3,624 2,300,950 86,224 -351,036 -26,314 449,095 97,367 546,462 302,754 -34,308 2,053,201 3,700 100 3,700 21,230 200,527 4,709 179,749 2,064 3,862 NF 800 800 79,817 404 OS 36,697 36,697 155,449 26,629 9,877 191,955 80,221 5,419,454 5,419,454 21,651,190 4,281,551 -83,786 25,848,955 11 12 13 14 15 16 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 332 Line No.: 1 Column: a Intercompany Transmission Schedule Page: 332 Line No.: 1 Column: b Terminates December 31, 2015 Schedule Page: 332 Line No.: 2 Column: b Teminates with 30 days notice Schedule Page: 332 Line No.: 3 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 4 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 5 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 6 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 7 Column: b Terminates September 30, 2029 Schedule Page: 332 Line No.: 7 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 8 Column: b Terminates May 1, 2022 Schedule Page: 332 Line No.: 8 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 9 Column: b Terminates December 31, 2017 Schedule Page: 332 Line No.: 9 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 10 Column: b Terminates September 30, 2029 Schedule Page: 332 Line No.: 11 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 12 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 13 Column: b Effective until terminated by counterparty Schedule Page: 332 Line No.: 13 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 14 Column: b Terminates with 1 year APS notice or 5 year SRP notice Schedule Page: 332 Line No.: 14 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 15 Column: b Terminates with 5 year notice Schedule Page: 332 Line No.: 15 Column: g Prior period adjustment /Timing Schedule Page: 332 Line No.: 16 Column: b Terminates May 1, 2019 Schedule Page: 332 Line No.: 16 FERC FORM NO. 1 (ED. 12-87) Column: g Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 1 Column: g Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 1 Column: h APS payment as a credit on APS provides SRP in the same contract Schedule Page: 332.1 Line No.: 2 Column: b Terminates with 1 year notice Schedule Page: 332.1 Line No.: 2 Column: g Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 3 Column: b Loss compensation for deliveries to DV Schedule Page: 332.1 Line No.: 3 Column: g Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 4 Column: g Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 6 Column: b Terminates September 30, 2037 Schedule Page: 332.1 Line No.: 6 Column: g Line No.: 7 Column: g Ancilliary/Timing Schedule Page: 332.1 Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 8 Column: g Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 10 Column: g Prior period adjustment /Timing FERC FORM NO. 1 (ED. 12-87) Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 Name of Respondent 20160317-8000 FERC Arizona Public Service Company This Report Is: PDF (Unofficial) 03/17/2016 (1) X An Original Line No. Date of Report (Mo, Da, Yr) 03/17/2016 (2) A Resubmission MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC) Description (a) 1 Industry Association Dues Year/Period of Report 2015/Q4 End of Amount (b) 970,388 2 Nuclear Power Research Expenses 3 Other Experimental and General Research Expenses 13,443 4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 1,423,757 6 Allocation of Parent Company Costs 9,235,597 7 Bank Fees 750,267 8 Billed to Others-Services Performed -64,872,491 9 Communication Service 282,359 10 Materials & Supplies 41,743 11 Miscellaneous Payroll -86,534 12 Outside Services 616,440 13 Rents/Leases 54,448 14 Transportation Expense 12,384 15 Travel 303,879 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 -51,254,320 TOTAL FERC FORM NO. 1 (ED. 12-94) Page 335 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405) (Except amortization of aquisition adjustments) 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) 57,569,607 Amortization of Other Electric Plant (Acc 405) (e) Total (f) 57,569,607 2 Steam Production Plant 55,014,425 2,102,978 2,135 57,119,538 3 Nuclear Production Plant 58,056,969 -2,173,590 2,257,519 58,140,898 4 Hydraulic Production Plant-Conventional -441,067 -441,067 5 Hydraulic Production Plant-Pumped Storage 6 Other Production Plant 69,267,330 7 Transmission Plant 43,894,009 4,067,809 47,961,818 124,145,279 927,403 125,072,682 35,465,416 5,922,645 41,388,061 70,747,118 456,219,556 8 Distribution Plant 140,689 69,408,019 9 Regional Transmission and Market Operation 10 General Plant 11 Common Plant-Electric 12 TOTAL 385,402,361 70,077 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% - 33.33% 2.08% - 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) Line No. Account No. (a) 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) Page 337 Applied Depr. rates (Percent) (e) Mortality Curve Type (f) Average Remaining Life (g) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of REGULATORY COMMISSION EXPENSES 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) 7,545,289 5 Legal and Filing Fees 6 Consulting Fees 7 Payroll and Employee Expense 8 Est. ACC and RUCO Assessments on Unbilled Rev 7,545,289 3,520 3,520 18,649 18,649 1,795,018 1,795,018 -70,532 -70,532 2,347,758 2,347,758 9 Other 10 11 FERC Expenses 12 Regulatory Assessment by FERC 13 Legal and Filing Fees 14 Consulting Fees 15 Payroll and Employee Expenses 3,291 3,291 189,888 189,888 16 Other 17 18 NRC Expenses 19 NRC License Fees 5,093,276 5,093,276 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) 14,915,791 Page 350 2,010,366 16,926,157 Deferred in Account 182.3 at Beginning of Year (e) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of REGULATORY COMMISSION EXPENSES (Continued) 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 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. 12-96) Page 351 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES 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 B(1) EPRI 4 B(1) EPRI 5 B(1) EPRI 6 B(1) EPRI 7 B(1) EPRI 8 B(1) EPRI 9 B(1) EPRI 10 Total 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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued) (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) 410,740 Account (e) 5490 Amount (f) 410,740 Line No. 1 5880 49,585 2 861,911 1070 861,911 3 526,034 5000 526,034 4 129,208 5060 129,208 5 937,715 5240 937,715 6 379,390 5490 379,390 7 712,731 5800 712,731 8 23,716 9200 23,716 9 49,585 49,585 Unamortized Accumulation (g) AMOUNTS CHARGED IN CURRENT YEAR 3,981,445 4,031,030 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of DISTRIBUTION OF SALARIES AND WAGES 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) 121,903,047 16,731,259 38,168,170 27,814,848 2,038,431 6,872,764 87,825,852 301,354,371 45,801,822 3,876,707 23,966,563 4,070,462 77,715,554 167,704,869 20,607,966 62,134,733 27,814,848 2,038,431 6,872,764 91,896,314 379,069,925 354 379,069,925 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of DISTRIBUTION OF SALARIES AND WAGES (Continued) Line No. 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 Cedar NU PV-NG Yuma Navajo STS 500 KV Line Studies Street Lights Miscellaneous Billings TOTAL Other Accounts TOTAL SALARIES AND WAGES FERC FORM NO. 1 (ED. 12-88) Page 355 Allocation of Payroll charged for Clearing Accounts (c) Total (d) 379,069,925 379,069,925 158,111,185 158,111,185 158,111,185 158,111,185 205,300 107,409 74,516 327 3,758,887 2,094,463 213,548,419 17,244,314 8,981,271 2,142,488 339,017 88 326,911 1,379,169 27,874 640,672 745,682 251,616,807 788,797,917 205,300 107,409 74,516 327 3,758,887 2,094,463 213,548,419 17,244,314 8,981,271 2,142,488 339,017 88 326,911 1,379,169 27,874 640,672 745,682 251,616,807 788,797,917 20160317-8000 03/17/2016 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/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) 2,448,050 4,099,061 5,748,367 6,703,684 ( 8,187,668) ( 18,021,501) ( 29,933,244) ( 46,080,726) ( 5,739,618) ( 13,922,440) ( 24,184,877) ( 39,377,042) 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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 61,645 MW 2 Reactive Supply and Voltage 61,645 MW 3 Regulation and Frequency Response 61,645 MW 4 Energy Imbalance 1,803,363 Usage - Related Billing Determinant Unit of Measure Number of Units Dollars (e) (f) (g) 67,964 MW 2,002,825 67,964 MW 6,939,384 MWh 64,173 MW -35,176 MWh 7,067,848 -364,042 5 Operating Reserve - Spinning 61,645 MW 15,919,257 64,173 MW 16,058,908 6 Operating Reserve - Supplement 61,645 MW 2,017,866 64,173 MW 2,039,384 7 Other 8 Total (Lines 1 thru 7) FERC FORM NO. 1 (New 2-04) 308,225 26,679,870 Page 398 293,271 26,804,923 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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 $40,891 of sold revenue in column (g) for 2015. Schedule Page: 398 Line No.: 2 Column: g 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/Q4 End of (2) 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 5,079 2 February 4,206 3 March 4,907 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 4,308 151 339 281 2 800 3,441 148 336 281 30 1800 4,091 199 336 281 11,840 498 1,011 843 2 4 Total for Quarter 1 5 April 5,275 30 1700 4,438 220 336 281 6 May 6,241 31 1800 5,384 234 342 281 7 June 7,562 18 1700 8 Total for Quarter 2 6,741 108 432 281 16,563 562 1,110 843 6,240 104 432 281 9 July 7,057 2 10 August 7,932 15 1700 7,122 97 432 281 11 September 6,786 8 1700 5,991 82 432 281 19,353 283 1,296 843 1700 12 Total for Quarter 3 13 October 6,351 1 1700 5,571 67 432 281 14 November 4,692 30 800 3,886 93 432 281 15 December 5,248 17 800 16 Total for Quarter 4 4,432 103 432 281 13,889 263 1,296 843 61,645 1,606 4,713 3,372 17 Total Year to Date/Year FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 400 Line No.: 1 Column: b Updated due to counterparty checkouts Schedule Page: 400 Line No.: 1 Column: e Updated due to counterparty checkouts Schedule Page: 400 Line No.: 2 Column: b Updated due to counterparty checkouts Schedule Page: 400 Line No.: 2 Column: e Updated due to counterparty checkouts Schedule Page: 400 Line No.: 3 Column: b Updated due to counterparty checkouts Schedule Page: 400 Line No.: 3 Column: e Updated due to counterparty checkouts Schedule Page: 400 Line No.: 5 Column: b Updated due to counterparty checkouts Schedule Page: 400 Line No.: 5 Column: e Updated due to counterparty checkouts Schedule Page: 400 Line No.: 5 Column: f Updated due to counterparty checkouts Schedule Page: 400 Line No.: 7 Column: b Updated due to counterparty checkouts Schedule Page: 400 Line No.: 7 Column: f Updated type of service per settlement agreement (docket ER15-710-002) Schedule Page: 400 Line No.: 7 Column: g Updated type of service per settlement agreement (docket ER15-710-002) Schedule Page: 400 Line No.: 11 Column: b Updated due to counterparty checkouts Schedule Page: 400 Line No.: 11 Column: f Updated due to counterparty checkouts FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD Year/Period of Report 2015/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: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of ELECTRIC ENERGY ACCOUNT 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 15,907,972 4 Nuclear 9,461,777 23 Requirements Sales for Resale (See 24 Non-Requirements Sales for Resale (See 6 Hydro-Pumped Storage 25 Energy Furnished Without Charge 27,442,278 26 Energy Used by the Company (Electric 7,772,414 27 Total Energy Losses 28 TOTAL (Enter Total of Lines 22 Through 11 Power Exchanges: 12 Received 796,496 13 Delivered 953,698 14 Net Exchanges (Line 12 minus line 13) 27) (MUST EQUAL LINE 20) -157,202 15 Transmission For Other (Wheeling) 16 Received 42,282,561 17 Delivered 42,261,873 18 Net Transmission for Other (Line 16 minus 20,688 line 17) 19 Transmission By Others Losses 20 TOTAL (Enter Total of lines 9, 10, 14, 18 35,078,178 and 19) FERC FORM NO. 1 (ED. 12-90) 63,255 Dept Only, Excluding Station Use) through 8) 10 Purchases 5,528,035 instruction 4, page 311.) 2,072,529 8 Less Energy for Pumping 9 Net Generation (Enter Total of lines 3 150,328 instruction 4, page 311.) 5 Hydro-Conventional 7 Other 27,950,491 Interdepartmental Sales) Page 401a 1,386,069 35,078,178 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission MONTHLY PEAKS AND OUTPUT Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 2,374,709 244,041 4,391 2 30 February 2,078,108 337,864 3,510 2 8:00 31 March 2,461,937 461,179 4,209 30 18:00 32 April 2,380,665 357,128 4,572 30 17:00 33 May 2,775,225 545,258 5,556 31 18:00 34 June 3,566,763 555,642 6,940 18 17:00 35 July 3,845,211 577,311 6,414 2 17:00 36 August 4,019,849 460,006 7,320 15 17:00 37 September 3,420,766 569,880 6,136 8 17:00 38 October 2,941,367 617,264 5,726 1 17:00 39 November 2,547,279 616,102 3,965 30 8:00 40 December 2,666,299 404,703 4,516 17 8:00 35,078,178 5,746,378 41 TOTAL FERC FORM NO. 1 (ED. 12-90) Page 401b 8:00 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 401 Line No.: 29 Column: b Adjusted to better reflect monthly activity Schedule Page: 401 Line No.: 29 Column: d Updated due to counterparty checkouts Schedule Page: 401 Line No.: 30 Column: b Adjusted to better reflect monthly activity Schedule Page: 401 Line No.: 30 Column: d Updated due to counterparty checkouts Schedule Page: 401 Line No.: 31 Column: b Adjusted to better reflect monthly activity Schedule Page: 401 Line No.: 31 Column: d Updated due to counterparty checkouts Schedule Page: 401 Line No.: 32 Column: b Adjusted to better reflect monthly activity Schedule Page: 401 Line No.: 32 Column: d Updated due to counterparty checkouts Schedule Page: 401 Line No.: 33 Column: b Adjusted to better reflect monthly activity Schedule Page: 401 Line No.: 34 Column: b Adjusted to better reflect monthly activity Schedule Page: 401 Line No.: 35 Column: b Adjusted to better reflect monthly activity Schedule Page: 401 Line No.: 36 Column: b Adjusted to better reflect monthly activity Schedule Page: 401 Line No.: 37 Column: b Adjusted to better reflect monthly activity FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 366496 9175 43.959 36.066 1.965 0.021 0.000 Page 402 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoor 1962 1981 113.60 113 7093 0 116 116 45 627267666 1415539 20543084 142374201 6435774 170768598 1503.2447 1595890 11941579 0 2581846 0 0 523399 1030310 0 484478 1453486 1153391 3004907 385188 1298492 25452966 0.0406 Gas MCF 2038 862675 10.473 -150.442 -174.390 -1.870 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 1.775 0.019 10724.361 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/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) 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 2.770 0.030 10714.799 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 Coal Tons 0 0 0.000 0.000 0.000 0.000 0.000 Gas MCF 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoor 1963 1970 0.00 0 0 0 0 0 25 0 0 0 0 0 0 0 901393 0 0 0 0 0 0 -241307 105322 0 0 529 34256 858 13292 814343 0.0000 Total 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 1739325 8892 40.986 43.318 2.436 0.024 0.000 Page 402.2 Plant Name: Ocotillo 1 (c) Steam Over 50% Outdoor 1969 1970 515.40 768 7414 0 485 485 27 3146105513 34814 14283669 129048527 9678744 153045754 296.9456 2342088 76278511 0 7718818 0 0 761211 3988930 431159 2429933 1174728 1576445 11481491 1947559 5277108 115407981 0.0367 Gas Total Gas MCF MCF 142619 0 1259859 1032487 0 1001455 5.925 0.000 1.547 6.551 0.000 1.711 6.345 2.454 1.708 0.063 0.024 0.039 0.000 9878.185 0.000 Steam Over 50% Outdoor 1960 1960 113.60 102 1384 0 110 110 11 55383000 152872 2358015 27049081 0 29559968 260.2110 0 2155028 0 186612 0 0 873557 180614 0 42776 0 201748 86382 655989 158778 4541484 0.0820 Total 0 0 0.000 0.000 1.708 0.039 22781.214 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/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 618020 10754 47.205 51.327 2.386 0.023 0.000 Page 402.3 Steam Units 1,2,3 Over 50% Outdoor 1974 1976 337.34 320 23295 0 315 315 0 1385869001 25111 32849766 238125776 1865912 272866565 808.8770 3588046 32366092 0 1830776 0 0 1118896 4383842 85176 0 1439596 255345 7283106 2896741 755250 56002866 0.0404 Oil Total Oil Bbls Bbls 4594 0 0 136819 0 0 107.136 0.000 0.000 140.451 0.000 0.000 24.442 2.430 0.000 0.235 0.023 0.000 0.000 9610.303 0.000 (c) Comb. Turbine Over 50% Outdoor 1971 2008 23.60 18 71 0 19 0 3 616000 33986 605677 2795511 0 3435174 145.5582 0 39910 0 0 0 0 300342 0 0 0 0 437 0 121069 453 462211 0.7503 Total Gas MCF 11690 1046308 1.841 3.414 3.263 0.065 0.000 0 0 0.000 0.000 3.263 0.065 19855.519 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/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 1135 0 48 0 2 22689000 13711 1755189 36301565 0 38070465 629.2639 157600 1429794 0 0 0 0 0 0 0 0 0 20724 0 511666 271269 2391053 0.1054 Gas Total Oil MCF Bbls 277830 0 0 1063805 0 0 2.775 0.000 0.000 5.146 0.000 0.000 4.838 4.838 0.000 0.063 0.063 0.000 0.000 13026.445 0.000 (c) Comb. Turbine Over 50% Outdoor 2007 2008 60.50 48 1160 0 48 0 0 25547000 0 1743296 35956047 0 37699343 623.1296 177452 1529174 0 0 0 0 0 687861 0 0 0 23334 0 397131 159343 2974295 0.1164 Total Gas MCF 286116 1039613 2.882 5.345 5.141 0.060 0.000 0 0 0.000 0.000 5.141 0.060 11643.246 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 78 337 0 79 0 0 16465000 0 510354 30015002 0 30525356 389.8513 0 1162391 0 0 0 0 8717 0 0 0 0 27758 0 288683 0 1487549 0.0903 Gas MCF 222311 1064621 2.820 5.229 4.911 0.071 0.000 Page 402.5 Total 0 0 0.000 0.000 4.911 0.071 14374.552 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoor 1972 1973 53.10 47 43 0 55 0 3 628000 0 878490 23098291 0 23976781 451.5401 0 112877 0 0 0 0 217983 62383 0 0 310174 40284 0 250089 32161 1025951 1.6337 Gas MCF 18644 1035523 3.265 6.054 5.847 0.180 0.000 Total 0 0 0.000 0.000 5.847 0.180 30742.516 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 605.00 443 1806 0 420 0 14 56518000 681252 14017813 278939233 0 293638298 485.3526 0 2852855 0 0 0 0 705152 2957168 0 0 0 305050 0 3019458 23033 9862716 0.1745 Gas MCF 590601 1031551 2.605 4.830 4.683 0.050 0.000 Page 402.6 Total 0 0 0.000 0.000 4.683 0.050 10779.486 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoor 1976 2003 132.00 160 2331 0 88 0 3 73861174 4011 3040457 46128524 0 49172992 372.5227 83557 5464311 0 0 0 0 0 0 0 0 0 17533 0 1547927 59497 7172825 0.0971 Gas MCF 929284 1040602 3.171 5.880 5.651 0.074 0.000 Total 0 0 0.000 0.000 5.651 0.074 13092.332 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/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 569.60 481 8622 0 506 0 31 1447168000 28158 14963054 287827833 0 302819045 531.6346 1637144 56701989 0 0 0 0 3178378 3115645 0 0 0 349544 0 4242485 859365 70084550 0.0484 Gas MCF 14280130 1596805 2.141 3.971 5.273 0.039 0.000 Page 402.7 Total 0 0 0.000 0.000 5.273 0.039 7608.871 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoor 2002 2002 573.10 552 19934 0 492 0 14 2375275000 1128691 12686806 268220371 0 282035868 492.1233 51678 88792024 0 0 0 0 1165032 3799503 0 0 0 351698 0 3076494 1295921 98532350 0.0415 Gas MCF 15217044 2225805 3.147 5.835 5.152 0.037 0.000 Total 0 0 0.000 0.000 5.152 0.037 7237.714 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 410.82 404 8044 0 382 0 228 3056368442 1618647 309942586 766663534 -21917073 1056307694 2571.2178 8552193 25085750 4361714 4225547 0 0 2873492 13479831 15069645 0 3203195 810253 6088532 5925180 1247190 90922522 0.0297 Nuclear Kg Uranium 466 66702 2805.980 53889.540 0.795 0.008 10327.541 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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) 03/17/2016 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 660170 9181 40.212 42.630 2.322 0.026 0.000 Oil Bbls 2893 126416 105.600 259.539 48.882 0.551 0.000 Plant Name: Cholla 3 (e) Steam Over 50% Outdoor 1978 1981 288.90 249 5760 0 260 260 33 1076540381 0 0 0 0 0 0.0000 1011347 29001814 0 3071172 0 0 358412 928696 0 831479 884762 465870 1713050 163653 1249220 39679475 0.0369 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 2.390 0.027 11273.994 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 758849 9164 44.433 48.701 2.657 0.028 0.000 Oil Bbls 3456 126550 116.201 390.705 73.508 0.788 0.000 Steam Over 50% Outdoor 1980 1981 312.30 265 6732 0 271 271 55 1299762253 3933199 57194907 398384415 15035298 474547819 1519.5255 2193634 38581471 0 3886734 0 0 421238 1389896 0 1003887 1964621 466769 4448066 810049 2095321 57261686 0.0441 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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) Coal Tons 0 0 0.000 0.000 0.000 0.000 0.000 Gas MCF 0 0 0.000 0.000 0.000 0.000 0.000 Plant Name: Four Corners 3 (e) Steam Over 50% Outdoor 1963 1970 0.00 0 0 0 0 0 1 0 0 0 0 0 0 0 -6709 0 0 0 0 0 0 9283 105322 0 0 529 34039 858 8775 152097 0.0000 Total FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Coal Tons 0 0 0.000 0.000 0.000 0.000 0.000 Gas MCF 0 0 0.000 0.000 0.000 0.000 0.000 Plant Name: Four Corners 4 (f) Steam Over 50% Outdoor 1964 1970 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 -4696 0 0 0 0 0 0 9286 105322 0 0 529 33691 858 8673 153663 0.0000 Total Page 403.1 0 0 0.000 0.000 0.000 0.000 0.000 Coal Tons 1880617 8839 40.392 42.636 2.412 0.024 0.000 Gas MCF 122141 1085692 5.691 6.293 5.796 0.057 0.000 Line No. Steam Over 50% Outdoor 1969 1970 515.40 791 7577 0 485 485 29 3377218267 29232 15760125 103048327 9671566 128509250 249.3389 2439501 80951931 0 7883680 0 0 761210 4290133 431159 2608436 1174728 1254092 12684460 1546132 4530090 120555552 0.0357 Total 0 0 0.000 0.000 2.425 0.024 9883.454 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 113.60 110 1068 0 110 110 11 50139000 138712 2446503 27274657 0 29859872 262.8510 0 1945646 0 168942 0 0 866235 163513 0 38725 0 106502 140617 455352 143744 4029276 0.0804 Gas MCF 556235 1492380 3.163 3.498 2.344 0.039 0.000 Total 0 0 0.000 0.000 2.344 0.039 16556.254 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 0.00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 6075 0 0 0 0 2277 172719 0 0 1216 843 280 0 13870 197280 0.0000 Gas MCF 0 0 0.000 0.000 0.000 0.000 0.000 Total 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 0.00 0 0 0 0 0 0 0 52347 0 0 0 52347 0 0 6075 0 0 0 0 2277 0 0 0 1216 843 0 0 0 10411 0.0000 Gas MCF 0 0 0.000 0.000 0.000 0.000 0.000 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 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) 03/17/2016 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 11166 1047167 1.589 2.947 2.814 0.053 0.000 Plant Name: Yucca 4 (e) Comb. Turbine Over 50% Outdoor 1971 2008 23.60 19 64 0 19 0 1 617000 0 472555 2597402 0 3069957 130.0829 0 32908 0 0 0 0 0 0 0 0 0 438 0 512212 578 546136 0.8851 Total FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 2.814 0.053 18951.378 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Gas MCF 64476 1042869 2.399 4.448 4.265 0.085 0.000 Line No. (f) Comb. Turbine Over 50% Outdoor 1973 2008 72.40 50 161 0 55 0 1 3374000 0 972279 15841137 0 16813416 232.2295 0 525207 0 0 0 0 0 0 0 0 0 2393 0 218070 4051 749721 0.2222 Total Page 403.3 0 0 0.000 0.000 7.811 0.156 19928.868 Oil Bbls 180 137697 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 18 5 0 54 0 1 45000 0 706722 7583390 0 8290112 114.5043 0 0 0 0 0 0 0 3372 0 0 0 32 0 58498 0 61902 1.3756 Total 0 0 0.000 0.000 0.000 0.000 23133.169 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) 03/17/2016 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 48 0 16 0 0 397000 9557 103952 5268581 0 5382090 206.2103 2937 131458 0 0 0 0 0 2985 0 0 0 36327 0 229108 29389 432204 1.0887 Oil Bbls 1158 136506 109.843 113.530 19.802 0.331 0.000 Total 0 0 0.000 0.000 19.802 0.331 16721.881 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 55 36 0 55 0 0 847000 0 1310745 15745362 0 17056107 321.2073 0 82100 0 0 0 0 448 51577 0 0 0 1100 0 56052 25354 216631 0.2558 Gas MCF 22044 1065324 2.008 3.724 3.496 0.097 0.000 Total 0 0 0.000 0.000 3.496 0.097 27726.092 Page 403.4 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoor 1973 2002 53.10 45 34 0 55 0 0 832000 0 1351929 10448309 0 11800238 222.2267 0 92157 0 0 0 0 440 51577 0 0 0 1180 0 108095 149387 402836 0.4842 Gas MCF 22969 1066916 2.164 4.012 3.761 0.111 0.000 Total 0 0 0.000 0.000 3.761 0.111 29454.327 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) 03/17/2016 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 52 47 0 55 0 2 656000 0 1074733 19744846 0 20819579 392.0825 0 110920 0 0 0 0 210747 56476 0 0 0 34931 0 115744 0 528818 0.8061 Gas MCF 20106 1038347 2.975 5.517 5.313 0.169 0.000 0 0 0.000 0.000 5.313 0.169 31824.695 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 28 48 0 55 0 1 618000 6294 2105490 18012862 0 20124646 378.9952 50200 84422 0 0 0 0 37858 0 0 0 0 424 0 204470 31862 409236 0.6622 Gas MCF 15924 1041070 2.859 5.302 5.092 0.137 0.000 Total 0 0 0.000 0.000 5.092 0.137 26825.243 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 47 83 0 55 0 2 746000 0 1822390 20057159 0 21879549 412.0442 60597 118719 0 0 0 0 45699 0 0 0 0 7030 0 124515 3655 360215 0.4829 Gas MCF 20167 1039173 3.175 5.887 5.665 0.159 0.000 0 0 0.000 0.000 5.665 0.159 28092.493 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) 03/17/2016 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 80 2459 0 88 0 2 80265144 3711 2421148 43074534 0 45499393 344.6924 90802 5705986 0 0 0 0 0 0 0 0 0 12021 0 210727 148794 6168330 0.0768 Gas MCF 988740 1041101 3.112 5.771 5.543 0.071 0.000 Total 0 0 0.000 0.000 5.543 0.071 12824.720 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 90 1860 0 88 0 3 101007262 4619 4339750 52290244 0 56634613 429.0501 114267 5841741 0 0 0 0 0 0 0 0 0 15914 0 776458 111538 6859918 0.0679 Gas MCF 960220 1040402 3.281 6.084 5.848 0.058 0.000 Total 0 0 0.000 0.000 5.848 0.058 9890.526 Page 403.6 0 0 0.000 0.000 0.000 0.000 0.000 Line No. Combined Cycle Over 50% Outdoor 2001 2003 135.60 109 1312 0 117 0 8 109286000 36557 5561109 82219664 0 87817330 647.6204 483010 5236694 0 0 0 0 519405 0 0 0 0 23944 0 906172 73477 7242702 0.0663 Gas MCF 993478 1040983 2.843 5.271 5.064 0.048 0.000 Total 0 0 0.000 0.000 5.064 0.048 9463.188 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) 03/17/2016 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 567.20 549 19060 0 492 0 26 2149994000 1056089 10988053 242875792 0 254919934 449.4357 46776 82791392 0 0 0 0 2341707 3439143 0 0 0 311235 0 10804524 1079111 100813888 0.0469 Gas MCF 15164584 2101174 2.944 5.460 5.197 0.039 0.000 Total 0 0 0.000 0.000 5.197 0.039 7557.174 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 410.82 391 8760 0 382 0 205 3375856203 1694862 312558246 814566341 -17074386 1111745063 2706.1610 8724828 27017581 4360405 3415668 0 0 2919664 12996127 15065125 0 679798 521845 2169345 3262032 844538 81976956 0.0243 Nuclear Kg Uranium 501 66702 0.000 53889.540 0.779 0.008 10270.772 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 7889 0 382 0 229 3029553576 1104281 194285654 543326229 -14668759 724047405 1762.4444 8549183 26478450 4360405 4323374 0 0 2627223 13433273 15065125 0 2125945 839244 5913294 7155164 1305401 92176081 0.0304 Nuclear Kg Uranium 491 66700 2871.754 53889.540 0.853 0.009 10241.251 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) 03/17/2016 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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) 03/17/2016 This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2015/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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report End of 2015/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) 03/17/2016 (2) A Resubmission GENERATING PLANT STATISTICS (Small Plants) 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company Year/Period of Report 2015/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 0.45 807 2,566,632 3 Star 1998 0.22 198 2,121,478 4 Tempe 1998 0.01 12 12,817 5 Glendale Airport 1999 0.07 127 114,593 6 Gilbert 2001 0.12 234 56,928 0.29 552 557,305 268 550,117 7 Scottsdale Covered Parking 1999 8 Municipal Rooftops 1999 9 Yuma 2002 0.17 10 Prescott Earu 2002 0.18 404 162,310 11 Prescott 2001 2.71 4,907 2,605,373 51,361 12 Red Rock 2005 13 Phoenix 1998 3.05 100 29,052 14 Hyder Phase 1 & 2 2011 16.00 42,004 73,340,993 15 Hyder II 2013 14.00 43,826 51,811,899 16 Cotton Center 2011 17.00 42,798 80,506,726 17 Paloma 2011 17.00 39,257 66,071,021 18 US Airways Center 2011 0.18 349 1,350,091 19 Chase Field 2011 0.06 96 1,477,062 20 Chino Valley 2012 19.00 46,476 86,991,993 21 Foothills 1 & 2 2012 35.00 110,820 143,313,165 22 APS Solar for Schools 2012 13.20 24,166 59,332,100 23 DVN1 2013 0.02 43 24 Palo Verde Emergengy OPS Center 2013 0.03 66 25 Gila Bend Phase 1 2014 16.00 52,035 26 Gila Bend Phase 2 2014 16.00 52,767 27 Carol Spring 2015 28 Desert Star 2015 10.00 14,817 29 Luke AFB 2015 528,504 30 Total Solar Operation/Maintenance 10.00 18,441 32,297,721 495,570 748,588,849 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 Page 32,597,473 190.76 31 FERC FORM NO. 1 (REV. 12-03) 110,142,135 410 This Report Is: Name of Respondent Date of Report Year/Period of Report (Mo, Da, Yr) 2015/Q4 End of Arizona Public Service Company 03/17/2016 (2) 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. 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X 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 5,700,585 2 9,469,533 3 2,194,693 4 1,598,678 5 494,169 6 1,949,708 7 8 3,316,196 9 880,587 10 959,811 11 12 9,544 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 4,494,862 22 23 24 6,883,883 25 26 27 3,259,747 28 3,229,772 29 3,924,281 3,251,052 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 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.: 30 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 2015/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of TRANSMISSION LINE STATISTICS 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 HASSAYAMPA 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 VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 345.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 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 NORTH GILA 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 Designed (d) 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 345.00 230.00 345.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 (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 (A) (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 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 10.30 1.60 2 1 881.15 81 256.00 76.00 180.00 206.00 47.00 120.00 242.70 13.30 0.25 18.50 35.68 111.50 566.00 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 5,211.50 (h) 1 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 2 1 1 2 366.00 27.00 Number Of Circuits Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of TRANSMISSION LINE STATISTICS 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 LINCOLN STREET 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 VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 69.00 115.00 115.00 115.00 115.00 115.00 115.00 115.00 WEST PHOENIX PLANT 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) 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 115.00 115.00 115.00 115.00 115.00 115.00 (3) STEEL (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 5.50 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 5,211.50 Number Of Circuits (h) 1 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 81 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of TRANSMISSION LINE STATISTICS 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 69.00 UNDERGROUND OVERHEAD RELATED TRANSMISSION EHV STRUCTURES TEMP. LIMITED TERM LAND Designed (d) 69.00 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) 29.35 2,756.52 1.64 30.58 1 5,211.50 881.15 81 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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 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 EXPENSES, EXCEPT DEPRECIATION AND TAXES Land rights, and clearing right-of-way) Land (j) 4,014,277 2,321,510 743,746 55,612 1,350,823 8,522 494,861 1,175,680 50,610 12,237,938 284,676 15,603,430 8,582,119 4,744,391 424,643 138,023 40,721 322,267 803,802 35,944 157,325 8,969 9,660,020 220,297 112,180 820,160 1,931,778 135,385,358 FERC FORM NO. 1 (ED. 12-87) Construction and Other Costs (k) Total Cost Operation Expenses (m) (l) 19,901,127 5,971,160 39,917,113 8,831,923 1,208,159 5,807,204 60,391,579 5,151,452 4,727,505 17,090,839 626,769 23,915,404 5,971,160 42,238,623 9,575,669 1,208,159 5,862,816 61,742,402 5,159,974 5,222,366 18,266,519 677,379 29,540,970 776,503 32,420,062 3,178,473 103,003,307 30,649,195 947,577 3,424,030 3,681,055 2,537,537 1,858,571 3,352,137 3,135,075 3,250,560 2,097,188 7,704,155 536,518 3,218,080 6,759,381 1,826,612 4,017,851 17,978 41,778,908 1,061,179 48,023,492 3,178,473 111,585,426 35,393,586 947,577 3,848,673 3,819,078 2,578,258 2,180,838 4,155,939 3,171,019 3,407,885 2,106,157 17,364,175 756,815 3,330,260 7,579,541 1,826,612 5,949,629 17,978 1,140,613,003 1,275,998,361 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 25,966,635 423 15,008,345 7,550,709 48,525,689 36 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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) 1113 AA 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) 37,261 383,722 286,973 171,181 142,671 3,283,837 3,077,401 1,324,874 203,127 855,388 3,321,098 3,461,123 1,611,847 374,308 998,059 68,982 1,021,582 85,094 42,236 390,432 78,429 519,018 381,847 933,461 141,199 352,384 46,640 74,058 435,033 93,110 18,029 12,019 365,101 2,785,385 6,122,495 5,672,649 1,663,288 3,775,970 872,073 6,704,094 1,203,882 4,485,834 4,206,368 6,951,684 39,196 16,026,636 6,250,720 7,821,426 618,139 857,317 13,492,925 374,911 383,526 13,894,312 2,380,164 1,951,111 3,113,684 2,115,819 433,334 392,494 229,551 3,027,431 2,854,367 7,144,077 5,757,743 1,705,524 4,166,402 950,502 7,223,112 1,585,729 5,419,295 4,347,567 7,304,068 39,196 23,416,408 7,292,081 11,422,192 618,139 857,317 21,734,711 374,911 383,526 20,581,496 2,380,164 1,997,751 3,187,742 2,550,852 526,444 410,523 241,570 3,392,532 135,385,358 1,140,613,003 1,275,998,361 7,389,772 1,041,361 3,600,766 8,241,786 6,687,184 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 25,966,635 423.1 15,008,345 7,550,709 48,525,689 36 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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) 27,849,198 21,621 Construction and Other Costs (k) 38,244,872 552,575,231 5,328,484 315,726 8,128,884 135,385,358 FERC FORM NO. 1 (ED. 12-87) 1,140,613,003 Total Cost Operation Expenses (m) (l) Maintenance Expenses (n) Rents (o) 38,244,872 580,424,429 5,350,105 315,726 8,128,884 1,275,998,361 Page 25,966,635 15,008,345 7,550,709 25,966,635 15,008,345 7,550,709 423.2 Total Expenses (p) Line No. 1 2 3 4 5 48,525,689 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 48,525,689 36 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 FOOTNOTE DATA Schedule Page: 422.2 Line No.: 3 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.: 5 Column: a INCLUDES LAND AND LAND RIGHTS FOR PALO VERDE TO SUN VALLEY, SUNDANCE TO PINAL CENTRAL, AND GILA RIVER TO JOJOBA Schedule Page: 422.2 Line No.: 6 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 LINE #18 - HASSAYAMPA TO NORTH GILA (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 FERC FORM NO. 1 (ED. 12-87) Page 450.1 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 FOOTNOTE DATA (10) CO-OWNERS OF LINE 15 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC SERVICE OF NEW MEXICO (11) CO-OWNERS OF LINE 16 ARE SALT RIVER PROJECT AND ARIZONA PUBLIC SERVICE COMPANY (12) CO-OWNERS OF LINE 18 ARE ARIZONA PUBLIC SERVICE COMPANY AND THE IMPERIAL IRRIGATION DISTRICT (13) EXPENSES TO OPERATE THESE LINES ARE ALLOCATED TO PARTICIPANTS BASED ON OWNERSHIP AS SET FORTH IN OPERATION AND MAINTENANCE AGREEMENTS (14) 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of 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) 111.50 STEEL CIRCUITS PER STRUCTURE Present Ultimate (f) (g) 4.00 1 1 8.00 1 2 8.00 1 2 0.02 WOOD 1 1 WILLIS 8.80 STEEL 1 2 RIO SALADO 0.87 STEEL 1 1 RIO SALADO 0.35 STEEL 1 1 1 1 1 1 1 1 1 HASSAYAMPA NORTH GILA 2 TRILBY WASH PALM VALLEY 3 TRILBY WASH PALM VALLEY 9.40 STEEL 4 MCMICKEN/TRILBY WASH FESTIVAL RANCH 0.31 STEEL 5 CHOLLA WINSLOW 6 ESTRELLITA 7 BUTTE 8 OCOTILLO 15.90 STEEL/HYBRID TONOPAH 0.24 STEEL 10 WADELL/DYSART WADDELL/HEARN 3.26 STEEL 11 COTTON CENTER GILLESPIE 5.00 STEEL 12 FESTIVAL/MCMICKEN TRILBY WASH 1.75 STEEL 2 2 13 EL SOL MERIDIAN -0.01 STEEL 1 1 13 16 9 HARQUAHALA 14.20 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 43 157.39 44 TOTAL FERC FORM NO. 1 (REV. 12-03) Page 424 34.20 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2015/Q4 End of TRANSMISSION LINES ADDED DURING YEAR (Continued) 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 Voltage KV (Operating) (k) 500 LINE COST Poles, Towers Conductors Asset Land and and Fixtures and Devices Land Rights Retire. Costs (n) (o) (l) (m) 8,582,119 55,984,299 47,019,008 (h) (2) 2156 ACSR Configuration and Spacing (j) 84/19 2156 KCMIL 84/19 230 11,702,034 795 ACSS 45/7 69 336.4 ACSR 26/7 795 ACSR 795 795 Specification Total Line No. (p) 111,585,426 1 5,015,157 16,717,191 2 6,918,184 2,964,936 9,883,120 3 69 468,034 200,586 668,620 4 45/7 69 190,512 81,648 272,160 5 ACSS 45/7 69 3,225,528 1,382,369 4,607,897 6 ACSS 45/7 69 769,536 335,479 1,105,015 7 795 ACSS 45/7 69 319,769 137,044 456,813 8 795 ACSS 45/7 69 206,874 88,660 295,534 9 795 ACSS 45/7 69 130,521 55,937 186,458 10 795 ACSS 45/7 69 1,597,938 580,701 2,292,124 11 795 ACSS 45/7 69 661,205 283,374 944,579 12 795 ACSS 45/7 69 339,516 23,438 362,954 13 (i) 113,485 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 8,695,604 FERC FORM NO. 1 (REV. 12-03) Page 425 82,513,950 58,168,337 149,377,891 44 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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 - PEORIA 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 12.00 9 ANTELOPE-PRESCOTT D 69.00 10 AQUEDUCT - PHOENIX D 69.00 4.16 11 ARABY-YUMA D 69.00 12.00 12 ARICA-ELOY D 69.00 12.00 13 ARLINGTON-MARICOPA COUNTY D 69.00 12.00 14 ARROWHEAD-GLENDALE D 69.00 12.00 15 ARROYO-PHOENIX D 69.00 12.00 16 ASARCO PIT-CASA GRANDE D 69.00 12.00 17 ASHFORK-ASHFORK D 69.00 12.00 18 AZTEC - DATELAND D 69.00 12.00 19 BACON-N.W. OF SNOWFLAKE D 69.00 12.00 20 BADGER SUB - TONOPAH D 69.00 12.00 21 BAGDAD NEW TOWN - BAGDAD T 115.00 12.00 22 BAGDAD-115KV CAP.-BAGDAD T 115.00 23 BAJA-SAN LUIS D 69.00 12.00 24 BALD MOUNTAIN-PRESCOTT VALLEY D 69.00 12.00 25 BASELINE-BUCKEYE D 69.00 12.00 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) 12.40 12.00 12.00 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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 Tertiary (e) 12.00 12.00 12 CAVE CREEK-CAVE CREEK D 69.00 13 CEDAR MOUNTAIN-WILLIAMS T 525.00 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 34.50 12.00 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 CIELO GRANDE-PHOENIX D 69.00 12.00 26 CLINIC - SCOTTSDALE D 69.00 12.00 27 COCONINO-FLAGSTAFF T 230.00 69.00 28 COCONINO-FLAGSTAFF D 69.00 12.00 29 COCOPAH-W. OF YUMA D 69.00 12.00 30 COLDWATER-GOODYEAR D 69.00 12.00 31 COLORADO-N. OF PARKER D 69.00 12.00 32 COLTER-AVONDALE D 69.00 12.00 33 CONLEY-SNOWFLAKE T 69.00 34 COOLIDGE-N. OF COOLIDGE D 12.40 35 COPPER CANYON-N. OF CAMP VERDE D 69.00 12.00 36 CORDES-CORDES JUNCTION D 69.00 12.00 37 CORNVILLE-CORNVILLE D 69.00 12.00 38 COTTON CENTER-N. OF GILA BEND D 69.00 12.00 39 COTTONWOOD-COTTONWOOD D 69.00 12.00 40 COTTONWOOD-COTTONWOOD D FERC FORM NO. 1 (ED. 12-96) Page 426.1 4.16 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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) 12.00 D Primary (c) 69.00 2 COUNTRY CLUB-PHOENIX T 230.00 69.00 3 COUNTY LINE - TONOPAH D 69.00 12.00 4 CROSSROADS-N. OF PARKER D 34.50 12.00 5 DALE-SCOTTSDALE D 69.00 12.00 6 DALE-SCOTTSDALE D 69.00 7 DAVENPORT- E. OF WILLIAMS D 69.00 12.00 8 DEADMAN WASH-PHOENIX D 69.00 12.00 9 DEADMAN WASH-PHOENIX (a) 1 COUNTRY CLUB-PHOENIX (b) D 69.00 10 DEER VALLEY-PHOENIX T 230.00 69.00 11 DEER VALLEY-PHOENIX D 69.00 12.00 12 DEL RIO-PEORIA D 69.00 12.00 13 DELANO-PRESCOTT D 69.00 12.00 14 DESERT RIDGE-SCOTTSDALE D 69.00 12.00 15 DESERT SANDS - YUMA T 69.00 16 DESERT SKY-BUCKEYE D 69.00 12.00 17 DESERT SPRINGS-PHOENIX D 69.00 12.00 18 DEWEY-N. OF DEWEY D 69.00 12.00 19 DIXILETA-N. OF SCOTTSDALE D 69.00 12.00 20 DON LUIS-BISBEE D 69.00 12.00 21 DOUBLETREE-PHOENIX D 69.00 12.00 22 DOVE VALLEY-PHOENIX D 69.00 12.00 23 DOWNING-SCOTTSDALE D 69.00 12.00 24 DRAKE-PAULDEN D 69.00 25 DRY LAKE - HOLBROOK D 69.00 7.20 525.00 69.00 69.00 12.00 26 DUGAS-MAYER T 27 DUGAS-MAYER T 28 DURANGO-PHOENIX D 29 DYSART-SURPRISE D 69.00 12.00 30 EAGLE EYE-W. OF AGUILA T 230.00 69.00 31 EAST END-SCOTTSDALE D 69.00 12.00 32 EASTERN OFFICE-PHOENIX D 69.00 12.00 33 EASTGATE-CASA GRANDE D 69.00 12.00 34 EGG RANCH - TONOPAH D 69.00 12.00 35 EHRENBERG-EHRENBERG D 34.50 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 12.00 34.50 12.00 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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 14.40 13 FOUR CORNERS-FRUITLAND,NM A,T 230.00 69.00 4.16 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 - BUCKEYE 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 - CAMERON D 69.00 21.60 28 GREENBRIER-GLENDALE D 69.00 12.00 29 GREENWAY-GLENDALE D 69.00 12.00 30 GREY BEARS-CHINO VALLEY D 69.00 12.00 31 GRISWOLD-PHOENIX D 69.00 12.00 32 HAMBLIN - CAMERON D 69.00 12.00 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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 - DATELAND T 525.00 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 - DATELAND 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 KAIBAB - WILLIAMS D 69.00 12.00 19 KEAMS CANYON-W. OF KEAMS CANYON D 69.00 21.00 20 KEARNY-KEARNY D 21.00 21 KIRKLAND JUNCTION-SE. OF KIRKLAND D 69.00 12.00 22 LAGUNA - SOMERTON D 69.00 12.00 23 LE BARRON HILL-FLAGSTAFF D 69.00 7.20 24 LEROUX-N. OF HOLBROOK D 69.00 12.00 25 LEUPP JUNCTION - W. OF WINSLOW D 69.00 21.00 26 LIBERTY IRON-PHOENIX D 69.00 27 LINCOLN STREET (230kV)-PHOENIX T 230.00 69.00 28 LINCOLN STREET NORTH-PHOENIX D 69.00 12.00 29 LINCOLN STREET WEST-PHOENIX D 69.00 12.00 30 LITCHFIELD-LITCHFIELD PARK D 69.00 12.00 31 LOMA VISTA-PHOENIX D 69.00 12.00 32 LONE PEAK-PHOENIX T 230.00 69.00 33 LONE PEAK-PHOENIX D 69.00 12.00 34 LONESOME VALLY-PRESCOTT D 69.00 12.00 35 LOOKOUT-PHOENIX D 69.00 12.00 36 LUKE FIELD NORTH-LUKE AFB D 69.00 12.00 37 MAGNOLIA - STANTON D 69.00 7.20 38 MARINE AIR BASE-YUMA D 69.00 12.00 39 MARINETTE-SUN CITY D 69.00 12.00 40 MARTINEZ WASH-WICKENBURG D 69.00 7.20 FERC FORM NO. 1 (ED. 12-96) Page 426.4 Tertiary (e) 12.00 12.00 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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 MAZATAL-RYE D Primary (c) 69.00 2 MCGUIREVILLE - RIM ROCK D 69.00 12.00 3 MCCORMICK-SCOTTSDALE D 69.00 12.00 4 MCDOWELL-PHOENIX D 69.00 12.00 5 MCMICKEN-SURPRISE D 69.00 12.00 6 MEADOWBROOK-PHOENIX T 230.00 69.00 7 MEADOWBROOK-PHOENIX D 69.00 12.00 8 MERIDIAN-GLENDALE D 69.00 9 MERRILL-FLORENCE D 69.00 12.00 10 METRO-PHOENIX D 69.00 12.00 11 MILLER WASH-VALLE D 69.00 7.20 12 MILLIGAN-ELOY T 230.00 69.00 13 MILLIGAN TEMP-ELOY D 69.00 12.00 14 MINGUS-JEROME D 69.00 7.20 12.00 15 MITTRY D 69.00 16 MOENKOPI-CAMERON T 525.00 17 MOENKOPI-CAMERON T 525.00 18 MONTE CRISTO-PHOENIX D 69.00 12.00 19 MOON VALLEY-PHOENIX D 69.00 12.00 20 MORGAN-PEORIA T 525.00 230.00 21 MORRISTOWN-MORRISTOWN D 69.00 12.00 22 MOUNTAIN VIEW-SUN CITY D 69.00 12.00 23 MT. FLOYD - SELIGMAN D 4.16 12.00 24 MT. FLOYD - SELIGMAN T 230.00 12.00 25 MUMMY MOUNTAIN-PARADISE VALLEY D 69.00 12.00 26 MUNDS PARK-S. OF FLAGSTAFF D 69.00 21.00 27 MURAL - BISBEE D 69.00 12.00 28 MURAL - BISBEE T 115.00 69.00 69.00 7.20 29 NADASY-N. OF WILLIAMS D 30 NAVAJO-PAGE A,T 525.00 31 NAVAJO-PAGE A,T 525.00 32 NAVAJO ARMY DEPOT-FLAGSTAFF D 69.00 12.00 33 NEW RIVER-NEW RIVER D 69.00 12.00 Tertiary (e) 12.00 12.00 34.50 12.00 34 NEWMAN PARK-S. OF FLAGSTAFF D 69.00 7.20 35 NORTH GILA-YUMA T 525.00 230.00 34.50 36 NORTH GILA-YUMA T 525.00 69.00 34.50 37 NORTH VALLEY-PHOENIX D 69.00 12.00 38 OAK CREAK-OAK CREEK D 69.00 12.00 39 OBERLIN TEMP - SURPRISE D 69.00 12.00 40 OCOTILLO-TEMPE A,T 230.00 69.00 FERC FORM NO. 1 (ED. 12-96) Page 426.5 12.00 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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) Primary (c) Secondary (d) 1 OCOTILLO-TEMPE A,T 2 OCOTILLO-TEMPE A,T 69.00 3 OLD HOME MANOR-CHINO VALLEY D 69.00 4 ORANGEWOOD-PHOENIX D 69.00 12.00 5 ORMES - MAYER D 69.00 4.16 6 OSBORNE TANK - FLAGSTAFF D 69.00 12.00 7 PADRE - FLAGSTAFF D 69.00 12.00 8 PALM VALLEY-GOODYEAR T 230.00 69.00 9 PALM VALLEY-GOODYEAR D 69.00 12.00 10 PALOMA-W. OF GILA BEND D 69.00 12.00 11 PALOMINAS -HEREFORD D 69.00 12.00 12 PANDA - GILA BEND A,T 13 PAPAGO BUTTE-SCOTTSDALE D 69.00 12.00 14 PARADISE-PHOENIX D 69.00 12.00 15 PARKS-PARKS D 69.00 12.00 16 PATTERSON-OUT OF BUCKEYE D 69.00 12.00 17 PATTON-OUT OF MORRISTON D 69.00 12.00 18 PAULDEN-PAULDEN D 69.00 12.00 19 PEBBLECREEK-GOODYEAR D 69.00 12.00 20 PEORIA-PEORIA D 69.00 12.00 21 PERRYVILLE - PERRYVILLE D 69.00 12.00 22 PICKET-SUPERIOR D 115.00 12.00 23 PIMA-GOODYEAR D 69.00 12.00 24 PINAL-GLOBE T 115.00 69.00 25 PINAL-GLOBE D 69.00 21.00 Tertiary (e) 12.00 230.00 21.00 26 PINE SPRINGS-W. OF WILLIAMS D 69.00 7.20 27 PINNACLE PEAK-PHOENIX T 525.00 230.00 34.50 28 PINNACLE PEAK-PHOENIX T 345.00 230.00 14.40 12.40 29 PINNACLE PEAK-PHOENIX T 230.00 69.00 30 PIONEER-PHOENIX D 69.00 12.00 31 PLANET-NE. OF PARKER D 69.00 12.00 32 PLEASANT-GLENDALE D 69.00 12.00 33 POLAND JUNCTION NW. OF MAYER D 69.00 12.00 34 POLK-PHOENIX D 69.00 12.00 35 POLK - PHOENIX D 69.00 12.00 36 POLLOCK -CHINO VALLEY D 69.00 12.00 37 POPLAR WASH-PEEPLES VALLEY D 69.00 7.20 38 PREACHER CANYON - STAR VALLEY T 345.00 69.00 39 PREACHER CANYON - STAR VALLEY D 69.00 21.60 40 PRESCOTT CHINO WELLS-CHINO VALEY D 69.00 4.16 FERC FORM NO. 1 (ED. 12-96) Page 426.6 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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 4 QUAIL SPRINGS-SE. OF COTTONWOOD D 69.00 12.00 5 QUARTZSITE-QUARTZSITE D 69.00 12.00 6 QUECHAN-YUMA D 69.00 12.00 7 RACEWAY-PEORIA T 230.00 69.00 8 RAINBOW VALLEY-SE. OF BUCKEYE D 69.00 12.00 9 RAINTREE-SCOTTSDALE (a) 1 PRESCOTT CHINO WELLS - CHINO VALLEY 2 PRESCOTT CITY-PRESCOTT 3 PYRAMID PEAK-GLENDALE (b) D 69.00 12.00 10 RAMON ASO-RED LAKE, N. OF WILLIAMS D 69.00 12.40 11 RAWHIDE-SCOTTSDALE D 69.00 12.00 12 REACH-SCOTTSDALE T 230.00 69.00 13 RED LAKE-E. OF WILLIAMS D 69.00 21.00 14 REDONDO-YUMA D 69.00 12.00 15 REIDHEAD-SNOWFLAKE D 69.00 7.20 16 RINCON-WICKENBURG D 69.00 7.20 17 RIO SALADO - TEMPE D 69.00 12.00 18 RIO VISTA-SUN CITY D 69.00 12.00 19 RIVERSIDE-YUMA D 69.00 12.00 20 ROAD RUNNER-PHOENIX D 69.00 12.00 21 ROBBINS BUTTE-OUT OF BUCKEYE D 69.00 12.00 22 ROCK SPRINGS-ROCK SPRINGS D 69.00 12.00 23 ROGERS LAKE-SW. OF FLAGSTAFF D 69.00 7.20 24 ROSE GARDEN-PHOENIX D 69.00 12.00 25 ROUND VALLEY - KINGMAN T 230.00 Tertiary (e) 12.40 12.00 26 SADDLE MTN-W. OF TONOPAH D 69.00 27 SADDLEBROOK - ORACLE T 115.00 28 SAGE VALLEY-VALLE D 69.00 12.00 29 SAGUARO 525kV-RED ROCK A,T 525.00 115.00 34.50 30 SAGUARO 230kv-RED ROCK A,T 230.00 115.00 12.40 31 SAGUARO 115kV-RED ROCK A,D 115.00 12.00 32 SALOME-S.E. OF SALOME D 69.00 12.00 33 SAN LUIS-SAN LUIS D 69.00 12.00 34 SAN LUIS (MEXICO CONN.)-SAN LUIS D 69.00 34.50 35 SAN MANUEL-SAN MANUEL D 115.00 46.00 36 SAN MANUEL-SAN MANUEL D 115.00 12.00 37 SAN PEDRO-W. OF DOUGLAS D 69.00 12.00 38 SANDVIG-FLAGSTAFF D 69.00 12.00 39 SANGUINETTI-YUMA T 69.00 40 SANTA ROSA-SE. OF MARICOPA T 230.00 FERC FORM NO. 1 (ED. 12-96) Page 426.7 12.00 69.00 12.40 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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) 1 SARIVAL-GOODYEAR D Primary (c) 69.00 Secondary (d) 12.00 12.00 2 SEDONA-SEDONA D 69.00 3 SELIGMAN COMPRESSER STATION-SELIGMAN D 230.00 4 SEXTON-E. OF STANFIELD D 69.00 5 SHAW-PHOENIX D 69.00 12.00 6 SHEA-SCOTTSDALE D 69.00 12.00 7 SHERMAN STREET-PHOENIX D 69.00 12.00 8 SHOW LOW-SHOW LOW D 69.00 12.00 9 SHOW LOW-SHOW LOW D 69.00 10 SHUMWAY-SHOW LOW D 69.00 11 SHUMWAY-SHOW LOW D 69.00 12 SKUNK CREEK-GLENDALE D 69.00 12.00 13 SNOWFLAKE-SNOWFLAKE D 69.00 12.00 14 SOLDIERS TRAIL - FLAGSTAFF D 69.00 12.00 15 SONORA - SUPERIOR D 69.00 21.60 16 SOUTH O'NEIL - YUMA T 69.00 17 SPANISH GARDENS-SURPRISE D 69.00 18 SPIDER WEB - FLAGSTAFF D 69.00 4.16 19 STAGECOACH-SCOTTSDALE D 69.00 12.00 7.20 12.00 12.00 20 STANTON-S. OF YARNELL D 69.00 21 STARDUST-SUN CITY WEST D 69.00 22 STOUT-PHOENIX D 69.00 12.00 23 STRAWBERRY-STRAWBERRY D 69.00 21.00 24 STURM RUGER-N. OF PRESCOTT D 69.00 4.16 25 STURM RUGER-N. OF PRESCOTT D 69.00 12.40 26 SUGARLOAF-SNOWFLAKE T 525.00 69.00 27 SUNDOG-PRESCOTT D 69.00 12.00 28 SUNNYSLOPE-PHOENIX T 230.00 69.00 29 SUNNYSLOPE-PHOENIX D 69.00 12.40 30 SUNSHINE-WINSLOW D 69.00 12.00 31 SURPRISE-SURPRISE T 230.00 69.00 32 SURPRISE-SURPRISE D 69.00 12.00 33 SWITZER CANYON-FLAGSTAFF D 69.00 12.00 34 SYCAMORE-DUGAS D 69.00 7.20 35 TABLE MESA-NEW RIVER D 69.00 7.20 36 TAPCO-E. OF CLARKDALE D 69.00 2.40 37 TARTESSO TEMPORARY - BUCKEYE D 69.00 12.00 38 TAT MOMOLI-CASA GRANDE T 230.00 39 TEMPE-TEMPE D 69.00 12.00 40 TENTH STREET-YUMA 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) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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 THAYER-THAYER D Primary (c) 69.00 2 THIRTY-SECOND STREET-YUMA D 69.00 12.00 3 THOMPSON PEAK-SCOTTSDALE D 69.00 12.00 4 TOLTEC-ELOY D 69.00 12.00 5 TONALEA-TUBA CITY D 69.00 21.60 6 TONOPAH-TONOPAH D 69.00 12.00 7 TONTO-PAYSON D 69.00 21.00 8 TONTO-PAYSON D 69.00 T 230.00 69.00 10 TUBA CITY-TUBA CITY 9 TRIBLY WASH - SURPRISE D 69.00 12.00 11 TURF-PHOENIX D 69.00 12.00 12 TUSAYAN-TUSAYAN D 69.00 12.00 13 TUSAYAN-TUSAYAN D 69.00 14 TUTHILL-BUCKEYE D 69.00 12.00 15 TWENTY-THIRD STREET-PHOENIX D 69.00 12.00 16 TWIN ARROWS - FLAGSTAFF T 69.00 17 UNION HILLS-PHOENIX D 69.00 12.00 18 UTTING-SE. OF BOUSE D 69.00 12.00 19 VALENCIA-BUCKEYE D 69.00 12.00 20 VALLE-WILLIAMS D 69.00 21.00 21 VALLEY FARMS-FLORENCE T 115.00 69.00 22 VALLEY FARMS-FLORENCE D 69.00 12.00 23 VARNEY-SURPRISE D 69.00 12.00 24 VERDE-CLARKDALE T 230.00 69.00 25 VICKSBURG-S. OF VICKSBURG JUNCTION D 69.00 12.00 26 VISTA-CASA GRANDE D 69.00 12.00 27 WADDELL-SURPRISE D 69.00 12.00 28 WALDRIP - YUMA T 69.00 29 WATSON-BUCKEYE D 69.00 12.00 30 WELCH - ASHFORK D 69.00 2.40 31 WELLFIELD - PRESCOTT VALLEY D 69.00 12.00 32 WENDON TEMP - LA PAZ D 69.00 12.00 33 WEST PHOENIX-PHOENIX T 230.00 69.00 34 WEST PHOENIX-PHOENIX D 69.00 12.40 35 WESTBROOK-PEORIA D 69.00 12.00 36 WESTWING-SUN CITY T 525.00 230.00 37 WESTWING-SUN CITY T 525.00 38 WESTWING-SUN CITY T 525.00 39 WESTWING-SUN CITY T 230.00 40 WESTWING-SUN CITY D 69.00 FERC FORM NO. 1 (ED. 12-96) Page 426.9 12.00 Tertiary (e) 12.00 12.40 12.40 12.40 34.50 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/17/2016 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2015/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) Primary (c) 230.00 Secondary (d) 69.00 1 WESTWING-SUN CITY T 2 WHITE SPAR-PRESCOTT D 69.00 12.00 3 WHITE TANKS-AVONDALE T 230.00 69.00 4 WHY - AJO D 69.00 21.60 5 WICKENBURG-WICKENBURG D 69.00 12.00 6 WILD BURRO-NEW RIVER D 69.00 7.20 7 WILD FLOWER-GOODYEAR D 69.00 12.00 8 WILHOIT-PRESCOTT D 69.00 12.00 12.00 Tertiary (e) 12.40 12.40 9 WILLIAMS-WILLIAMS D 69.00 10 WILLIS - GOODYEAR D 69.00 12.00 11 WILLOW LAKE-PRESCOTT T 230.00 115.00 12.40 12 WILLOW LAKE-PRESCOTT T 230.00 69.00 12.40 13 WINDMILL-SEDONA D 69.00 7.20 14 WINONA-WINONA D 69.00 12.00 15 WINSLOW-WINSLOW D 69.00 12.00 16 WINTERSBURG - TONOPAH D 69.00 12.00 17 WOODRUFF-HOLBROOK D 69.00 21.00 18 WOODY MOUNTAIN-FLAGSTAFF D 69.00 12.00 19 WUPATKI-FLAGSTAFF D 69.00 12.00 20 YALE-PHOENIX D 69.00 12.00 21 YARNELL-YARNELL D 69.00 12.00 22 YAVAPAI-CHINO VALLEY T 525.00 230.00 12.40 12.40 23 YAVAPAI-CHINO VALLEY T 230.00 69.00 24 YORKSHIRE-PHOENIX D 69.00 12.00 25 YOUNG'S CANYON - DONEY PARK T 345.00 69.00 26 YUCCA-YUMA T 161.00 69.00 27 YUMA PALMS TEMP-YUMA D 69.00 12.00 28 ZENIFF-SNOWFLAKE D 69.00 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 40 2 57 2 6 capacitor bank-69kv 1 capacitor bank-69kv 1 7 9 2 capacitor bank-69kv 1 14 11 20 1 capacitor bank-12kv 1 4 12 12 1 83 2 capacitor bank-69kv 1 22 14 42 1 15 9 1 16 9 1 17 20 1 18 3 1 19 20 1 20 30 1 10 13 21 capacitor bank-115kv 5 49 22 20 1 capacitor bank-69kv 1 14 23 83 2 capacitor bank -12kv 2 10 24 40 2 capacitor bank-69kv 2 22 25 20 1 83 2 26 27 capacitor bank-69kv 1 14 28 29 30 112 1 9 1 31 10 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) 1 capacitor bank-69kv Page 427 1 10 40 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 4 522 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 50 1 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 9 10 1 13 18 143 19 1 capacitor bank 525kv 1 569 20 shunt reactor 525kV 4 167 21 capacitor bank 345kv 2 870 22 23 1 24 150 2 83 2 capacitor bank -12kV 2 7 25 40 2 capacitor bank -12kV 2 7 26 27 355 2 40 2 capacitor bank-69kv 2 36 28 83 2 capacitor bank-69kv 1 14 29 83 2 capacitor bank-69kv 1 29 30 9 1 83 2 31 32 33 34 40 2 12 35 20 1 36 20 1 37 40 2 40 2 capacitor bank-12kv capacitor bank 69kv 1 7 capacitor bank-69kV 1 11 39 6 40 38 capacitor bank-12kV FERC FORM NO. 1 (ED. 12-96) 4 Page 427.1 2 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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) 125 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 3 355 2 40 2 20 1 83 2 3 1 83 2 564 3 125 3 22 1 40 2 83 2 2 capacity bank-69kV 2 14 3 4 capacitor bank-12kv 2 7 5 capacitor bank 69kV 1 29 6 capacitor bank -12kv 2 7 8 capacitor bank 69kv 1 29 9 capacitor bank-69kV 1 48 7 10 11 12 13 capacitor bank-12kv 2 10 14 15 1 16 83 2 capacitor bank-12kv 2 10 17 40 2 capacitor bank-69kv 1 14 18 83 2 capacitor bank-12kv 2 7 19 20 1 42 1 83 2 capacitor bank-12kv 2 4 22 123 3 capacitor bank-69kv 1 48 23 capacitor bank-69kv 3 22 24 4 20 21 25 1 4 shunt reactor 525kV 26 269 3 1 190 83 2 capacitor bank-525kv 1 536 27 capacitor bank-12kV 2 7 28 125 3 100 2 30 41 1 capacitor bank-12kV 2 5 31 41 1 capacitor bank-12kV 1 5 32 41 1 capacitor bank-12kV 2 14 29 33 34 40 2 20 1 376 2 36 83 2 37 40 2 83 2 39 1 40 41 FERC FORM NO. 1 (ED. 12-96) 35 1 capacitor bank-69kv 1 48 38 capacitor bank-12kv Page 427.2 1 4 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 1 shunt reactor 525kv 3 125 11 1400 2 1 shunt reactor 345kV 3 200 12 106 2 shunt reactor - 230V 2 200 13 167 4 capacitor bank 12kv 4 10 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 40 2 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 7 1 1 8 40 2 9 83 2 125 3 12 40 2 13 125 3 14 83 2 15 41 1 16 9 1 17 20 1 18 9 1 10 capacitor bank-12kV 2 7 11 19 20 9 1 36 2 21 capacitor bank-69kV 2 29 22 1 23 20 1 24 6 1 25 26 27 188 1 83 2 capacitor bank-69kV 1 35 28 167 4 capacitor bank-12kv 8 19 29 83 2 30 83 2 31 376 2 32 41 1 33 40 2 34 83 2 35 40 2 36 1 37 2 83 2 39 1 40 FERC FORM NO. 1 (ED. 12-96) capacitor bank-12kV Page 427.4 2 7 38 83 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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) 20 1 1 16 1 2 83 2 3 83 2 4 83 2 5 188 1 6 125 3 capacitor bank-69kV 1 48 7 8 41 1 capacitor bank-69kv 2 14 9 125 3 capacitor bank -12kv 4 10 10 1 11 188 1 12 1 2 14 7 1 15 1 13 capacitor bank 525kv shunt reactor 525kv 4 10 4,235 16 646 17 83 2 18 83 2 19 600 1 20 1 9 1 capacitor bank-69kv 1 11 21 83 2 capacitor bank-69kv 1 48 22 3 1 23 50 1 24 83 2 25 9 1 26 9 1 1 50 1 1 capacitor bank-12kv 4 10 27 28 29 1 shunt reactor 525kv 2 380 30 capacitor bank 525kV 2 1,738 31 6 1 32 20 1 33 1 34 600 1 shunt reactor 525kV 4 328 509 6 capacitor bank 525kv 2 979 35 36 37 83 2 40 2 16 1 39 355 2 40 FERC FORM NO. 1 (ED. 12-96) capacitor bank 12kv Page 427.5 2 5 38 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 230kv capacitor bank 69kv Number of Units (j) Line Total Capacity No. (In MVa) (k) 1 2 314 2 1 48 3 4 125 3 4 1 5 1 6 7 1 8 188 1 1 83 2 9 20 1 10 20 1 11 12 13 40 2 125 3 5 1 15 16 1 16 9 1 17 20 1 18 41 1 19 83 2 20 20 1 13 1 capacitor bank-12kV 2 7 14 21 22 1 36 2 23 84 1 24 41 1 25 1 26 3 2025 3 752 4 83 2 30 4 1 31 20 1 32 9 1 33 2 83 2 shunt reactor-525kV 1 190 27 1872 28 1 capacitor bank 230kv 3 159 29 capacitor bank-69kV 2 29 34 capacitor bank-12kV 2 10 35 3 36 1 37 162 2 38 16 1 39 3 3 40 FERC FORM NO. 1 (ED. 12-96) Page 427.6 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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) 10 1 1 40 2 2 41 1 3 40 2 16 1 5 83 2 6 188 1 7 9 1 8 83 2 9 1 10 83 2 11 376 2 capacitor bank-69kv capacitor bank-69kV 2 1 22 48 4 12 4 1 13 20 1 14 1 15 1 16 83 2 17 83 2 18 9 1 19 83 2 20 3 21 16 1 22 1 23 83 24 2 25 20 1 capacitor bank-69kv 1 7 26 27 1 28 1450 2 896 2 167 29 1 30 2 shunt reactor - 525V 4 22 1 capacitor bank-115kv 2 49 31 20 1 capacitor bank-69kv 2 7 32 40 2 capacitor bank-69kv 1 7 33 20 1 capacitor bank-34.5k 1 4 34 65 4 35 138 5 36 6 1 37 40 2 38 39 355 FERC FORM NO. 1 (ED. 12-96) 2 capacitor bank 230kv Page 427.7 2 94 40 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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 40 2 (i) capacitor bank-69kV Number of Units (j) Line Total Capacity No. (In MVa) (k) 1 2 29 2 3 4 83 2 5 83 2 6 83 2 40 2 9 7 capacitor bank-12kv 1 4 10 8 22 9 capacitor bank-69kV 2 capacitor bank-12kv 2 6 10 capacitor bank-69kV 2 14 11 83 2 12 40 2 13 20 1 14 2 15 16 17 83 2 1 18 83 2 19 1 20 83 2 21 83 2 22 9 1 23 5 3 24 20 1 25 269 3 40 2 355 2 28 83 2 2 3 30 564 3 125 3 32 34 2 33 1 34 1 35 2 36 9 1 37 83 2 39 40 2 40 1 capacitor bank-69kv 1 14 26 capacitor bank-69kv 1 7 27 43 29 53 31 capacitor bank-69kv capacitor bank-69kv 1 1 38 FERC FORM NO. 1 (ED. 12-96) Page 427.8 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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) 20 1 1 83 2 2 83 2 3 41 1 1 14 4 2 5 16 1 capacitor bank-69kv 1 10 6 40 2 capacitor bank-69kv 1 7 7 capacitor bank-21.6 4 10 8 capacitor bank 69kv 2 9 188 1 20 1 6 10 83 2 11 1 9 capacitor bank - 12V 2 capacitor bank-12kv 6 7 12 capacitor bank-69kV 1 7 13 41 1 14 83 2 15 16 83 2 17 11 1 18 40 2 19 2 3 20 188 1 21 41 1 22 41 1 23 200 2 20 1 83 2 83 2 capacitor bank-69kV 4 29 24 25 capacitor bank-12kv 4 14 26 27 28 83 29 2 1 30 20 1 31 10 1 564 3 capacitor bank-69kv 1 35 33 83 2 capacitor bank-12kV 4 10 34 41 1 4500 9 41 FERC FORM NO. 1 (ED. 12-96) 32 35 36 4 shunt reactor 525kV 3 571 37 capacitor bank 525kv 1 236 38 shunt reactor 230kV 2 212 39 40 1 Page 427.9 This Report Is: Name of Respondent 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/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) 376 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 capacitor bank-12kv 2 2 3 3 1 4 36 2 capacitor bank-69kv 2 1 12 2 40 376 12 5 1 6 83 2 7 3 1 8 16 2 capacitor bank-69kv 1 6 9 41 1 capacitor bank - 69V 1 14 10 166 2 shunt reactor 230kV 1 25 376 11 2 12 1 13 1 14 20 2 15 18 1 16 4 1 17 18 1 3 7 18 1 19 83 2 10 20 9 1 21 672 2 22 100 1 23 capacitor bank 69kv capacitor bank-12kv 1 4 24 20 1 150 1 capacitor bank 69kV 1 14 25 84 1 capacitor bank-69kv 1 25 26 20 1 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 1 (ED. 12-96) Page 427.10 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426 Line No.: 1 Column: b A-ATTENDED D-DISTRIBUTION T-TRANSMISSION Schedule Page: 426 Line No.: 1 Column: c VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 Column: d VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 Column: e VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 Column: k CAPACITY IS EXPRESSED IN MVAR Schedule Page: 426.2 Line No.: 25 Column: f 0.25 MVa 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 0.81 MVa Schedule Page: 426.3 0.1 MVa Schedule Page: 426.3 0.1 MVa Schedule Page: 426.4 Line No.: 8 Column: f 0.373 MVa Schedule Page: 426.4 Line No.: 23 Column: f Line No.: 37 Column: f Line No.: 40 Column: f Line No.: 11 Column: f Line No.: 29 Column: f Line No.: 34 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.: 6 Column: f Line No.: 7 Column: f 0.1 MVa Schedule Page: 426.6 0.1 MVa Schedule Page: 426.6 Line No.: 26 Column: f Line No.: 37 Column: f Line No.: 10 Column: f Line No.: 15 Column: f 0.1 MVa Schedule Page: 426.6 0.56 MVa Schedule Page: 426.7 0.56 MVa Schedule Page: 426.7 0.1 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.7 Line No.: 16 Column: f Line No.: 21 Column: f Line No.: 23 Column: f Line No.: 28 Column: f Line No.: 15 Column: f Line No.: 18 Column: f Line No.: 20 Column: f Line No.: 34 Column: f Line No.: 35 Column: f Line No.: 36 Column: f Line No.: 30 Column: f Line No.: 6 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 0.1 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 Line No.: 13 Column: f Line No.: 19 Column: f 0.5 MVa Schedule Page: 426.10 0.1 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 03/17/2016 2015/Q4 Name of Respondent This Report Is: 20160317-8000 FERC PDF (Unofficial) 03/17/2016 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/17/2016 Year/Period of Report 2015/Q4 End of 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 438 266,900,000 3 Share of estimated income taxes Pinnacle West Capital Corporation 236 14,830,659 4 Share of withholding and payroll taxes Pinnacle West Capital Corporation 236,241,408 246,325,601 Pinnacle West Capital Corporation 228.3 100,596,034 Pinnacle West Capital Corporation 228.3,925,926 138,576,761 Pinnacle West Capital Corporation 143,232,242 67,794,523 10 Shared services Pinnacle West Capital Corporation various 28,599,927 11 Compensation paid in stock Pinnacle West Capital Corporation various 22,223,843 21 Shared services Pinnacle West Capital Corporation various 13,253,865 22 Four Corners Capital Pinnacle West Capital Corporation 131 2,666,605 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 23 24 25 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Name of Respondent This Report is: (1) X An Original (2) 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) 03/17/2016 2015/Q4 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 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 20160317-8000 FERC PDF (Unofficial) 03/17/2016 Document Content(s) Form120151200007.PDF..................................................1-333