20170406-8017 FERC PDF (Unofficial) 03/31/2017 THIS FILING IS Item 1: X An Initial (Original) Submission OR Form 1 Approved OMB No.1902-0021 (Expires 12/31/2019) Resubmission No. ____ Form 1-F Approved OMB No.1902-0029 (Expires 12/31/2019) Form 3-Q Approved OMB No.1902-0205 (Expires 12/31/2019) 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) 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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/forms/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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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. “In connection with our regular examination of the financial statements of for the year ended on which we have reported separately under date of , we have also reviewed schedules 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/forms/form-1/form-1.pdf and http://www.ferc.gov/docs-filing/forms.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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 "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. 20170406-8017 FERC PDF (Unofficial) 03/31/2017 1/3-Q: REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER IDENTIFICATION 02 Year/Period of Report 2016/Q4 End of 01 Exact Legal Name of Respondent Arizona Public Service Company 03 Previous Name and Date of Change (if name changed during year) / / 04 Address of Principal Office at End of Period (Street, City, State, Zip Code) 400 North 5th Street, Phoenix, AZ 85004 05 Name of Contact Person Jeffrey B. Guldner 06 Title of Contact Person SVP Public Policy 07 Address of Contact Person (Street, City, State, Zip Code) 400 North 5th Street, Phoenix, AZ 85004 08 Telephone of Contact Person,Including 09 This Report Is Area Code (1) X An Original (602) 250-2952 (2) A Resubmission 10 Date of Report (Mo, Da, Yr) 03/31/2017 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 & CAO APS/PNW 03/31/2017 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 20170406-8017 03/31/2017 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) 03/31/2017 Year/Period of Report End of 2016/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 20170406-8017 03/31/2017 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) 03/31/2017 Year/Period of Report End of 2016/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, 2016, as filed with the Securities and Exchange Commission. FERC FORM NO. 1 (ED. 12-96) Page 102 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. 1 Title Name of Officer President & Chief Executive Officer (b) Donald E. Brandt Salary for Year (c) 1,315,103 Executive Vice President & Chief Operations Officer Mark A. Schiavoni 679,205 Executive Vice President and Advisor to the CEO of APS Randall K. Edington Executive Vice President and General Counsel David P. Falck 564,849 Executive Vice President and Chief Financial Officer James R. Hatfield 619,670 Executive Vice President and Chief Nuclear Officer Robert S. Bement 491,452 Senior Vice President, Transmission, Distribution & Cust Daniel T. Froetscher 364,530 Senior Vice President, Public Policy Jeffrey B. Guldner 399,763 Vice President, Controller and Chief Accounting Officer Denise R. Danner 334,930 Vice President, Communications John S. Hatfield 299,926 Vice President and Treasurer Lee R. Nickloy 298,925 Senior Vice President, Human Resources & Ethics Barbara M. Gomez 359,420 Vice President, Transmission and Distribution Operations Patrick Dinkel 294,002 Vice President, Resource Management Tammy D. McLeod 290,051 (a) 2 3 4 5 1,099,327 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 FERC FORM NO. 1 (ED. 12-96) Page 104 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 FOOTNOTE DATA Schedule Page: 104 Line No.: 1 Column: a Chairman of the Board, President and Chief Executive Officer 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.: 5 Column: a Mr. Edington served as Executive Vice President and Chief Nuclear Officer, PVNGS, APS until October 2016, at which time he became Executive Vice President and Advisor to the CEO of APS. 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.: 11 Column: a Executive Vice President and Chief Nuclear Officer, PVNGS, APS Mr. Bement served as Senior Vice President Site Operations of PVNGS of APS until June of 2016, at which time he became Executive Vice President, Nuclear of PVNGS of APS, which title he held until October of 2016 at which time he became Executive Vice President and Chief Nuclear Officer of PVNGS of APS. Schedule Page: 104 Line No.: 13 Column: a Senior Vice President, Transmission, Distribution & Customers Schedule Page: 104 Line No.: 17 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.: 21 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.: 23 Column: a Ms. Gomez served as Vice President of Human Resources of APS until December of 2016, at which time she became Senior Vice President, Human Resources and Ethics of APS. Schedule Page: 104 Line No.: 25 Column: a As of May 18, 2016, Mr. Dinkel retained his title but was no longer designated as a Section 16 Officer. Schedule Page: 104 Line No.: 27 Column: a As of May 18, 2016, Ms. McLeod retained her title but was no longer designated as a Section 16 Officer. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Denis A. Cortese Fountain Hills, Arizona 4 5 Richard P. Fox Scottsdale, Arizona 6 7 Michael L. Gallagher Phoenix, Arizona 8 9 Roy A. Herberger, Jr. Phoenix, Arizona 10 11 Dale E. Klein Austin, Texas 12 13 Humberto S. Lopez Tucson, Arizona 14 15 Kathryn L. Munro La Jolla, California 16 17 Bruce J. Nordstrom Flagstaff, Arizona 18 19 Paula J. Sims Chapel Hill, North Carolina 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 105 Line No.: 19 Column: a Ms. Sims was added to the APS Board in October of 2016. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) (1)03/31/2017 An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 ER16-1877 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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: 20170406-8017 FERC PDF (Unofficial) (1)03/31/2017 An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 20160516-5202 Document Date \ Filed Date Docket No. Description 05/16/2016 ER11-3638 See FootnoteFERC 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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: 20170406-8017 FERC PDF (Unofficial) (1)03/31/2017 An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/Q4 INFORMATION ON FORMULA RATES Formula Rate Variances 1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. 2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. 3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. 4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote. Line No. Page No(s). Schedule Column 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 FERC FORM NO. 1 (NEW. 12-08) Page 106b Line No Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) (1) 03/31/2017 X An Original Arizona Public Service Company (2) A Resubmission Date of Report 03/31/2017 Year/Period of Report 2016/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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 1. The town of Litchfield Park franchise was approved on March 8, 2016. The Sedona franchise was approved by voters on August 30, 2016 and went into effect on November 19, 2016 for another 25 years. 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. On April 29, 2016, APS sold a 50% interest in two existing APS transmission lines to SRP. The sale included the "Kyrene-Knox Segment" of the 230kV transmission lines, as well as associated facilities and land rights. The Arizona Corporation Commission (ACC) approved this sale under ACC Decision No. 74991. APS filed the final accounting entries for the transaction with FERC in March 2017. 4. None. 5. Palo Verde – Delaney 500kV line Reason for addition: This line is one section of a new 500kV path from Palo Verde to the northwest region of the Phoenix metropolitan area, and ultimately terminating at Pinnacle Peak substation. This project will increase the import capability to the Phoenix metropolitan area as well as increase the export/scheduling capability from the Palo Verde area. This project will also increase the system reliability by providing a new transmission source to help serve the areas in the western portions of the Phoenix Metropolitan area. Voltage: 500kV AC End points: Palo Verde 500kV switchyard & Delaney 500kV/69kV substation Construction start: October 20th, 2014 Line construction completed: January 23rd, 2016 Substation construction completed: May 6th, 2016 Delaney 500kV side of substation energization: May 20th, 2016 Miles constructed from Palo Verde – Delaney: 15 miles Arizona Corporation Commission Decision Information: CEC #128 was originally authorized in Decision No. 68063 and modified in Decision No. 75081 (both in Docket No. L-00000D-05-0128-00000) Delaney – Sun Valley 500kV line Reason for addition: This line is one section of a new 500kV path from Palo Verde to the northwest region of the Phoenix metropolitan area, and ultimately terminating at Pinnacle Peak substation. This project will increase the import capability to the Phoenix metropolitan area as well as increase the export/scheduling capability from the Palo Verde area. This project will also increase the system reliability by providing a new transmission source to help serve the areas in the western portions of the Phoenix Metropolitan area. FERC FORM NO. 1 (ED. 12-96) Page 109.1 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Voltage: 500kV AC End points: Delaney 500kV/69kV substation & Sun Valley 500kV/230kV substation Construction start: October 13th, 2014 Line construction completed: October 21st , 2015 Substation construction completed: February 12th, 2016 Sun Valley substation energization: May 20th, 2016 Miles constructed from Palo Verde – Delaney: 28 miles Arizona Corporation Commission Decision Information: CEC #128 was originally authorized in Decision No. 68063 and modified in Decision No. 75081 (both in Docket No. L-00000D-05-0128-00000) 6. Lines of Credit and Short-Term Borrowings APS maintains committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes. The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2016 and 2015 (dollars in thousands): December 31, 2016 Commitments under Credit Facilities $ Weighted-Average Commitment Fees $ 1,000,000 (135,500) Outstanding Commercial Paper Amount of Credit Facilities Available 1,000,000 December 31, 2015 $ 864,500 0.100% -$ 1,000,000 0.100% During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million. On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021. At December 31, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021. APS may increase the amount of each facility up to a maximum of $700 million, 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 $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2016, APS had $135.5 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. FERC FORM NO. 1 (ED. 12-96) Page 109.2 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Long-Term Debt All of APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2016 and 2015 (dollars in thousands): 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, 2016 and 2015 (dollars in thousands): APS Pollution control bonds: Variable Fixed Total pollution control bonds Other long-term Debt Unamortized discount Unamortized premium Total Long-Term Debt (a) (b) Maturity Dates (a) Interest Rates 2029 2024-2029 (b) 1.75%-4.70% 2018-2046 1.43%-8.75% December 31, 2016 $ $ 35,975 147,150 183,125 3,904,686 (11,816) 4,506 4,080,501 2015 $ $ 92,405 211,150 303,555 3,453,695 (10,374) 4,686 3,751,562 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 0.81% at December 31, 2016 and 0.01%-0.24% at December 31, 2015. The following table shows principal payments due on APS’s total long-term debt (dollars in thousands): Year 2017 APS $ — 2018 82,000 2019 600,000 2020 250,000 2021 — Thereafter Total 3,155,811 $ 4,087,811 Credit Facilities and Debt Issuances On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. 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 May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay FERC FORM NO. 1 (ED. 12-96) Page 109.3 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) commercial paper borrowings and replenish cash temporarily used to fund capital expenditures. On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E. On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A. On August 1, 2016, APS repaid at maturity APS's $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016. On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016. On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B. On December 6, 2016, APS redeemed at par and canceled all $17 million of the Coconino County Arizona Pollution Control Corporation Revenue Bonds (Arizona Public Service Company Project), Series 1998. Contractual Obligations The following table summarizes APS’s contractual requirements as of December 31, 2016 (dollars in millions): 20182019 2017 Long-term debt payments, including interest: (a) $ 187 $ 20202021 1,033 $ Thereafter 523 $ 5,248 Total $ 6,991 Short-term debt payments, including interest (b) 136 — — — 136 Fuel and purchased power commitments (c) 617 1,135 1,033 7,127 9,912 40 80 80 420 620 350 198 16 212 776 17 38 43 241 339 2 4 4 58 68 35 66 58 263 422 Renewable energy credits (d) Purchase obligations (e) Coal reclamation Nuclear decommissioning funding requirements Operating lease payments Total contractual commitments FERC FORM NO. 1 (ED. 12-96) $ 1,384 $ 2,554 Page 109.4 $ 1,757 $ 13,569 $ 19,264 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) (a) The long-term debt matures at various dates through 2046 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2016. Lines of credit and short-term borrowings. Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. Contracts to purchase renewable energy credits in compliance with the RES. These contractual obligations include commitments for capital expenditures and other obligations. (b) (c) (d) (e) Estimated minimum required pension contributions are zero for 2017, 2018 and 2019. 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 commodity contract collateral obligations and other transactions. As of December 31, 2016, standby letters of credit totaled $35 million and will expire in 2017. As of December 31, 2016, surety bonds expiring through 2019 totaled $53 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. 8. The union and non-union annualized wage scale increases during 2016 through December 31, 2016, were as follows: a. b. c. d. Total Type of Cost Union Negotiated Non-Union Base Salary Increases Special Increases Promotions FERC FORM NO. 1 (ED. 12-96) Number of Increases 1,442 3,921 481 890 6,734 Page 109.5 Annualized Costs $ 2,636,584 11,516,699 1,095,635 4,604,775 $ 19,853,693 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) COMMENTS: a. There were general wage increases for both the IBEW (averaging 2.25%) and the USPA (averaging approximately 2.8%) 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 doubtful whether the 115th 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 written, enacted and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed GHG emissions; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“CO2”) equivalent emitted. In addition to federal legislative initiatives, state-specific initiatives may also impact our business. While Arizona has no pending legislation and no proposed agency rule regulating GHGs in Arizona, the California legislature enacted AB 32 and SB 1368 in 2006 to address GHG emissions. In October 2011, the California Air Resources Board approved final regulations that established a state-wide cap on GHG emissions beginning on January 1, 2013 and established a GHG allowance trading program under that cap. The first phase of the program, which applies to, among other entities, importers of electricity, commenced on January 1, 2013. Under the program, entities selling electricity into California, including APS, must hold carbon allowances to cover GHG emissions associated with electricity sales into California from outside the state. APS is authorized to recover the cost of these carbon allowances through the PSA. Regulatory Initiatives. In 2009, EPA determined that GHG emissions endanger public health and welfare. 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). FERC FORM NO. 1 (ED. 12-96) Page 109.6 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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, this timing will be impacted by the court-imposed stay described below. Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ is continuing to assess alternatives while completing outreach and soliciting feedback from stakeholders. In addition to these ongoing 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 the 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 FERC FORM NO. 1 (ED. 12-96) Page 109.7 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 or potential plant closures, as alternatives to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains ongoing, 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 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 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 FERC FORM NO. 1 (ED. 12-96) Page 109.8 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) these plants. Cholla. APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of selective catalytic reduction ("SCR") controls with a cost to APS of approximately $100 million is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a Federal Implementation Plan ("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. Pending certain regulatory approvals, APS would permanently close Cholla Unit 2 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 a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program. EPA signed the final rule approving the Agency's proposal on January 13, 2017. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review. Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required 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. 4CA purchased the El Paso interest on July 6, 2016. NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC provided notice of its intent to exercise the option. 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. On July 28, 2014, EPA issued a final Navajo Plant BART rule. 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 review process. 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. 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 FERC FORM NO. 1 (ED. 12-96) Page 109.9 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) is approximately $1 million, the majority of which has already been incurred. Litigation concerning the rules, including supplemental analyses EPA has prepared in support of the MATS regulation, is ongoing. These proceedings do not materially impact APS. Regardless of the results from further judicial or administrative proceedings concerning 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 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. 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. On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds. Because EPA has yet to undertake rulemaking proceedings to implement the CCR provisions of the WIIN Act, and Arizona has yet to determine whether it will develop a state-specific permitting program, it is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR. 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. APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. 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, the majority of which has already been incurred. Additionally, the CCR rule requires ongoing groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time. Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next three years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion. Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase FERC FORM NO. 1 (ED. 12-96) Page 109.10 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings. 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 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. 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 ("RI/FS"). The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by June 2017. 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 former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination FERC FORM NO. 1 (ED. 12-96) Page 109.11 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. 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. Federal Agency Environmental Lawsuit Related to Four Corners On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners. 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. FERC FORM NO. 1 (ED. 12-96) Page 109.12 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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. The Four Corners region, in which Four Corners is located, has historically experienced drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. However, during the past 12 months the region has received snowfall and precipitation sufficient to recover the Navajo Reservoir to an optimum operating level, reducing the probability of shortage in future years. Although the watershed and reservoirs are in a good condition at this time, APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future drought conditions that could have an impact on operations of its plants. 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, FERC FORM NO. 1 (ED. 12-96) Page 109.13 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 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 the DOE in the Court of Federal Claims. The lawsuit sought to recover damages incurred due to DOE’s breach of the 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 reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019. APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on October 31, 2016, and approved on February 1, 2017, in the amount of $11.3 million (APS’s share is $3.3 million). Payment for the claim is expected in the second quarter of 2017. 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. On March 2, 2016, the United States Court of Appeals for the Ninth Circuit unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016. FERC FORM NO. 1 (ED. 12-96) Page 109.14 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 in the amount of $0.8 million 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. On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million. APS's share of this settlement payment, together with its share of the partial payment described above, is approximately $0.8 million. Peabody Bankruptcy On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri. Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona. APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement. On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleged that the Buyers breached the Agreement. On January 27, 2017, the bankruptcy court approved a settlement between the parties, and on February 6, 2017 the parties executed an amendment to the Coal Supply Agreement that allows for continuation of the agreement with modified terms and conditions acceptable to the parties. II. REGULATORY MATTERS Retail Rate Case Filings with the Arizona Corporation Commission On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%). FERC FORM NO. 1 (ED. 12-96) Page 109.15 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) The principal provisions of the application are: • a test year ended December 31, 2015, adjusted as described below; • an original cost rate base of $6.8 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2015; • the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 44.20 % 5.13 % Common stock equity 55.80 % 10.50 % Weighted-average cost of capital 8.13 % • a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law; • a base rate for fuel and purchased power costs of $0.029882 per kWh based on estimated 2017 prices (a decrease from the current base fuel rate of $0.03207 per kWh); • authorization to defer for potential future recovery its share of the construction costs associated with installing selective catalytic reduction equipment at Four Corners (estimated at approximately $400 million in direct costs). APS proposes that the rates established in this rate case be increased through a step mechanism beginning in 2019 to reflect these deferred costs; • authorization to defer for potential future recovery in the Company’s next general rate case the construction costs APS incurs for its Ocotillo power plant modernization project, once the project reaches commercial operation. APS estimates the direct construction costs at approximately $500 million and that the new facility will be fully in service by early 2019; • authorization to defer until the Company’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated; • updates and modifications to four of APS’s adjustor mechanisms - the PSA, the LFCR, the TCA and the Environmental Improvement Surcharge (“EIS”); • a number of proposed rate design changes for residential customers, including: 1 2 3 4 change the on-peak time of use period from 12 p.m. - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays; reduce the difference in the on- and off-peak energy price and lower all energy charges; offer four rate plan options, three of which have demand charges and a fourth that is available to non-partial requirements customers using less than 600 kWh on average per month; and modify the current net metering tariff to provide for a credit at the retail rate for the portion of generation by rooftop solar customers that offsets their own load, and for a credit for excess energy delivered to the grid at an export rate. FERC FORM NO. 1 (ED. 12-96) Page 109.16 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) • proposed rate design changes for commercial customers, including an aggregation rider that allows certain large customers to qualify for a reduced rate, an extra-high load factor rate schedule for certain customers, and an economic development rate offering for new loads meeting certain criteria. The Company requested that the increase become effective July 1, 2017. On July 22, 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months. The ACC staff and intervenors began filing their direct testimony in late December 2016. On January 12, 2017, APS began settlement discussions with all parties. On January 13, 2017, the ALJ hearing the case before the ACC issued a procedural order delaying hearings on the case from the originally scheduled March 22, 2017 to April 24, 2017, to allow parties to participate in settlement discussions and prepare testimony on the distributed generation rate design issues addressed in the value and cost of DG decision. According to the procedural order, settlement discussions are to be completed and, if applicable, any related settlement must be filed by March 17, 2017. The procedural order also extended the rate case completion date as calculated by Commission rule for an additional 33 days. On March 1, 2017, the Staff of the ACC filed with the ACC a settlement term sheet with respect to APS’s pending general retail rate case. The settlement term sheet was agreed to by a majority of the formal stakeholders in the rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations. The settlement term sheet must be converted to a definitive settlement agreement and signed by the supporting parties. It will then be submitted to an administrative law judge, whose decision regarding whether the settlement should be approved will be reviewed by the ACC. We currently anticipate hearings on the proposed settlement will begin on April 24, 2017. Through a separate agreement, APS, industry representatives, and solar advocates commit to stand by the settlement agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. APS cannot predict whether a definitive settlement agreement based on the settlement term sheet will ultimately be approved by the ACC. 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 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; FERC FORM NO. 1 (ED. 12-96) Page 109.17 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) • 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 settlement agreement for the 2009 retail rate case (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. 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 FERC FORM NO. 1 (ED. 12-96) Page 109.18 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC. 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. On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. The ACC has not yet ruled on the Company’s 2017 RES Implementation Plan. In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically. The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the EPA. The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. APS cannot predict the outcome of this proceeding. Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. In March 2014, the ACC 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. On April 1, 2016, APS filed an FERC FORM NO. 1 (ED. 12-96) Page 109.19 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program. On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on the Company’s 2017 DSM Plan. 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. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding. PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following: • APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate; • An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC; • The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point); • The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and FERC FORM NO. 1 (ED. 12-96) Page 109.20 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) • 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 2016 and 2015 (dollars in thousands): Beginning balance Deferred fuel and purchased power costs - current period Amounts charged to customers Ending balance Year ended December 31, 2015 2016 6,926 $ (9,688) $ 60,303 (14,997) (1,617) (38,150) $ 12,465 $ (9,688) The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers ("Retail Transmission Charges"). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. 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. Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 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, 2016. 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 to make changes to their protocols in the FERC FORM NO. 1 (ED. 12-96) Page 109.21 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) future. As a result, APS is evaluating how its formula rate protocols compare with more recently approved formula rate protocols and anticipates that it will make a filing to update its formula rate protocols in the first quarter of 2017. 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 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. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two month delay in implementation did not have an adverse effect on APS. APS filed its 2017 LFCR adjustment on January 13, 2017. APS requested an adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective the first billing cycle of March 2017. Net Metering In 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 was held in April 2016. On October 7, 2016, the ALJ issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize inputs from historical wholesale solar power costs and eventually an avoided cost methodology. As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a resource comparison proxy methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed. The price established by this resource comparison proxy method will be updated annually (between rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by that utility for exported distributed energy. In addition, the ACC made the following determinations: • Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to the date new rates are effective based on APS' pending rate case will be grandfathered for a period of 20 years from the date of interconnection; FERC FORM NO. 1 (ED. 12-96) Page 109.22 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) • Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and • Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years. This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change as are all ACC policies. The determination of the initial export energy price to be paid by APS will be made in APS’s currently pending rate case, which is scheduled for hearing by the ACC in April 2017. APS cannot predict the outcome of this determination. The ACC’s decision did not make any policy determinations as to any specific costs to be charged to DG solar system customers for their use of the grid. The determination of any such costs will be made in APS's future rate cases. On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserts that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC's request for rehearing is required for TASC to challenge this decision in court. To date, the ACC has taken no action on the rehearing request. The ACC's decision is expected to remain in effect during any legal challenge. 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 on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor. System Benefits Charge The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016. Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge. The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense. Subpoena from Arizona Corporation Commissioner Robert Burns On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) FERC FORM NO. 1 (ED. 12-96) Page 109.23 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer. On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed. On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff. As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas. Commissioner Burns has also scheduled a workshop in this matter for March 17, 2017. APS and Pinnacle West 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 to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $64 million as of December 31, 2016 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 suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. 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. 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. FERC FORM NO. 1 (ED. 12-96) Page 109.24 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates. APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016. On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter. 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. On January 13, 2017, EPA approved a final rule incorporating APS's compromise proposal. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review. 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 is seeking recovery of the unit’s decommissioning and other retirement-related costs over the previously estimated remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($116 million as of December 31, 2016), 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. Navajo Plant On February 13, 2017, the co-owners of the Navajo Plant voted not to pursue continued operation of the plant beyond December 2019, the expiration of the current lease term, and to pursue a new lease or lease extension with the Navajo Nation that would allow decommissioning activities to begin after December 2019 instead of later this year. Various stakeholders including regulators, tribal representatives and others interested in the continued operation of the plant intend to meet to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. We cannot predict whether any alternate solutions will be found that would be acceptable to all of the stakeholders and feasible to implement. APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($108 million as of December 31, 2016) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material. We cannot predict whether APS would obtain such recovery. On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding. FERC FORM NO. 1 (ED. 12-96) Page 109.25 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 10. None. 11. (RESERVED) 12. N/A 13. Board and Officer Elections, Retirements, Resignations and Changes During 2015: Directors – On October 20, 2016, Ms. Paula J. Sims was elected as a Director to the APS Board of Directors Officers – On February 17, 2016, Maria Lacal was promoted to Senior Vice President, Regulatory & Oversight, Palo Verde Nuclear Generating Station (“PVNGS”). On June 22, 2016, the following appointments were made: • • • • • 14. Robert S. Bement as Executive Vice President, Nuclear, PVNGS of APS, and effective October 31, 2016, Executive Vice President and Chief Nuclear Officer, PVNGS, of APS Randall K. Edington as Executive Vice President and Advisor to the CEO of APS, effective October 31, 2016; John J. Cadogan as Senior Vice President, Site Operations, PVNGS, of APS; Michael E. McLaughlin as Vice President, Operations Support, PVNGS, of APS; Charles Kharrl as Vice President, Site Operations/General Plant Manager, PVNGS, of APS N/A FERC FORM NO. 1 (ED. 12-96) Page 109.26 Name of RespondentFERC PDF (Unofficial) This Report Is: 20170406-8017 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report 03/31/2017 End of 2016/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) 18,107,367,045 878,382,780 18,985,749,825 6,723,503,730 12,262,246,095 111,114,186 1,365 266,205,234 0 0 147,202,304 230,118,481 12,492,364,576 0 0 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 6,088,343 1,585,306 0 0 6,088,897 1,562,163 0 0 0 0 0 0 0 956,182,908 0 6,704,345 0 967,390,290 0 0 0 0 0 918,129,534 0 15,959,853 0 938,616,121 0 5,883,580 0 2,853,225 103,573 0 200,749,231 48,412,790 3,037,062 0 13,448,933 20,069,909 0 0 252,069,374 0 0 0 8,538,022 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 Name of RespondentFERC PDF (Unofficial) This Report Is: 20170406-8017 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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) 0 707,530 0 0 45,972,686 0 0 0 107,949,073 37,251,489 54,798,629 6,704,345 0 0 789,066,637 29,029,286 0 0 1,387,590,018 5,983,723 0 0 207,928 0 124,596,849 0 0 18,579,262 826,574,489 0 2,392,561,555 16,641,383,058 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 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 Name of RespondentFERC PDF (Unofficial) This Report is: 20170406-8017 03/31/2017 (1) x An Original Arizona Public Service Company (2) A Resubmission Date of Report (mo, da, yr) Year/Period of Report 03/31/2017 end of 2016/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 2,440,807,686 18,400,365 0 0 37,511,652 2,331,244,870 0 0 0 -25,423,581 4,905,680,056 178,162,368 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 4,679,254,873 183,125,000 0 0 3,904,686,078 4,506,087 11,816,370 4,080,500,795 303,555,000 0 0 3,453,695,075 4,686,330 10,373,885 3,751,562,520 178,775,422 0 64,451 539,614,017 0 219,756 53,941,700 0 615,936,293 1,388,551,639 186,209,060 0 515,308 505,338,198 0 294,496 92,213,397 1,613,757 443,576,528 1,229,760,744 135,500,000 259,171,351 0 72,901,602 82,519,751 141,954,872 53,791,554 0 0 0 291,567,656 0 84,985,708 73,072,613 154,011,438 56,807,168 0 0 Name of RespondentFERC PDF (Unofficial) This Report is: 20170406-8017 03/31/2017 (1) x An Original Arizona Public Service Company (2) A Resubmission Date of Report (mo, da, yr) 03/31/2017 Year/Period of Report end of 2016/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 -10,569 230,469,912 7,433,638 102,572,995 53,941,700 1,550,885 0 1,033,914,291 0 6,131 169,328,681 7,103,830 204,130,617 92,213,397 3,268,559 1,613,757 950,455,247 88,672,074 210,162,291 0 268,874,788 814,110,646 285,079 0 3,230,569,940 620,061,459 5,232,736,277 16,641,383,058 115,609,383 187,080,422 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 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. Current 3 Months Prior 3 Months Total Total Line Ended Ended Prior Year to Current Year to No. Quarterly Only Quarterly Only Date Balance for Date Balance for (Ref.) No 4th Quarter No 4th Quarter Quarter/Year Quarter/Year Page No. Title of Account (e) (f) (d) (a) (b) (c) 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 300-301 3,516,336,004 3,519,645,174 4 Operation Expenses (401) 320-323 1,741,835,152 1,768,447,876 5 Maintenance Expenses (402) 320-323 243,851,753 231,357,405 6 Depreciation Expense (403) 336-337 388,363,026 385,402,361 3 Operating Expenses 7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337 4,380,701 70,077 8 Amort. & Depl. of Utility Plant (404-405) 336-337 77,215,884 70,747,118 9 Amort. of Utility Plant Acq. Adj. (406) 336-337 10,873,443 10,873,443 5,286 55,045 12 Regulatory Debits (407.3) 6,688,721 6,688,721 13 (Less) Regulatory Credits (407.4) 5,867,920 -293,623 10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 11 Amort. of Conversion Expenses (407) 14 Taxes Other Than Income Taxes (408.1) 262-263 191,154,808 197,728,627 15 Income Taxes - Federal (409.1) 262-263 4,925,542 21,013,707 16 262-263 5,218,902 8,798,827 - Other (409.1) 17 Provision for Deferred Income Taxes (410.1) 234, 272-277 718,918,056 838,754,779 18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 470,172,298 608,242,675 19 Investment Tax Credit Adj. - Net (411.4) 266 20 (Less) Gains from Disp. of Utility Plant (411.6) 4,573,793 21 Losses from Disp. of Utility Plant (411.7) 22 (Less) Gains from Disposition of Allowances (411.8) 31,586 500,880 23 Losses from Disposition of Allowances (411.9) 26,794 447,680 25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 2,917,386,264 2,927,361,941 26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 598,949,740 592,283,233 24 Accretion Expense (411.10) FERC FORM NO. 1/3-Q (REV. 02-04) Page 114 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) (h) (g) GAS UTILITY Current Year to Date Previous Year to Date (in dollars) (in dollars) (i) (j) OTHER UTILITY Current Year to Date Previous Year to Date (in dollars) (in dollars) (k) (l) Line No. 1 3,516,336,004 3,519,645,174 2 3 1,741,835,152 1,768,447,876 4 243,851,753 231,357,405 5 388,363,026 385,402,361 6 4,380,701 70,077 7 77,215,884 70,747,118 8 10,873,443 10,873,443 9 5,286 55,045 10 11 6,688,721 6,688,721 12 5,867,920 -293,623 13 191,154,808 197,728,627 14 4,925,542 21,013,707 15 5,218,902 8,798,827 16 718,918,056 838,754,779 17 470,172,298 608,242,675 18 19 20 4,573,793 21 31,586 500,880 22 26,794 447,680 23 24 2,917,386,264 2,927,361,941 25 598,949,740 592,283,233 26 FERC FORM NO. 1 (ED. 12-96) Page 115 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/Q4 End of STATEMENT OF INCOME FOR THE YEAR (continued) Line No. TOTAL (Ref.) Page No. (b) 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 (ED. 12-96) Current Year (c) Previous Year (d) 598,949,740 592,283,233 2,593,422 2,268,268 1,500 24,125 5,805 1,949,265 1,637,402 1,500 26,228 4,731 261,158 42,140,186 84,594,492 5,744,862 133,049,032 163,181 35,214,865 100,695,289 715,765 137,080,966 1,245,727 2,219,096 2,099,141 2,277,953 3,134,998 93,051,238 99,531,104 -274,394 3,147,962 110,346,098 117,716,715 285,200 -4,739,586 -719,179 581,486 1,520,860 308,601 -5,702,824 -985,426 722,200 1,718,654 7,112,486 -13,225,425 46,743,353 6,617,182 -13,993,285 33,357,536 189,828,017 3,415,015 1,567,557 180,243 43,304 179,563,539 3,574,447 1,441,956 180,243 43,303 8,445,697 19,480,590 183,552,149 462,140,944 7,193,611 16,183,284 175,366,723 450,274,046 462,140,944 450,274,046 119 262-263 262-263 262-263 234, 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. Current Quarter/Year Year to Date Balance (c) UNAPPROPRIATED RETAINED EARNINGS (Account 216) Balance-Beginning of Period Changes Adjustments to Retained Earnings (Account 439) Stock Compensation cumulative effect adjustment 146 8,803,672 TOTAL Credits to Retained Earnings (Acct. 439) Federal Income Taxes State Income Taxes 190 190 8,803,672 -2,913,624 -479,311 2,148,493,189 TOTAL Debits to Retained Earnings (Acct. 439) Balance Transferred from Income (Account 433 less Account 418.1) Appropriations of Retained Earnings (Acct. 436) Previous Quarter/Year Year to Date Balance (d) 1,968,719,143 -3,392,935 462,140,944 450,274,046 -284,800,000 ( 270,500,000) -284,800,000 ( 270,500,000) 2,331,244,870 2,148,493,189 TOTAL Appropriations of Retained Earnings (Acct. 436) Dividends Declared-Preferred Stock (Account 437) TOTAL Dividends Declared-Preferred Stock (Acct. 437) Dividends Declared-Common Stock (Account 438) 234 TOTAL Dividends Declared-Common Stock (Acct. 438) Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings Balance - End of Period (Total 1,9,15,16,22,29,36,37) APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 FERC FORM NO. 1/3-Q (REV. 02-04) Page 118 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 (c) 2,331,244,870 Previous Quarter/Year Year to Date Balance (d) 2,148,493,189 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 FOOTNOTE DATA Schedule Page: 118 Line No.: 4 Column: c On February 9, 2017, Arizona Public Service Company filed with the Federal Energy Regulatory Commission a request for approval to use Account 439, Adjustments to Retained Earnings, in order to record a cumulative-effect adjustment to retained earnings required by the adoption of Accounting Standard Update 2016-09. On March 7, 2017, APS received a request from the Commission for additional information. On March 22, 2017 APS provided responses to the request for additional information. Schedule Page: 118 Line No.: 10 Column: c Income taxes related to the adoption of ASU 2016-09. Schedule Page: 118 Line No.: 11 Column: c Income taxes related to the adoption of ASU 2016-09. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 462,140,944 450,274,046 4 Depreciation and Depletion 392,743,727 385,472,438 5 Amortization of UTL PLT; ACQ; ADJ; Prop Loss; Reg Study; Nuclear Fuel 169,846,214 165,899,295 3 Noncash Charges (Credits) to Income: 6 7 Deferred Fuel and Purchased Power -22,152,543 16,613,022 8 Deferred Income Taxes (Net) 217,612,029 225,814,123 9 Investment Tax Credit Adjustment (Net) 23,081,869 8,473,212 10 Net (Increase) Decrease in Receivables -13,310,332 -16,748,117 -267,615 -21,427,295 11 Net (Increase) Decrease in Inventory 12 Net (Increase) Decrease in Allowances Inventory -1,186,675 -2,517,423 13 Net Increase (Decrease) in Payables and Accrued Expenses -83,127,969 -46,378,798 14 Net (Increase) Decrease in Other Regulatory Assets -18,780,278 -163,062,404 15 Net Increase (Decrease) in Other Regulatory Liabilities 16,585,435 -27,989,767 16 (Less) Allowance for Other Funds Used During Construction 42,140,186 35,214,865 17 (Less) Undistributed Earnings from Subsidiary Companies 18 Other (provide details in footnote): 19 Other Current Assets -2,590,342 28,545,473 20 Other Current Liabilities 46,996,386 24,087,552 21 Other Long Term Assets/Liabilities Net -158,247,356 59,769,064 987,203,308 1,051,609,556 -1,192,481,662 -1,024,915,891 -86,603,552 -83,672,189 19,480,590 16,183,284 60,782,000 46,546,059 -1,237,783,804 -1,078,225,305 633,410,106 478,813,436 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) -635,691,074 49 Net (Increase) Decrease in Receivables -496,062,379 3,514,388 50 Net (Increase ) Decrease in Inventory 51 Net (Increase) Decrease in Allowances Held for Speculation 52 Net Increase (Decrease) in Payables and Accrued Expenses 31,075,486 36,535,000 53 Other (provide details in footnote): 54 Investment in coal mine reclamation trust -13,544,694 55 Investments and Other Assets -320,127 -1,093,573 -1,219,339,719 -1,060,032,821 693,150,500 842,414,500 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 Equity Infusion from Pinnacle West 42,000,000 66 Net Increase in Short-Term Debt (c) 135,500,000 67 Other (provide details in footnote): 68 69 70 Cash Provided by Outside Sources (Total 61 thru 69) 870,650,500 842,414,500 -370,430,000 -402,150,000 71 72 Payments for Retirement of: 73 Long-term Debt (b) 74 Preferred Stock 75 Common Stock 76 Other (provide details in footnote): 77 78 Net Decrease in Short-Term Debt (c) -147,400,000 79 80 Dividends on Preferred Stock 81 Dividends on Common Stock -281,300,000 -266,900,000 218,920,500 25,964,500 -13,215,911 17,541,235 22,056,289 4,515,054 8,840,378 22,056,289 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 Column: b Prepaids Cummulative Adjustment - Stock Comp Adjustment Notes Receivable Other Risk Management $ $ Schedule Page: 120 Line No.: 19 (13,483,560) (3,392,935) (4) 468,797 13,817,360 (2,590,342) Column: c Risk Management Notes Receivable Prepaids $ 27,268,231 924,988 352,254 28,545,473 $ Schedule Page: 120 Line No.: 20 Column: b Ocotillo Modernization Project Four Corners Take or Pay Red Rock Accruals Customer Deposits SCE Right of Way Employee Benefits Exchange Palo Verde Sale Leaseback Stock Comp Adjustment Tolling Agreements Interest Accrued Other Payroll Accrual Accrued Taxes SCE Transmission Termination Agreement $ $ 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 FERC FORM NO. 1 (ED. 12-87) 47,444,127 16,942,062 11,838,795 9,447,138 8,618,272 2,708,135 848,495 (6,191) (54,802) (2,329,346) (3,015,614) (6,320,861) (9,067,257) (12,056,567) (18,000,000) 46,996,386 Column: c $ Page 450.1 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) Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Employee Benefits PVVIE Capital Lease $ Schedule Page: 120 Line No.: 21 Column: b Pension and other benefits Decommissioning Trust Utility Plant (Removal Costs) Customer advances for construction Postretirement assets Other Long-Term Assets/Liabilities Net Margin and collateral accounts - assets Margin and collateral accounts - liabilities Schedule Page: 120 Line No.: 21 $ (44,502,000) (42,108,862) (41,569,427) (26,937,309) (2,042,590) (19,495,619) 673,450 17,735,000 $ (158,247,356) Column: c Post-Employment Benefits 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 $ $ Schedule Page: 120 Line No.: 55 Line No.: 55 Grant Street Land Purchase FERC FORM NO. 1 (ED. 12-87) 114,608,409 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 Column: b Post-Employment Benefits Other Schedule Page: 120 (6,514,419) (14,393,170) 24,087,552 $ $ (510,800) 190,673 (320,127) $ (624,834) Column: c Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent Arizona Public Service Company This Report is: (1) X An Original (2) A Resubmission FOOTNOTE DATA Post-Employment Benefits Other $ FERC FORM NO. 1 (ED. 12-87) Page 450.3 (480,267) 11,528 (1,093,573) Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) (1) 03/31/2017 X An Original Arizona Public Service Company (2) A Resubmission Date of Report 03/31/2017 Year/Period of Report End of 2016/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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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 and decommissioning 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 long term debt and asset retirement obligations, 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’s notes to financial statements have been combined with Pinnacle West Capital Corporation’s financial statements and are prepared with generally accepted accounting principles, accordingly certain footnotes are not reflective of APS’s financial statements contained herein. 2. Summary of Significant Accounting Policies Nature of Operations APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. Accounting Records and Use of Estimates Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (‘GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. FERC FORM NO. 1 (ED. 12-88) Page 123.1 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Regulatory Accounting APS is regulated by the Arizona Corporation Commission (“ACC”) and the Federal Energy Regulatory Commission (“FERC”). 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 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. FERC FORM NO. 1 (ED. 12-88) Page 123.2 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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, 2016 were as follows: • • • • Fossil plant — 19 years; Nuclear plant — 27 years; Other generation — 26 years; Transmission — 39 years; FERC FORM NO. 1 (ED. 12-88) Page 123.3 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) • • Distribution — 33 years; and General plant — 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 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 2014 through 2016, the depreciation rates ranged from a low of 0.30% to a high of 14.12%. The weighted-average depreciation rate was 2.66% in 2016, 2.74% in 2015, and 2.77% in 2014. 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 7.17% for 2016, 8.02% for 2015, and 8.47% for 2014. 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 evidence indicates that the weighted-average cost (even if in excess of market) will be recovered. FERC FORM NO. 1 (ED. 12-88) Page 123.4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. FERC FORM NO. 1 (ED. 12-88) Page 123.5 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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 an other 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 FERC FORM NO. 1 (ED. 12-88) Page 123.6 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. The following table summarizes supplemental APS cash flow information for each of the last two years (dollars in thousands): Year ended December 31, 2016 2015 Cash paid during the period for: Income taxes, net of refunds Interest, net of amounts capitalized Significant non-cash investing and financing activities: Accrued capital expenditures Dividends declared but not paid $ 26,864 181,809 $ 14,831 167,670 $ 114,874 72,900 $ 83,798 69,400 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 2016, FERC FORM NO. 1 (ED. 12-88) Page 123.7 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) and $58 million in 2015. Estimated amortization expense on existing intangible assets over the next five years is $41 million in 2017, $23 million in 2018, $12 million in 2019, $4 million in 2020, and $1 million in 2021. At December 31, 2016, the weighted-average remaining amortization period for intangible assets was 6 years. Investments Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 17 for more information on these investments. Preferred Stock At December 31, 2016, 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 24, 2017, 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 31, 2017. The accompanying statements contain all adjustments and disclosures necessary for fair presentation. 3. New Accounting Standards ASU 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting In March 2016, new stock compensation accounting guidance was issued intended to simplify the accounting for employee share-based payments. The new guidance impacts several aspects of the accounting for share-based payments including: modifies the tax withholding threshold that triggers liability classification of an award, requires all excess income tax benefits and deficiencies arising from share-based payments to be recognized in earnings in the period they occur, simplifies the accounting for forfeitures, and clarifies certain cash flow presentation matters. Certain aspects of the standard must be adopted using a prospective approach and other aspects must be adopted using a modified retrospective approach. During the fourth quarter of 2016, we elected to early adopt this standard, and accordingly have applied the guidance effective as of January 1, 2016. Prior to adoption of the new standard, our stock compensation awards were FERC FORM NO. 1 (ED. 12-88) Page 123.8 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) generally classified as liability awards and accounted for at fair value until settled because employees could withhold at more than the minimum statutory tax withholding rate. In accordance with the new guidance, certain of these stock compensation awards are now classified as equity awards and accounted for at grant date fair value. As a result of adopting the new standard, Pinnacle West recorded a cumulative effect adjustment to retained earnings of $6 million. The other provisions of the standard did not have a material impact on our comparative financial statements. See Note 14 for additional details of the adoption impacts. ASU 2015-07, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) In May 2015, new accounting guidance was issued that removes the requirement to categorize certain investments valued using net asset value, as a practical expedient, within the fair value hierarchy. We retrospectively adopted this guidance during the first quarter of 2016. The adoption of this guidance modifies our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results. See Note 8 and Note 13. ASU 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard 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. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard 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 plan on adopting this standard on January 1, 2018, and are currently evaluating the transition method and the effect on our financial statements. As part of our evaluation we continue to actively monitor certain industry issues being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group. Conclusions reached by these groups may impact our application of the standard, specifically in regards to the treatment of contributions in aid of construction. FERC FORM NO. 1 (ED. 12-88) Page 123.9 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new 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 standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements. ASU 2016-02, Leases In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including FERC FORM NO. 1 (ED. 12-88) Page 123.10 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. We are evaluating the impacts of adopting this new standard, and the impacts it may have on our financial statements. 4. Regulatory Matters Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%). The principal provisions of the application are: • a test year ended December 31, 2015, adjusted as described below; • an original cost rate base of $6.8 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2015; • the following proposed capital structure and costs of capital: Capital Structure Cost of Capital 44.20 % 5.13 % Long-term debt Common stock equity 55.80 % Weighted-average cost of capital 10.50 % 8.13 % • a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law; • a base rate for fuel and purchased power costs of $0.029882 per kWh based on estimated 2017 prices (a decrease from the current base fuel rate of $0.03207 per kWh); • authorization to defer for potential future recovery its share of the construction costs associated with installing selective catalytic reduction equipment at Four Corners (estimated at approximately $400 million in direct costs). APS proposes that the rates established in this rate case be increased through a step FERC FORM NO. 1 (ED. 12-88) Page 123.11 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) mechanism beginning in 2019 to reflect these deferred costs; • authorization to defer for potential future recovery in the Company’s next general rate case the construction costs APS incurs for its Ocotillo power plant modernization project, once the project reaches commercial operation. APS estimates the direct construction costs at approximately $500 million and that the new facility will be fully in service by early 2019; • authorization to defer until the Company’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated; • updates and modifications to four of APS’s adjustor mechanisms - the PSA, the LFCR, the TCA and the Environmental Improvement Surcharge (“EIS”); • a number of proposed rate design changes for residential customers, including: 1 change the on-peak time of use period from 12 p.m. - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays; 2 reduce the difference in the on- and off-peak energy price and lower all energy charges; 3 offer four rate plan options, three of which have demand charges and a fourth that is available to non-partial requirements customers using less than 600 kWh on average per month; and 4 modify the current net metering tariff to provide for a credit at the retail rate for the portion of generation by rooftop solar customers that offsets their own load, and for a credit for excess energy delivered to the grid at an export rate. • proposed rate design changes for commercial customers, including an aggregation rider that allows certain large customers to qualify for a reduced rate, an extra-high load factor rate schedule for certain customers, and an economic development rate offering for new loads meeting certain criteria. The Company requested that the increase become effective July 1, 2017. On July 22, 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months. The ACC staff and intervenors began filing their direct testimony in late December 2016. On January 12, 2017, APS began settlement discussions with all parties. On January 13, 2017, the ALJ hearing the case before the ACC issued a procedural order delaying hearings on the case from the originally scheduled March 22, 2017 to April 24, 2017, to allow parties to participate in settlement discussions and prepare testimony on the distributed generation rate design issues addressed in the value and cost of DG decision. According to the procedural order, settlement discussions are to be completed and, if applicable, any related settlement must be filed by March 17, 2017. The procedural order also extended the rate case completion date as calculated by Commission rule for an additional 33 days. FERC FORM NO. 1 (ED. 12-88) Page 123.12 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) On March 1, 2017, the Staff of the ACC filed with the ACC a settlement term sheet with respect to APS’s pending general retail rate case. The settlement term sheet was agreed to by a majority of the formal stakeholders in the rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations. The settlement term sheet must be converted to a definitive settlement agreement and signed by the supporting parties. It will then be submitted to an administrative law judge, whose decision regarding whether the settlement should be approved will be reviewed by the ACC. We currently anticipate hearings on the proposed settlement will begin on April 24, 2017. Through a separate agreement, APS, industry representatives, and solar advocates commit to stand by the settlement agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. APS cannot predict whether a definitive settlement agreement based on the settlement term sheet will ultimately be approved by the ACC. 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 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 FERC FORM NO. 1 (ED. 12-88) Page 123.13 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) subsequent years if Arizona property tax rates increase; and • Deferral of 100% in all years if Arizona property tax rates decrease; • A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, see "Four Corners" below); • Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation; • Modifications to the Environmental Improvement Surcharge to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually; • Modifications to the PSA, including the elimination of the 90/10 sharing provision; • A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the settlement agreement for the 2009 retail rate case (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. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms. FERC FORM NO. 1 (ED. 12-88) Page 123.14 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC. 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. On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. The ACC has not yet ruled on the Company’s 2017 RES Implementation Plan. In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically. The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the EPA. The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. APS cannot predict the outcome of this proceeding. Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS FERC FORM NO. 1 (ED. 12-88) Page 123.15 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) to submit a Demand Side Management Implementation Plan ("DSM Plan") for review by and approval of the ACC. In March 2014, the ACC 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. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program. On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on the Company’s 2017 DSM Plan. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.16 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding. PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following: • APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate; • An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC; • The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point); • The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and • The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC. The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2016 and 2015 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.17 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Beginning balance Deferred fuel and purchased power costs - current period Amounts charged to customers Ending balance Year ended December 31, 2015 2016 $ (9,688) $ 6,926 60,303 (14,997) (38,150) (1,617) $ 12,465 $ (9,688) The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers ("Retail Transmission Charges"). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. 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. Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges FERC FORM NO. 1 (ED. 12-88) Page 123.18 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) went into effect automatically on June 1, 2016. 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 to make changes to their protocols in the future. As a result, APS is evaluating how its formula rate protocols compare with more recently approved formula rate protocols and anticipates that it will make a filing to update its formula rate protocols in the first quarter of 2017. 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 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. The ACC approved the 2016 annual LFCR to be effective in May 2016. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the two month delay in implementation did not have an adverse effect on APS. APS filed its 2017 LFCR adjustment on January 13, 2017. APS requested an adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels), to be effective the first billing cycle of March 2017. Net Metering In 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 was held in April 2016. On October 7, 2016, the ALJ issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize inputs from FERC FORM NO. 1 (ED. 12-88) Page 123.19 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) historical wholesale solar power costs and eventually an avoided cost methodology. As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a resource comparison proxy methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed. The price established by this resource comparison proxy method will be updated annually (between rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by that utility for exported distributed energy. In addition, the ACC made the following determinations: • Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to the date new rates are effective based on APS' pending rate case will be grandfathered for a period of 20 years from the date of interconnection; • Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and • Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years. This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change as are all ACC policies. The determination of the initial export energy price to be paid by APS will be made in APS’s currently pending rate case, which is scheduled for hearing by the ACC in April 2017. APS cannot predict the outcome of this determination. The ACC’s decision did not make any policy determinations as to any specific costs to be charged to DG solar system customers for their use of the grid. The determination of any such costs will be made in APS's future rate cases. On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserts that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC's request for rehearing is required for TASC to challenge this decision in court. To date, the ACC has taken no action on the rehearing request. The ACC's decision is FERC FORM NO. 1 (ED. 12-88) Page 123.20 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) expected to remain in effect during any legal challenge. 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 on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor. System Benefits Charge The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016. Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge. The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense. Subpoena from Arizona Corporation Commissioner Robert Burns On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer. On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that FERC FORM NO. 1 (ED. 12-88) Page 123.21 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed. On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff. As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas. Commissioner Burns has also scheduled a workshop in this matter for March 17, 2017. APS and Pinnacle West 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 to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $64 million as of December 31, 2016 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 suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed above. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.22 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. 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 established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates. APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016. On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter. 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. On January 13, 2017, EPA approved a final rule incorporating APS's compromise proposal. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review. 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 is seeking recovery of the unit’s decommissioning and other retirement-related costs over the previously estimated remaining life of the plant in its current retail rate case. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($116 million as of December 31, 2016), 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 123.23 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Navajo Plant On February 13, 2017, the co-owners of the Navajo Plant voted not to pursue continued operation of the plant beyond December 2019, the expiration of the current lease term, and to pursue a new lease or lease extension with the Navajo Nation that would allow decommissioning activities to begin after December 2019 instead of later this year. Various stakeholders including regulators, tribal representatives and others interested in the continued operation of the plant intend to meet to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. We cannot predict whether any alternate solutions will be found that would be acceptable to all of the stakeholders and feasible to implement. APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($108 million as of December 31, 2016, see Note 10 for additional details) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material. We cannot predict whether APS would obtain such recovery. On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding. FERC FORM NO. 1 (ED. 12-88) Page 123.24 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in thousands): December 31, Pension (a) Retired power plant costs Income taxes - AFUDC equity Deferred fuel and purchased power — mark-to-market (Note 17) Four Corners cost deferral Income taxes — investment tax credit basis adjustment Lost fixed cost recovery Deferred compensation Deferred property taxes AG-1 deferral Demand side management (b) Tax expense of Medicare subsidy Prior flow through of tax benefits Transmission vegetation management Mead-Phoenix transmission line CIAC Deferred fuel and purchased power (b) (c) Coal reclamation Other Total regulatory assets (d) (a) (b) (c) (d) $ 2016 711,059 127,504 158,423 42,963 63,582 56,476 61,307 35,595 73,200 5,868 3,744 12,102 1,718 11,040 12,465 5,600 4,944 $ 1,387,590 $ $ 2015 619,223 137,431 139,207 141,549 70,271 50,228 45,507 34,751 50,453 13,683 3,520 4,543 11,372 6,503 5,933 1,334,174 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. See “Cost Recovery Mechanisms” discussion above. Subject to a carrying charge. 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 123.25 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The detail of regulatory liabilities is as follows (dollars in thousands): Asset retirement obligations Removal costs Other postretirement benefits Income taxes — deferred investment tax credit Excess deferred taxes Income taxes - change in rates Spent nuclear fuel Renewable energy standard (a) Demand side management (a) Sundance maintenance Deferred fuel and purchased power Deferred gains on utility property Four Corners coal reclamation Other Total regulatory liabilities $ $ December 31, 2016 2015 279,976 $ 277,554 13,983 13,543 156,575 213,621 113,195 100,779 1,718 3,520 75,592 76,553 71,726 70,488 26,809 48,138 20,472 25,194 15,287 13,678 9,688 10,958 8,056 18,248 8,920 9,793 9,572 814,111 $ 879,525 (a) See “Cost Recovery Mechanisms” discussion above. 5. 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 123.26 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The components of APS’s income tax expense are as follows (dollars in thousands): Year Ended December 31, 2016 Current: Federal State Total current Deferred: Federal State Total deferred Total income tax expense $ $ 2015 186 4,500 4,686 211,225 29,469 240,694 245,380 $ $ 15,311 7,813 23,124 199,681 23,217 222,898 246,022 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, 2016 Federal income tax expense at 35% statutory rate Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit Credits and favorable adjustments related to prior years resolved in current year Medicare Subsidy Part-D Allowance for equity funds used during construction (see Note 1) Investment tax credit amortization Other Income tax expense $ $ 247,794 2015 $ 243,640 18,750 20,433 — 844 (11,724) (5,887) (4,397) 245,380 (1,710) 837 (9,711) (5,527) (1,940) 246,022 $ 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, 2016, APS has recorded a regulatory liability of $74 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law. On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate FERC FORM NO. 1 (ED. 12-88) Page 123.27 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2016, 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. The components of the net deferred income tax liability were as follows (dollars in thousands): 2016 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 Credit and loss carryforwards Other Total deferred tax assets DEFERRED TAX LIABILITIES Plant-related Risk management activities Other postretirement benefit assets Regulatory assets: Allowance for equity funds used during construction Deferred fuel and purchased power — mark-to-market Pension and other postretirement benefits Retired power plant costs (see Note 3) Other Other Total deferred tax liabilities Deferred income taxes — net 6. $ December 31, 2015 107,958 113,195 60,375 64,438 40,149 194,981 56,379 1,645 187,454 826,574 $ 107,885 100,779 83,034 61,868 80,616 181,787 60,956 176,016 852,941 (3,230,570) (21,129) (62,819) (3,032,796) (20,744) (70,986) (61,088) (21,396) (274,184) (49,166) (125,114) (5,165) (3,850,631) $ (3,024,057) (54,110) (55,020) (240,692) (53,420) (109,601) (4,984) (3,642,353) (2,789,412) $ Lines of Credit and Short-Term Borrowings APS maintains committed revolving credit facilities in order to enhance liquidity and provide credit support for their 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, 2016 and 2015 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.28 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) December 31, 2016 2015 $ 1,000,000 $ 1,000,000 (135,500) $ 864,500 $ 1,000,000 Commitments under Credit Facilities Outstanding Commercial Paper Amount of Credit Facilities Available Weighted-Average Commitment Fees 0.100% 0.100% During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million. On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021. At December 31, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021. APS may increase the amount of each facility up to a maximum of $700 million, 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 $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2016, APS had $135.5 million of commercial paper outstanding and 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, 2016 and 2015 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.29 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) APS Pollution control bonds: Variable Fixed Total pollution control bonds Other long-term Debt Unamortized discount Unamortized premium Total Long-Term Debt (a) (b) Maturity Dates (a) Interest Rates 2029 2024-2029 (b) 1.75%-4.70% 2018-2046 1.43%-8.75% December 31, 2016 $ $ 35,975 147,150 183,125 3,904,686 (11,816) 4,506 4,080,501 2015 $ $ 92,405 211,150 303,555 3,453,695 (10,374) 4,686 3,751,562 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 0.81% at December 31, 2016 and 0.01%-0.24% at December 31, 2015. The following table shows principal payments due on APS’s total long-term debt (dollars in thousands): Year APS 2017 $ — 2018 82,000 2019 600,000 2020 250,000 2021 — Thereafter Total 3,155,811 $ 4,087,811 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, 2016 Carrying Fair Value Amount Total $ FERC FORM NO. 1 (ED. 12-88) 4,080,501 $ As of December 31, 2015 Carrying Fair Value Amount 4,330,475 $ 3,694,971 $ Page 123.30 3,981,367 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Credit Facilities and Debt Issuances On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. 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 May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures. On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E. On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A. On August 1, 2016, APS repaid at maturity APS's $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016. On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016. On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B. On December 6, 2016, APS redeemed at par and canceled all $17 million of the Coconino County Arizona Pollution Control Corporation Revenue Bonds (Arizona Public Service Company Project), Series 1998. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.31 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2016, the ratio was approximately 47% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below. None of APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings. All of APS’s bank agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. APS does not have a material adverse change restriction for credit facility borrowings. An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2016, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.1 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.6 billion, assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2016. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.32 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement) for the employees of Pinnacle West and its subsidiaries. These plans provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits. On September 30, 2014, Pinnacle West announced plan design changes to the other postretirement benefit plan, which required an interim remeasurement of the benefit obligation for the plan. Effective January 1, 2015, those eligible retirees and dependents over age 65 and on Medicare can choose to be enrolled in a Health Reimbursement Arrangement (HRA). The Company is providing 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 approval to move up to $140 million of the other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to move into a new account to pay for active union employee medical costs. As of December 31, 2016, such methodology would result in an amount of approximately $140 million being transferred to the new account. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.33 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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): Service cost-benefits earned during the period Interest cost on benefit obligation Expected return on plan assets Amortization of: Prior service cost (credit) Net actuarial loss Net periodic benefit cost Portion of cost charged to expense $ $ $ Pension 2016 53,792 $ 131,647 (173,906) 527 40,717 52,777 26,172 2015 59,627 123,983 (179,231) 594 31,056 36,029 20,036 $ $ Other Benefits 2016 2015 $ 14,993 $ 16,827 29,721 28,102 (36,495) (36,855) $ $ (37,883) 4,589 (25,075) (12,435) $ $ (37,968) 4,881 (25,013) (10,391) The following table shows the plans’ changes in the benefit obligations and funded status for the years 2016 and 2015 (dollars in thousands): Pension 2016 Change in Benefit Obligation Benefit obligation at January 1 Service cost Interest cost Benefit payments Actuarial (gain) loss Benefit obligation at December 31 Change in Plan Assets Fair value of plan assets at January 1 Actual return on plan assets Employer contributions Benefit payments Fair value of plan assets at December 31 Funded Status at December 31 FERC FORM NO. 1 (ED. 12-88) 2015 Other Benefits 2016 2015 $ 3,033,803 53,792 131,647 (142,247) 127,467 3,204,462 $ 3,078,648 59,627 123,983 (137,115) (91,340) 3,033,803 $ 647,020 14,993 29,721 (26,231) 50,942 716,445 $ 682,335 16,827 28,102 (24,988) (55,256) 647,020 2,542,774 166,408 100,000 (133,825) 2,675,357 $ (529,105) 2,615,404 (44,690) 100,000 (127,940) 2,542,774 $ (491,029) 833,017 63,463 819 (14,648) 882,651 $ 166,206 834,625 (2,399) 791 833,017 $ 185,997 Page 123.34 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2016 and 2015 (dollars in thousands): 2016 Projected benefit obligation $ 2015 3,204,462 $ 3,033,803 Accumulated benefit obligation 3,049,406 2,873,467 Fair value of plan assets 2,675,357 2,542,774 The following table shows the amounts recognized on the Comparative Balance Sheets as of December 31, 2016 and 2015 (dollars in thousands): Pension 2016 Noncurrent asset Current liability Noncurrent liability Net amount recognized $ (19,795) (509,310) $ (529,105) 2015 $ (10,031) (480,998) $ (491,029) Other Benefits 2016 2015 $ 166,206 $ 185,997 $ 166,206 $ 185,997 The following table shows the details related to accumulated other comprehensive loss as of December 31, 2016 and 2015 (dollars in thousands): Net actuarial loss Prior service cost (credit) APS’s portion recorded as a regulatory (asset) liability Income tax expense (benefit) Accumulated other comprehensive loss Pension 2016 2015 $ 773,750 $ 679,501 81 609 $ (711,059) (24,202) 38,570 Other Benefits 2016 2015 $ 146,509 $ 127,124 (303,417) (341,301) (619,223) (23,663) $ 37,224 $ 156,575 833 500 $ 213,621 925 369 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 2017 (dollars in thousands): Net actuarial loss Prior service cost (credit) Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2017 FERC FORM NO. 1 (ED. 12-88) Page 123.35 $ Pension 46,971 81 $ 47,052 Other Benefits $ 5,181 (37,842) $ (32,661) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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: Discount rate – pension Discount rate – other benefits Rate of compensation increase Expected long-term return on plan assets - pension Expected long-term return on plan assets - other benefits Initial healthcare cost trend rate (pre-65 participants) Initial healthcare cost trend rate (post-65 participants) Ultimate healthcare cost trend rate Number of years to ultimate trend rate (pre-65 participants) Number of years to ultimate trend rate (post-65 participants) Benefit Costs for the Years Ended December 31, 2016 2015 4.37% 4.02% 4.52% 4.14% 4.00% 4.00% 6.90% 6.90% 4.45% 4.45% 7.00% 7.00% 5.00% 5.00% 5.00% 5.00% 4 4 0 0 Benefit Obligations As of December 31, 2016 2015 4.08% 4.37% 4.17% 4.52% 4.00% 4.00% N/A N/A N/A N/A 7.00% 7.00% 5.00% 5.00% 5.00% 5.00% 4 4 0 0 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 2017, we are assuming a 6.55% long-term rate of return for pension assets and 6.37% (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): Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants Effect on service and interest cost components of net periodic other postretirement benefit costs Effect on the accumulated other postretirement benefit obligation FERC FORM NO. 1 (ED. 12-88) Page 123.36 1% Increase 1% Decrease $ $ 8,430 8,440 108,046 (5,455) (6,527) (86,651) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Plan Assets The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities. The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis. Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended 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 and other government agencies, U.S Treasury Futures Contracts, and fixed income debt securities issued by corporations. Long-term fixed income assets may also include interest rate swaps, 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 also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds. Based on the IPS, and given the pension plan’s funded status at year-end 2016, 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, 2016, long-term fixed income assets represented 57% of total pension plan assets, and return-generating assets represented 43% of total pension plan assets. As of December 31, 2016, 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, 2016, FERC FORM NO. 1 (ED. 12-88) Page 123.37 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) investment in fixed income assets represented 51% of the other postretirement benefit plan total assets, and non-fixed income assets represented 49% of the other postretirement benefit plan’s assets. 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, U.S Treasury Futures Contracts, 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. U.S Treasury Future Contracts are valued using the quoted active market prices from the exchange on which they trade, 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. Mutual funds, classified as Level 1, are valued using a NAV that is observable and 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. Investments in common and collective trusts are valued using NAV, as a practical expedient and accordingly are not classified in the fair value hierarchy. 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, 2016, the plans were able to transact in the common and collective trusts at NAV. Investments in partnerships are also valued using the concept of NAV, as a practical expedient and accordingly are not classified in the fair value hierarchy. The NAV for these investments 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, 2016, approximately $54 million of these commitments have been funded. The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent FERC FORM NO. 1 (ED. 12-88) Page 123.38 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2016, 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) Balance at December 31, 2016 Other (a) Pension Plan: Cash and cash equivalents $ 13,995 $ — $ — $ 13,995 Fixed income securities: Corporate — 1,210,453 — 1,210,453 112,583 — — 112,583 — 102,170 — 102,170 Common stock equities (c) 235,109 — — 235,109 Mutual funds (d) 251,506 — — 251,506 Equities — — 266,840 266,840 Real estate U.S. Treasury Other (b) Common and collective trusts: — — 161,449 161,449 Partnerships — — 208,915 208,915 Short-term investments and other (e) — — 112,337 112,337 Total $ 613,193 $ 1,312,623 $ 749,541 $ 2,675,357 $ 304 Other Benefits: Cash and cash equivalents $ 304 $ — $ — Fixed income securities: Corporate — 268,193 — 268,193 145,255 — — 145,255 — 34,506 — 34,506 243,741 — — 243,741 67,418 — — 67,418 Equities — — 95,814 95,814 Real estate U.S. Treasury Other (b) Common stock equities (c) Mutual funds (d) Common and collective trusts: — — 14,509 14,509 Partnerships — — 3,060 3,060 Short-term investments and other (e) — — 9,851 9,851 Total FERC FORM NO. 1 (ED. 12-88) $ 456,718 $ Page 123.39 302,699 $ 123,234 $ 882,651 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) (b) (c) (d) (e) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy. This category consists primarily of debt securities issued by municipalities. This category primarily consists of US common stock equities. These funds invest in US and international common stock equities. This category includes plan receivables and payables. Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Balance at Other (a) December 31, 2015 Pension Plan: Cash and cash equivalents $ 1,893 $ — $ — $ 1,893 Fixed Income Securities: Corporate — 1,108,736 — 1,108,736 274,778 — — 274,778 — 113,008 — 113,008 Common stock equities (c) 247,701 — — 247,701 Mutual funds - International equities 116,307 — — 116,307 Equities — — 315,989 315,989 Real Estate — — 150,359 150,359 U.S. Treasury Other (b) Common and collective trusts: Partnerships — — 169,937 169,937 Short-term investments and other (d) — — 44,066 44,066 Total $ 640,679 $ $ 240 $ 1,221,744 $ 680,351 $ 2,542,774 $ 240 Other Benefits: Cash and cash equivalents — $ — Fixed Income Securities: Corporate — 217,026 — 217,026 131,435 — — 131,435 — 31,106 — 31,106 265,583 — — 265,583 52,568 — — 52,568 Equities — — 110,055 110,055 Real Estate — — 13,512 13,512 U.S. Treasury Other (b) Common stock equities (c) Mutual funds - International equities Common and collective trusts: Short-term investments and other (d) Total FERC FORM NO. 1 (ED. 12-88) — — $ 449,826 Page 123.40 $ 248,132 $ 11,492 135,059 11,492 $ 833,017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) These investments primarily represent assets valued using net asset value as a practical expedient, and have not been classified in the fair value hierarchy. (b) This category consists primarily of debt securities issued by municipalities. (c) This category primarily consists of US common stock equities. (d) This category includes plan receivables and payables. 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 2016, and $100 million in 2015. 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 2017-2019 period. With regard to contributions to the other postretirement benefit plans, Pinnacle West made a contribution of approximately $1 million in each of 2016 and 2015. Pinnacle West expects to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans. APS funds its share of the contributions. APS’s share of the pension plan contribution was approximately $100 million in 2016 and $100 million in 2015. APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2016 and 2015. 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 2017 $ Other Benefits 172,859 $ 31,126 2018 173,232 33,795 2019 182,944 36,195 2020 191,037 37,998 2021 196,292 39,368 1,049,149 201,944 Years 2022-2026 Electric plant participants contribute to the above amounts in accordance with their respective participation agreements. Employee Savings Plan Benefits Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2016, 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 FERC FORM NO. 1 (ED. 12-88) Page 123.41 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 $10 million for 2016 and $9 million for 2015. 9. Leases We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. See Note 3 for a discussion of the new lease accounting standard. APS’s lease expense was $38 million in 2016 and $59 million in 2015. Estimated future minimum lease payments for APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands): Year APS 2017 $ 34,919 2018 33,690 2019 31,767 2020 30,439 2021 28,020 Thereafter 263,207 Total future lease commitments $ 422,042 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 Statements 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, 2016 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.42 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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 $ 1,770,324 $ 1,080,072 $ 17,615 581,572 360,757 9,717 (b) 672,799 242,649 62,479 (a) 351,050 237,535 — Four Corners Generating Station 63.0% 934,837 578,924 248,072 Navajo Generating Station Units 1, 2 and 3 14.0% 279,629 176,931 5,761 Cholla common facilities (c) 63.3% (b) 159,707 58,276 ANPP 500kV System 33.6% (b) 127,970 38,610 2,291 Navajo Southern System 22.5% (b) 62,135 20,491 334 Palo Verde — Yuma 500kV System 19.0% (b) 13,699 5,368 408 Four Corners Switchyards 51.3% (b) 39,850 10,474 1,044 Phoenix — Mead System 17.1% (b) 39,330 13,725 85 Palo Verde — Rudd 500kV System 50.0% (b) 91,904 19,818 227 Morgan — Pinnacle Peak System 65.2% (b) 140,374 13,557 — Round Valley System 50.0% (b) 515 127 — Palo Verde — Morgan System 85.8% (b) 125,908 1,326 28,949 Hassayampa — North Gila System 80.0% (b) 142,541 3,231 — Cholla 500kV Switchyard 85.7% (b) 5,078 1,201 — Saguaro 500kV Switchyard 75.0% (b) 20,456 12,426 2 806 (d) Transmission facilities: (a) (b) (c) (d) 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. Due to the closure of Cholla Unit 2 in 2015, all new Cholla common facilities construction is owned by APS at 50.5% FERC FORM NO. 1 (ED. 12-88) Page 123.43 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 11. 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 the DOE in the Court of Federal Claims. The lawsuit sought to recover damages incurred due to DOE’s breach of the 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 reported net income. In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019. APS has submitted two claims pursuant to the terms of the August 18, 2014 settlement agreement, for two separate time periods during July 1, 2011 through June 30, 2015. The DOE has approved and paid $53.9 million for these claims (APS’s share is $15.7 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on October 31, 2016, and approved on February 1, 2017, in the amount of $11.3 million (APS’s share is $3.3 million). Payment for the claim is expected in the second quarter of 2017. 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-wide 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 approximately $13.4 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million (on January 1, 2017 this coverage was increased to $450 million), which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately $13.1 billion (on January 1, 2017 this balance was decreased to $13.0 billion) of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium FERC FORM NO. 1 (ED. 12-88) Page 123.44 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $18.9 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium of approximately $16.6 million. The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL"). APS is subject to retrospective premium adjustments 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 $23.8 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 $64 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions. Fuel and Purchased Power Commitments and Purchase Obligations APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2017 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $977 million in 2017; $737 million in 2018; $598 million in 2019; $525 million in 2020; $524 million in 2021; and $7.3 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) $ 2017 2018 2019 2020 2021 195,428 $ 189,588 $ 193,818 $ 198,160 $ 202,619 $ 2,068,355 Thereafter Total take-or-pay commitments are approximately $3.0 billion. The total net present value of these commitments is approximately $2.1 billion. APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal FERC FORM NO. 1 (ED. 12-88) Page 123.45 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last two years (dollars in thousands): Total purchases $ Year Ended December 31, 2016 2015 160,066 $ 211,327 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 $40 million in 2017; $40 million in 2018; $40 million in 2019; $40 million in 2020; $40 million in 2021; and $420 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Coal Mine Reclamation Obligations APS and 4CA 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 $207 million at December 31, 2016 and $202 million at December 31, 2015. 4CA recorded an obligation for the coal mine final reclamation of approximately $15 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $17 million in 2017; $18 million in 2018; $19 million in 2019; $21 million in 2020; $22 million in 2021; and $241 million thereafter. 4CA expects to make payments for the final mine reclamation as follows: $1 million in 2017; $1 million in 2018; $1 million in 2019; $1 million in 2020; $2 million in 2021; and $17 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 FERC FORM NO. 1 (ED. 12-88) Page 123.46 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) RI/FS work plan. The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by June 2017. 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. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. 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 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. On March 2, 2016, the United States Court of Appeals for the Ninth Circuit unanimously affirmed the District Court's decision. The plaintiffs filed a Petition for Rehearing En Banc, which was denied on April 11, 2016. FERC FORM NO. 1 (ED. 12-88) Page 123.47 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, 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 and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. EPA recently approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the recent Cholla rule approval. Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required 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. 4CA purchased the El Paso interest on July 6, 2016. NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. 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 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. See "Navajo Plant" in Note 4 for information regarding future plans for the Navajo Plant. Cholla. APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million 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. Pending certain FERC FORM NO. 1 (ED. 12-88) Page 123.48 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) regulatory approvals, APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 4 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 a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program. EPA signed the final rule approving the Agency's proposal on January 13, 2017. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review. 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. 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 majority of which has already been incurred. Litigation concerning the rules, including supplemental analyses EPA has prepared in support of the MATS regulation, is ongoing. These proceedings do not materially impact APS. Regardless of the results from further judicial or administrative proceedings concerning 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 FERC FORM NO. 1 (ED. 12-88) Page 123.49 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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. On December 16, 2016, President Obama signed the WIIN Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds. Because EPA has yet to undertake rulemaking proceedings to implement the CCR provisions of the WIIN Act, and Arizona has yet to determine whether it will develop a state-specific permitting program, it is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR. 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. APS is currently evaluating compliance alternatives for Cholla and estimates that its share of incremental costs to comply with the CCR rule for this plant is in the range of $5 million to $40 million based upon which compliance alternatives are ultimately selected. 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, the majority of which has already been incurred. Additionally, the CCR rule requires ongoing groundwater monitoring. Depending upon the results of such monitoring at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time. Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next 3 years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion. Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures FERC FORM NO. 1 (ED. 12-88) Page 123.50 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings. 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, this timing will be impacted by the court-imposed stay described below. Prior to the court-imposed stay described below, ADEQ, with input from a technical working group comprised of Arizona utilities and other stakeholders, was working to develop a compliance plan for submittal to EPA. Since the imposition of the stay, ADEQ is continuing to assess alternatives while completing outreach and soliciting feedback from stakeholders. In addition to these ongoing 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 a 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 FERC FORM NO. 1 (ED. 12-88) Page 123.51 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 or potential plant closures, as alternatives to purchasing allowances. Given these uncertainties, our analysis of the available compliance options remains ongoing, 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 FERC FORM NO. 1 (ED. 12-88) Page 123.52 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, 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. Federal Agency Environmental Lawsuit Related to Four Corners On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners. 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 in the amount of $0.8 million 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. On March 16, 2016, APS and the coal supplier entered into a final settlement agreement with the NMTRD FERC FORM NO. 1 (ED. 12-88) Page 123.53 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners co-owners agreed to forgo refund rights with respect to all of the contested amounts previously paid under the applicable tax statute, as well as pay $1 million. APS's share of this settlement payment, together with its share of the partial payment described above, is approximately $0.8 million. Peabody Bankruptcy On April 13, 2016, Peabody Energy Corporation and certain affiliated entities filed a petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri. Under a Coal Supply Agreement, dated December 21, 2005, Peabody supplied coal to APS and PacifiCorp (collectively, the “Buyers”) for use at the Cholla power plant in Arizona. APS believes that the Coal Supply Agreement terminated automatically on April 13, 2016 as a result of Peabody's bankruptcy filing. The Buyers filed a motion requesting that the Bankruptcy Court enter an order determining that the Buyers are authorized to enforce the termination provisions in the Coal Supply Agreement. On May 13, 2016, Peabody filed a complaint against the Buyers in the bankruptcy court in which Peabody alleged that the Buyers breached the Agreement. On January 27, 2017, the bankruptcy court approved a settlement between the parties, and on February 6, 2017 the parties executed an amendment to the Coal Supply Agreement that allows for continuation of the agreement with modified terms and conditions acceptable to the parties. 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 commodity contract collateral obligations and other transactions. As of December 31, 2016, standby letters of credit totaled $35 million and will expire in 2017. As of December 31, 2016, surety bonds expiring through 2019 totaled $53 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 123.54 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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 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 2016, APS recognized an ARO for the Ocotillo steam units as a condition of the air permit (issued in 2016) to allow the construction and operation of five new turbine units. This resulted in an increase to the ARO in the amount of $10 million. In addition, Four Corners spent $16 million in actual decommissioning costs. Finally, in 2016, APS received a new decommissioning study for the Palo Verde Nuclear Generating Station. This resulted in an increase to the ARO in the amount of $151 million, an increase in plant in service of $131 million, and a reduction of the regulatory liability of $20 million. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.55 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows the change in our asset retirement obligations for 2016 and 2015 (dollars in thousands): Asset retirement obligations at the beginning of year Changes attributable to: Accretion expense Settlements Estimated cash flow revisions Newly incurred or acquired obligations Asset retirement obligations at the end of year $ 2016 443,576 2015 $ 390,750 $ 26,518 (15,577) 151,046 10,373 615,936 25,163 (32,048) 17,556 42,155 443,576 $ 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. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.56 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. During the first quarter of 2016 we retrospectively adopted new accounting guidance that requires certain instruments valued using NAV to no longer be classified within the fair value hierarchy. As such, certain instruments valued using NAV are included in our fair value disclosures and tables in a separate column; however, these investments are not classified within any of the fair value hierarchy levels. Prior to the adoption of this guidance these instruments were typically reported within Level 2 or Level 3. The adoption of this guidance changes our fair value disclosures, but does not impact the methodology for valuing these instruments, or our financial statement results. Recurring Fair Value Measurements We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments. 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. Coal Reclamation Trust Investments The coal reclamation trust holds cash equivalent investments in money market funds that are valued using quoted prices in active markets, and are reported within Level 1. FERC FORM NO. 1 (ED. 12-88) Page 123.57 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities FERC FORM NO. 1 (ED. 12-88) Page 123.58 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) are held indirectly through commingled funds. The commingled funds are valued using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. 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 funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy. 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 123.59 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Fair Value Tables The following table presents the fair value at December 31, 2016, 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, 2016 Other Assets Coal reclamation trust - Cash equivalents (b) 13,545 — $ — $ — $ 13,545 Risk management activities — derivative instruments: Commodity contracts — 43,722 11,076 1 54,799 — — — 353,261 353,261 — — — 795 795 Nuclear decommissioning trust: U.S. commingled equity funds Fixed income securities: Cash and cash equivalent funds U.S. Treasury 95,441 — — — 95,441 Corporate debt — 111,623 — — 111,623 Mortgage-backed securities — 115,337 — — 115,337 Municipal bonds — 80,997 — — 80,997 Other — 22,132 — — 22,132 95,441 330,089 — 354,056 779,586 $ 108,986 $ 373,811 $ 11,076 $ 354,057 $ 847,930 $ — (45,641) $ (58,482) Subtotal nuclear decommissioning trust Total Liabilities Risk management activities — derivative instruments: Commodity contracts $ $ (1) $ (104,124) (a) Primarily consists of long-dated electricity contracts. (b) Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. FERC FORM NO. 1 (ED. 12-88) Page 123.60 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 Fixed income securities: Cash and cash equivalent funds U.S. Treasury 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 — — 23,555 129,505 291,069 — 314,622 735,196 129,505 $ 314,061 $ $ 314,634 $ 788,564 Subtotal nuclear decommissioning trust Total $ 30,364 Liabilities Risk management activities — derivative instruments: Commodity contracts (a) $ — $ (144,044) $ (63,343) $ (12) $ (207,399) 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). FERC FORM NO. 1 (ED. 12-88) Page 123.61 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The remaining option contract expired on October 1, 2016. The significant unobservable inputs at December 31, 2015 for these instruments include electricity 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, 2016 and December 31, 2015: December 31, 2016 Fair Value (thousands) Commodity Contracts Assets Valuation Technique Significant Unobservable Input WeightedRange Average Liabilities Electricity: Forward Contracts (a) $ 10,648 $ 32,042 Discounted cash flows Electricity forward price (per MWh) $16.43 - $41.07 $ 29.86 Natural Gas: Discounted cash flows Forward Contracts (a) 26,440 428 Total (a) $ 11,076 $ 58,482 Includes swaps and physical and financial contracts. FERC FORM NO. 1 (ED. 12-88) Page 123.62 Natural gas forward price (per MMBtu) $2.32 - $3.60 $ 2.81 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) December 31, 2015 Fair Value (thousands) Commodity Contracts Assets Valuation Technique Significant Unobservable Input WeightedRange Average Liabilities Electricity: Forward Contracts (a) $ 24,543 Option Contracts (b) $ — 54,679 5,628 Discounted cash flows Option model Electricity forward price (per MWh) $15.92 - $40.73 $ 26.86 Electricity forward price (per MWh) $23.87 - $44.13 $ 33.91 Electricity price volatilities 40% - 59% 52% Natural gas price volatilities 32% - 40% 35% Natural Gas: Discounted cash flows Forward Contracts (a) 3,036 5,821 Total $ (a) (b) 30,364 $ Natural gas forward price (per MMBtu) $2.18 - $3.14 $ 2.61 63,343 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, 2016 and 2015 (dollars in thousands): Commodity Contracts Net derivative balance at beginning of period Total net gains (losses) realized/unrealized: Included in earnings Included in OCI Deferred as a regulatory asset or liability Settlements Transfers into Level 3 from Level 2 Transfers from Level 3 into Level 2 Net derivative balance at end of period Net unrealized gains included in earnings related to instruments still held at end of period FERC FORM NO. 1 (ED. 12-88) Page 123.63 $ $ $ Year Ended December 31, 2016 2015 (32,979) $ (41,386) 88 (37,543) 15,146 1,900 5,982 (47,406) - $ $ (452) (4,009) 14,809 (6,256) 4,315 (32,979) - 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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, 2016, 2.5 million common shares were available for issuance under the 2012 Plan. During 2016, 2015, and 2014, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. 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 During the fourth quarter of 2016, we adopted new stock-based compensation accounting guidance prescribed by ASU 2016-09, see Note 3. Prior to the adoption of this guidance we had certain awards that were accounted for as liability awards due to the ability of the employee to withhold taxes beyond the minimum statutory tax withholding rate. Under the new standard, the tax withholding terms of our awards no longer trigger liability treatment. Accordingly, effective, January 1, 2016 certain awards that were previously classified as liability awards are now accounted for as equity awards. The impacts of this accounting change relating to prior years have been applied using a modified retrospective approach, resulting in a $5 million cumulative-effect adjustment, net of income tax expense of $3 million, to increase Retained Earnings as of January 1, 2016. The impacts of this accounting change relating to the current year, resulted in a pre-tax $12 million adjustment to decrease operations FERC FORM NO. 1 (ED. 12-88) Page 123.64 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) and maintenance expense that was recognized during the fourth quarter of 2016. Due to this transition approach, the following discussion reflects this change in the 2016 expense and activity; however, expense and activities relating to 2015 and 2014 reflect the historical treatment. The new standard also requires excess income tax benefits and deficiencies arising from stock based compensation to now be recognized in the period incurred, simplifies accounting for forfeitures, and clarifies certain cash flow presentation matters. These other provisions of the standard did not have a material impact on our comparative financial statements. Compensation cost included in net income for stock-based compensation plans was $19 million in 2016 and $19 million in 2015. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $10 million in 2016 and $7 million in 2015. As of December 31, 2016, there were approximately $13 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years. The total fair value of shares vested was $22 million in 2016 and $21 million in 2015. The following table is a summary of awards granted and the weighted-average grant date fair value for the two years ended 2016 and 2015. Restricted Stock Units, Stock Grants, and Stock Units (a) 2016 2015 Units granted Weighted-average grant date fair value 141,811 $ 67.34 Performance Shares (b) 2016 2015 152,651 $ 64.12 166,666 $ 60.60 151,430 $ (a) Units granted includes awards that will be cash settled of 43,952 in 2016 and 45,104 in 2015. (b) Reflects the target payout level. FERC FORM NO. 1 (ED. 12-88) Page 123.65 64.97 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table is a summary of the status of non-vested awards as of December 31, 2016 and changes during the year. Restricted Stock Units, Stock Grants, and Stock Units Weighted-Average Grant Shares Date Fair Value Nonvested at January 1, 2016 428,287 Granted 141,811 - $ Change in performance factor Vested Forfeited (c) Nonvested at December 31, 2016 Vested Awards Outstanding at December 31, 2016 Performance Shares Weighted-Average Grant Shares (b) Date Fair Value 56.69 305,832 67.34 166,666 66.60 15,573 54.09 - $ 58.86 (230,881) 55.07 (171,303) 54.09 (3,958) 62.86 (4,044) 62.34 62.04 312,724 65.32 335,259 (a) 174,201 171,303 (a) Includes 112,554 of awards that will be cash settled. (b) The nonvested performance shares are reflected at target payout level. The performance metric component 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. (c) We account for forfeitures as they occur. Share-based liabilities paid relating to restricted stock units were $3 million, and $10 million in 2016 and 2015, respectively. This includes cash used to settle restricted stock units of $3 million for each of the years 2016and 2015. Restricted stock units that are cash settled are classified as liability awards. Share-based liabilities paid relating to performance shares were $16 million in 2015. In 2016, performance shares were classified as equity awards. Restricted Stock Units, Stock Grants, and Stock Units Restricted stock units are 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% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award FERC FORM NO. 1 (ED. 12-88) Page 123.66 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares. In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West. This award vested on December 31, 2016, because he remained employed with the Company through that date. The Board can increase the number of awards that vest, up to an additional 33,745 restricted stock units, payable in stock, if certain performance requirements are met. Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash 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. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company's closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award. 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. Each stock unit is convertible to one share of 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 are granted to officers and key employees. The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based upon six non-financial separate performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West's total shareholder return (TSR) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). 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 FERC FORM NO. 1 (ED. 12-88) Page 123.67 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) the employee is not entitled to the dividends on those shares. Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest. 15. Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Comparative Statements of Income, but does not impact our financial condition, net income or cash flows. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.68 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. As of December 31, 2016, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 1,314 Gas 194 GWh 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, 2016and 2015 (dollars in thousands): Financial Statement Location Commodity Contracts Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion) Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) (a) (b) OCI — derivative instruments Fuel and purchased power (b) Year Ended December 31, 2016 2015 $ 47 (3,926) $ (615) (5,988) During the years ended December 31, 2016 and 2015, 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 $3 million before income taxes will be FERC FORM NO. 1 (ED. 12-88) Page 123.69 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2016 and 2015 (dollars in thousands): Financial Statement Location Commodity Contracts Net Gain Recognized in Income Net Gain (Loss) Recognized in Income Total (a) Operating revenues Fuel and purchased power (a) Year Ended December 31, 2016 2015 $ $ 771 25,711 26,482 $ $ 574 (108,973) (108,399) Amounts are before the effect of PSA deferrals. Derivative Instruments in the Comparative Balance Sheets Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Comparative Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are 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, 2016 and December 31, 2015, include gross liabilities of $2 million and $3 million, respectively, of derivative instruments designated as hedging instruments. FERC FORM NO. 1 (ED. 12-88) Page 123.70 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 related 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, 2016: (dollars in thousands) Current Assets Investments and Other Assets Total Assets Current Liabilities Deferred Credits and Other Total Liabilities Total (a) (b) Gross Recognized Derivatives (a) $ 48,094 6,704 54,798 $ (50,182) (53,941) (104,123) (49,325) Eligible for Offsetting Derivatives Cash Collateral (b) $ (28,400) $ -(6,703) -(35,103) -- $ 28,400 6,703 35,103 -- $ Net Derivatives After Impacts of Offsetting $ 19,694 1 19,695 ----- $ (21,782) (47,238) (69,020) (49,325) All of our gross recognized derivative instruments were subject to master netting arrangements. We had no cash collateral and margin provided to counterparties. We had total cash collateral received from counterparties of $4,054; this amount is reflected in miscellaneous current and accrued liabilities. Certain cash collateral is not eligible for offsetting as it does not related to recognized derivatives. As of December 31, 2015: (dollars in thousands) Current Assets Investments and Other Assets Total Assets Current Liabilities Deferred Credits and Other Total Liabilities Total Gross Recognized Derivatives (a) $ 37,396 15,960 53,356 $ (113,560) (93,827) (207,387) (154,031) 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) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) 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 related to recognized derivatives. FERC FORM NO. 1 (ED. 12-88) Page 123.71 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Credit Risk and Credit Related Contingent Features We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, 2016, we have no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2016 (dollars in thousands): December 31, 2016 Aggregate fair value of derivative instruments in a net liability position $ 104,123 Cash collateral posted — Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) (a) 23,914 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 $144 million if our FERC FORM NO. 1 (ED. 12-88) Page 123.72 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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 2017 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors. For regulatory reporting purposes, APS accounts for the lease renewal as a capital lease on the balance sheet and an operating lease for income statement and cash flow statement purposes. APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants 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 periods, APS may be required to pay the noncontrolling equity participants approximately $291 million beginning in 2017, and up to $456 million over the lease extension term. 17. Nuclear Decommissioning Trusts To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Comparative Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2016 and December 31, 2015 (dollars in thousands): FERC FORM NO. 1 (ED. 12-88) Page 123.73 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Total Unrealized Gains Fair Value Total Unrealized Losses December 31, 2016 Equity securities $ 353,261 Fixed income securities Net receivables (a) Total $ $ 188,091 $ — 425,530 9,820 (4,962) 795 — — 779,586 $ 197,911 $ Total Unrealized Gains Fair Value (4,962) Total Unrealized Losses December 31, 2015 Equity securities $ 314,957 Fixed income securities Net payables (a) Total $ (a) $ 157,098 $ (115) 420,574 11,955 (2,645) (335) — — 735,196 $ 169,053 $ (2,760) Net receivables/(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): Realized gains Realized losses Proceeds from the sale of securities (a) (a) $ Year Ended December 31, 2016 2015 11,213 $ 5,189 (10,106) (6,225) 633,410 478,813 Proceeds are reinvested in the trust. The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2016 is as follows (dollars in thousands): Fair Value Less than one year $ 13,063 1 year – 5 years 119,292 5 years – 10 years 105,612 Greater than 10 years 187,563 Total FERC FORM NO. 1 (ED. 12-88) $ Page 123.74 425,530 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 18. 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, 2016 and 2015 (dollars in thousands): Year Ended December 31, 2016 $ Balance at beginning of period 2015 (27,097) $ (48,333) Derivative Instruments OCI (loss) before reclassifications (538) (957) Amounts reclassified from accumulated other comprehensive loss (a) 2,941 4,187 Net current period OCI (loss) 2,403 3,230 (3,821) 14,726 Amounts reclassified from accumulated other comprehensive loss (b) 3,092 3,280 Net current period OCI (loss) (729) 18,006 Pension and Other Postretirement Benefits OCI (loss) before reclassifications $ Balance at end of period (a) (b) (25,423) $ (27,097) 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 123.75 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) ( 37,947,651) 2 Preceding Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 3,279,529 3 Preceding Quarter/Year to Date Changes in Fair Value 14,726,301 4 Total (lines 2 and 3) 18,005,830 5 Balance of Account 219 at End of Preceding Quarter/Year ( 19,941,821) 6 Balance of Account 219 at Beginning of Current Year ( 19,941,821) 7 Current Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 3,092,366 8 Current Quarter/Year to Date Changes in Fair Value ( 3,821,973) 9 Total (lines 7 and 8) ( 729,607) 10 Balance of Account 219 at End of Current Quarter/Year FERC FORM NO. 1 (NEW 06-02) ( Page 122a 20,671,428) Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) 10,384,980) 2 ( 7,467,023 ( 957,776) 13,768,525 5 ( 7,155,262) ( 27,097,083) 6 ( 7,155,262) ( 27,097,083) ( 4,359,505) ( 25,423,581) 4 3,229,718 7 8 537,532) ( 4,752,153) 9 10 FERC FORM NO. 1 (NEW 06-02) 21,235,548 2,940,641 ( (i) (j) 450,274,046 471,509,594 462,140,944 463,814,446 6,033,007 2,403,109 Page 122b Total Comprehensive Income 48,332,631) 4,187,494 3 Net Income (Carried Forward from Page 117, Line 78) 1,673,502 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) (2) A Resubmission 03/31/2017 SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION 20170406-8017 FERC PDF (Unofficial) (1) 03/31/2017 X An Original Arizona Public Service Company Year/Period of Report 2016/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) 16,700,335,556 16,700,335,556 186,209,060 186,209,060 956,737,712 956,737,712 17,843,282,328 17,843,282,328 8,558,796 8,558,796 11 Construction Work in Progress 878,382,780 878,382,780 12 Acquisition Adjustments 255,525,921 255,525,921 18,985,749,825 18,985,749,825 4 Property Under Capital Leases 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 13 Total Utility Plant (8 thru 12) 14 Accum Prov for Depr, Amort, & Depl 15 Net Utility Plant (13 less 14) 6,723,503,730 6,723,503,730 12,262,246,095 12,262,246,095 5,913,579,625 5,913,579,625 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) 787,724,158 787,724,158 6,701,303,783 6,701,303,783 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 22,199,947 22,199,947 6,723,503,730 6,723,503,730 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 17,617,604 38,367,067 3 Nuclear Materials 73,889,976 39,611,510 4 Allowance for Funds Used during Construction 5 (Other Overhead Construction Costs, provide details in footnote) 6 SUBTOTAL (Total 2 thru 5) 8,188,300 6,838,623 -138,270 1,787,196 99,557,610 7 Nuclear Fuel Materials and Assemblies 8 In Stock (120.2) 9 In Reactor (120.3) 10 SUBTOTAL (Total 8 & 9) 845 75,047,820 269,365,593 75,046,455 269,366,438 11 Spent Nuclear Fuel (120.4) 12 Nuclear Fuel Under Capital Leases (120.6) 13 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 146,227,544 14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 222,696,504 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 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/Q4 End of NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) Amortization (d) Changes during Year Other Reductions (Explain in a footnote) (e) Balance End of Year (f) Line No. 1 35,378,374 20,606,297 2 31,610,394 81,891,092 3 6,271,856 8,755,067 4 1,787,196 -138,270 5 111,114,186 6 7 75,047,300 1,365 78,206,814 266,205,234 8 9 266,206,599 10 11 12 -79,181,574 78,206,814 147,202,304 13 230,118,481 14 15 16 17 18 19 20 21 22 FERC FORM NO. 1 (ED. 12-89) Page 203 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 03/31/2017 2016/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 3,516,989 86,611 4 (303) Miscellaneous Intangible Plant 688,013,045 78,757,011 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 691,530,034 78,843,622 6 2. PRODUCTION PLANT 7 A. Steam Production Plant 8 (310) Land and Land Rights 5,793,509 9 (311) Structures and Improvements 169,959,505 3,311,193 10 (312) Boiler Plant Equipment 1,156,581,622 74,794,208 11 (313) Engines and Engine-Driven Generators 12 (314) Turbogenerator Units 212,294,513 4,876,147 13 (315) Accessory Electric Equipment 127,147,099 6,162,407 14 (316) Misc. Power Plant Equipment 95,057,631 9,961,269 15 (317) Asset Retirement Costs for Steam Production 42,687,295 10,372,588 16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 1,809,521,174 109,477,812 17 B. Nuclear Production Plant 18 (320) Land and Land Rights 4,417,789 19 (321) Structures and Improvements 816,786,489 32,821,342 20 (322) Reactor Plant Equipment 1,239,997,477 5,009,380 21 (323) Turbogenerator Units 400,230,928 11,801,264 22 (324) Accessory Electric Equipment 289,890,908 4,300,005 23 (325) Misc. Power Plant Equipment 194,436,793 12,032,260 24 (326) Asset Retirement Costs for Nuclear Production -53,660,218 131,518,351 25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 2,892,100,166 197,482,602 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 15,766,669 -2,334 38 (341) Structures and Improvements 115,260,761 5,789,819 39 (342) Fuel Holders, Products, and Accessories 55,221,288 965,793 40 (343) Prime Movers 652,662,488 6,786,198 41 (344) Generators 1,295,258,387 141,496,848 42 (345) Accessory Electric Equipment 209,397,323 6,431,997 43 (346) Misc. Power Plant Equipment 27,345,148 3,214,024 44 (347) Asset Retirement Costs for Other Production 8,856,067 45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 2,379,768,131 164,682,345 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 7,081,389,471 471,642,759 FERC FORM NO. 1 (REV. 12-05) Page 204 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 2016/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 Additions (c) 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 12,071,901 26,484,019 100,360,046 60,535 63,034,578 40,059,127 16,270,449 13,126 2,448,884,451 258,353,781 62,532,920 82,466,661 494,771,283 2,123,630 593,108,591 355,117,541 685,513,670 1,646,381,070 833,455,083 375,644,742 291,363,329 43,555,103 51,910 3,181,115 54,509,197 28,949,771 23,659,040 14,120,920 37,260,210 31,716,045 20,771,481 28,917,146 1,924,067 2,390,792 74,601,786 5,540,635,409 206 247,451,694 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 17,446,237 818,011,534 178,637 13,167,310 4,072,451 100,798,760 818,011,534 16,580,450,899 100,798,760 1,157,090,616 16,580,450,899 1,157,090,616 52,430,284 26,384,160 2,332,904 442,759 1,790,255 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) 4,279 755,988 760,267 3,599,321 766,014,068 769,613,389 605,366 6,632,498 5,793,509 172,665,332 1,224,743,332 2,577,932 157,953 258,301 214,592,728 133,151,553 104,760,599 53,059,883 1,908,766,936 10,232,050 1,675,499 9,422,334 4,293,224 562,820 260,464 -183,946 183,946 16,214,341 15,764,335 120,813,197 55,639,804 657,158,530 1,429,583,770 214,237,650 30,377,550 8,856,067 2,532,430,903 7,514,566,266 237,383 547,277 2,290,156 7,171,465 1,591,670 181,622 12,019,573 38,465,964 FERC FORM NO. 1 (REV. 12-05) 4,417,789 847,932,332 1,235,400,577 407,922,914 293,628,093 206,208,589 77,858,133 3,073,368,427 Page 205 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: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) 970,920 6,482,748 42,672,153 96,761 117,625 2,469,186 86,170 39 -319,150 -339,339 -20,187 10,009,063 42,207,863 2,739,437,032 411,599 62,584,830 85,517,484 546,409,741 130,292 3,282,338 2,123,630 5,703,534 2,027,215 1,895,952 9,013,566 5,485,365 560,291 21,102,853 441,602 423,147 -22,430 -411,599 52,189,785 -22,430 616,332,398 376,749,366 697,738,638 1,674,627,714 859,274,164 395,855,932 299,177,622 45,037,568 1,967,645 74,601,786 5,735,874,888 14,600,073 258,075,198 250,678,126 39,202,919 685,274 38,758,419 806,335 10,184,222 263,285,751 21,305,376 897,581,693 10,477,060 3,915,156 3,973,111 172,506 4,228 145,612 2,327,616 213,312 21,228,601 21,228,601 122,653,680 42,185,433 9,900,000 9,322,009 577,991 112,753,680 -9,322,009 41,607,442 FERC FORM NO. 1 (REV. 12-05) 207,213,264 140,830,608 1,134,576,414 151,481,294 539,431,138 493,717,503 37,567,321 34,619,490 Page 207 897,581,693 17,657,073,268 17,657,073,268 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: 20170406-8017 FERC PDF (Unofficial) (1) 03/31/2017 X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Date Originally Included Date Expected to be used Balance at Line Of Property in This Account in Utility Service End of Year No. (a) (b) (c) (d) 1 Land and Rights: 2 Roanoke Substation 12/31/1991 12/31/2025 282,772 11/30/2005 12/31/2017 2,004,206 12/31/1993 12/31/2025 592,651 10/31/2006 12/31/2025 401,193 12/31/2014 12/31/2025 320,827 5/31/2008 12/31/2017 653,352 12/31/2008 6/30/2018 746,020 10/31/2008 12/31/2020 1,929,113 5/1/2009 12/31/2025 427,534 22 Other General Parcels (2) 12/31/1999 12/31/2025 281,560 23 Other Transmission Parcels (2) 12/31/1999 12/31/2025 92,023 24 Other Distribution Parcels (4) 12/31/1999 12/31/2025 556,005 3 35th Ave. & Roanoke Ave., Phoenix, AZ 4 Prescott Service Center Office 5 Prescott, AZ 6 Madison Substation 7 11th St. & Jackson St., Phoenix, AZ 8 Paradise Substation 9 15021 N. 33rd Place, Phoenix, AZ 10 Punkin Center Substation 11 146 E. Purtill Trail, Tonto Basin, AZ 12 Buckeye to Elianto (SV4) Transmission Line 13 Township 010N 030W Sec 7; Buckeye, AZ 14 Payson Substation 15 Township100N 100E Sec2; Payson, AZ 16 Via Dona (NE2) Substation 17 118th Place & Via Dona Rd; Scottsdale, AZ 18 Citrus (WS4) Substation 19 Parcel 502-40-267 /T01NR02W.S10/ 2.633 acres 20 21 Other Property: 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) 8,558,796 Page 214 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Date Originally Included Date Expected to be used Balance at Line Of Property in This Account in Utility Service End of Year No. (a) (b) (c) (d) 1 Land and Rights: 2 Yavapai to Wellfield 3 11/30/2016 1/1/2027 271,540 Township 015N 001W; Yavapai, AZ 4 5 6 7 8 9 10 11 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) 8,558,796 Page 214.1 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) (a) 1 Generation Plant 2 3 Ocotillo Modernization Project 162,912,606 4 Four Corners F5 Selective Catalytic Reduction System 113,319,478 5 Four Corners F4 Selective Catalytic Reduction System 111,043,240 6 Palo Verde Nuclear Admin And Technical Manual Replacement 20,655,694 7 Palo Verde NRC Cyber Security Manual 8,332,058 8 Four Corners F5 Lf Field And Stator Rewind 6,319,988 9 Navajo Reliability Projects 5,714,658 10 Palo Verde Polar Crane U2 4,478,812 11 Palo Verde Dig Upgrade Generex U1 4,284,723 12 Palo Verde Seismic Hazards Validation 3,844,910 13 Palo Verde Security Access Control Fire Protect 3,143,754 14 Palo Verde Wrf Clarifiers Life Extension 2,900,219 15 Four Corners Motors, Pumps And Valves Replacements 2,836,694 16 West Phoenix Well No. 9 Replacement 2,565,478 17 Palo Verde Probalistic Risk Assessment Software 2,514,547 18 Four Corners U4 Pendant Rh/Outlet Header Replacement 2,305,986 19 Yucca Major Overhaul 2,135,136 20 Sundance Sd34 Gsu Replacement 1,850,817 21 Four Corners F5 Coal Silo Wall Replacement 1,817,323 22 Palo Verde Sp666 Replacement Of Sp Filtration System U3 1,761,762 23 Four Corners Coal Silo Section Replacement 1,604,599 24 Palo Verde Sp Pump Capital Spare 1,549,691 25 West Phoenix Major Overhaul- Capital Cc1 1,505,128 26 Palo Verde Rcp Motor Replacement 1R20 1,452,580 27 Palo Verde Loss Of Phase Detection System 1,408,332 28 Four Corners F45 Common Facility Building Repl 1,339,108 29 Palo Verd Best Estimate Loss Of Coolant Accident Manual Replacement 1,236,058 30 Four Corners Environmental Projects 1,140,961 31 Four Corners F5 Absorber Module Overhaul 5Nc 1,122,100 32 Palo Verde Wrf Domestic Water Well "A" 1,071,688 33 Palo Verde Cd-1218 - Lp Fw Heater 2B Replacement U1 1,045,596 34 Minor Generation Projects Less Than $1 Million 36,365,847 35 36 Transmission 37 38 Palo Verde - Morgan 500Kv Transmission System 27,057,375 39 North Gila - Ts8 230 Substation And Line Additions/Improvements 16,767,238 40 Mazatzal 345/69 Substation And Line Additions/Improvements 4,329,769 41 Komatke 69 Switchyard Additions/Improvements 3,930,358 42 East End - Raintree 69 Line Additions/Improvements 3,863,693 43 TOTAL FERC FORM NO. 1 (ED. 12-87) 878,382,780 Page 216 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 2,273,603 (a) 1 ANPP 500 Kv Transmission System 2 Pinal Central - Sundance 230 Line Additions/Improvements 1,408,845 3 Other Other Transmission Less Than $1 Million 10,433,141 4 5 Distribution 6 7 Underground Service-Line Extension -Non Residential 9,083,660 8 Solar Partners Com And App Cost Phase 1 8,698,308 9 Smart Grid Adms Rtus Dual-Port 7,754,546 10 Underground Cable Replacement 6,255,370 11 Residential Underground Distribution Lines Additions/Improvements 4,622,527 12 Cochise County East Side Solution Substion Additions/Improvements 3,558,606 13 Utting Substation Additions/Improvements 3,556,579 14 Smart Grid Super Control Switch 3,549,170 15 Network Protectors 3,181,133 16 Integrated Volt-Var Control System Installations 1,967,672 17 Solar Innovation Study 1,863,804 18 AT&T 4 Network Transformers 1,851,915 19 Delano - Add New Feeder Breaker 1,299,217 20 New Daisy Mountain Anthem Substation 1,271,147 21 Customer Interconnection For Additional Load 1,127,251 22 Wood Pole Replacement 1,041,807 23 Other Distribution Less Than $1 Million 15,901,567 24 25 Unplanned Emergency - Transmission And Distribution 8,791,081 26 Highway Line Relocation - Transmission And Distribution 5,749,397 27 Planned Overhead Line Replacements - Transmission And Distribution 3,551,589 28 29 General & Intangible 30 31 Customer Information System Replacement 72,490,989 32 2020 Vision-Adms 39,607,196 33 Ems Upgrade Project 15,858,428 34 New Prescott Service Center Construction 14,575,128 35 800 Mhz Radio Request For Proposal 12,392,980 36 NERC Cip Compliance 2016 9,246,827 37 Corporate Headquarters Elevator Modernization 7,214,811 38 Miscelaneous Building Projects 4,434,837 39 T&D Consolidated Communication Plan 4,022,584 40 Data Analytics 3,339,694 41 Palo Verde Ingress/Egress Parking Lot Modification 2,568,035 42 Hardware/Software License Maintenance Renewal Program 2,318,000 43 TOTAL FERC FORM NO. 1 (ED. 12-87) 878,382,780 Page 216.1 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 2,152,468 (a) 1 Maximo Meter Asset Project 2 Miscellaneous Non-Building Projects 1,048,578 3 Minor General Projects Less Than $1 Million 6,792,286 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 TOTAL FERC FORM NO. 1 (ED. 12-87) 878,382,780 Page 216.2 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 5,678,404,960 5,678,404,960 388,363,026 388,363,026 4,380,701 4,380,701 1,488,189 1,488,189 506,214 506,214 394,738,130 394,738,130 121,813,603 121,813,603 13 Cost of Removal 36,093,229 36,093,229 14 Salvage (Credit) 15,188,492 15,188,492 15 TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14) 142,718,340 142,718,340 16 Other Debit or Cr. Items (Describe, details in footnote): -16,845,125 -16,845,125 5,913,579,625 5,913,579,625 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 1,156,978,896 1,156,978,896 21 Nuclear Production 1,554,353,737 1,554,353,737 24 Other Production 626,454,731 626,454,731 25 Transmission 760,899,219 760,899,219 1,591,928,007 1,591,928,007 222,965,035 222,965,035 5,913,579,625 5,913,579,625 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) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 FOOTNOTE DATA Schedule Page: 219 Line No.: 12 Column: b FERC Page 219 Column (b), Line 12 121,813,603 Gain/(Loss) on Disposition of Assets (633,328) FERC Page 204-207 Column (d), Line 5 760,267 FERC Page 204-207 Column (d), Line 48 - FERC Page 204-207 Column (d), Line 60 - General Plant Retirements 1,291,131 Other (10,477,993) FERC Page 204-207 Column (d), Line 104 112,753,680 Schedule Page: 219 Line No.: 16 Column: b 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 (2,149,020) (1,124,716) (332,041) 0 (3,084,696) (7,429,425) (2,936,533) 211,306 (16,845,125) FERC FORM NO. 1 (ED. 12-87) Page 450.1 2016/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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) 38,345,560 20,069,909 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 120,438,920 131,249,414 8 Transmission Plant (Estimated) 7 Production Plant (Estimated) 34,331,669 38,401,294 9 Distribution Plant (Estimated) 77,675,882 81,991,917 490,631 426,749 232,937,102 252,069,374 1,296,535 707,530 272,579,197 272,846,813 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) 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) (1) 03/31/2017 X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 Sales: 23 Surrender to EPA 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) 2017 Current Year No. (b) Amt. (c) No. (d) 251,064.00 Amt. (e) 48,487.00 3,733.00 27,738.00 27,738.00 219,593.00 48,487.00 533.00 533.00 533.00 533.00 533.00 Page 228a 35 35 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Allowances (Accounts 158.1 and 158.2) Year/Period of Report End of 2016/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. 2018 No. (f) 48,487.00 2019 Amt. (g) No. (h) 48,487.00 Amt. (i) Future Years No. Amt. (j) (k) 1,260,662.00 Totals No. (l) 1,657,187.00 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 3,733.00 27,738.00 48,487.00 48,487.00 1,309,149.00 27,738.00 1,674,203.00 533.00 533.00 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 11 11 1,066.00 46 46 36 37 38 39 40 41 42 43 44 45 46 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 228 Line No.: 44 Column: c Line No.: 44 Column: k Line No.: 44 Column: m Line No.: 45 Column: c Line No.: 45 Column: k Line No.: 45 Column: m 34.91 Schedule Page: 228 11.8 Schedule Page: 228 45.99 Schedule Page: 228 34.91 Schedule Page: 228 11.8 Schedule Page: 228 45.99 FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) (1) 03/31/2017 X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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) 2017 Current Year No. (b) Amt. (c) Page 228b No. (d) Amt. (e) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Allowances (Accounts 158.1 and 158.2) Year/Period of Report End of 2016/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. 2018 No. (f) Future Years 2019 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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: 20170406-8017 FERC PDF (Unofficial) (1)03/31/2017 An Original X Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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. Line Reimbursements 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,WA348466 23 FACIL STDY,WA352878 50,727 143 ( ( 160,000) 143 1,844) 143 143 24 FACIL STDY,WA358556 75,676 143 ( 250,000) 143 25 FACIL STDY,WA359618 62,125 143 ( 500,000) 143 26 FACIL STDY,WA359805 53,275 143 ( 160,000) 143 ( 160,000) 143 27 FACIL STDY,WA359997 68,168 143 28 SMG SISSTD,WA310005 53,694 143 143 29 SMG SISSTD,WA310886 2,049 143 143 30 SMG SISSTD,WA353938 196 143 143 31 SMG SISSTD,WA354422 196 143 32 SYSIMPTSTD,WA173723 ( 33 SYSIMPTSTD,WA205085 34 SYSIMPTSTD,WA223536 1,000) 143 77,077) 143 250,000 143 4 143 143 359) 143 143 35 SYSIMPTSTD,WA305310 ( 65,032) 143 500,000 143 36 SYSIMPTSTD,WA307280 ( 40,067) 143 160,000 143 37 SYSIMPTSTD,WA309370 ( 54,132) 143 160,000 143 38 SYSIMPTSTD,WA333894 ( 28,805) 143 160,000 143 39 SYSIMPTSTD,WA334372 ( 1,742) 143 143 40 SYSIMPTSTD,WA334374 ( 2,042) 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) (1)03/31/2017 An Original X Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/Q4 Transmission Service and Generation Interconnection Study Costs (continued) Line No. 1 Description (a) Costs Incurred During Period (b) Account Charged (c) Reimbursements Received During the Period (d) Account Credited With Reimbursement (e) Transmission Studies 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Generation Studies 22 SYSIMPTSTD,WA334485 40,649 143 143 23 SYSIMPTSTD,WA334605 58,509 143 143 24 SYSIMPTSTD,WA334709 ( 1,896) 143 143 25 SYSIMPTSTD,WA334712 ( 4,030) 143 143 26 SYSIMPTSTD,WA334713 ( 4,030) 143 143 27 SYSIMPTSTD,WA342410 ( 1,307) 143 143 28 SYSIMPTSTD,WA351491 ( 897) 143 143 29 SYSIMPTSTD,WA352111 ( 3,587) 143 143 30 SYSIMPTSTD,WA353816 ( 1,654) 143 143 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) CREDITS Written off During Written off During the Quarter/Year the Period Account Charged Amount (d) (e) Debits (c) 34,750,848 Balance at end of Current Quarter/Year (f) 35,595,335 844,487 2 Amortize through 2036 3 4 Capital Contribution on Phoenix-Mead Transmission 108 11,372,400 332,041 11,040,359 5,423,595 158,423,281 5 U-1345-90-269 Amortize through 2050 6 7 Income Taxes - AFUDC Equity 24,640,241 various 139,206,635 8 E-01345A-03-0437 Amortize through 2046 9 10 AG-1 Deferral 5,867,920 5,867,920 11 E-01345A-11-0224 12 13 Decontamination 5,286 407 5,286 3,519,999 190 1,801,641 1,718,358 48,990,754 12,465,037 98,585,613 42,962,517 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 61,455,791 various 20 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 21 Amortize through 2017 22 23 Deferred Fuel and Purchased Power Mark-to-Market 141,548,130 24 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 25 Amortize through 2020 26 27 Deferred Fuel and Purchased Power - Interest 60,245 60,245 28 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 29 Amortize through 2018 30 31 Navajo Coal Reclamation 6,502,663 ( 485,000) 501 417,889 571 4,543,164 5,599,774 32 E-01345A-08-0172 Amortize through 2026 33 34 Transmission Vegetation Management 4,543,164 35 ER11-3468-000 Amortize through 2016 36 37 Spent Nuclear Fuel 372,189 518 372,189 38 ER11-3468-000 Amortize through 2017 39 40 Pension and Other Postretirement Benefits 127,719,936 various 619,222,919 35,884,292 711,058,563 41 E-01345A-08-0172 42 43 Demand Side Management 44 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 3,744,147 3,744,147 1,334,174,106 Page 321,470,051 232 268,054,139 1,387,590,018 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) CREDITS Written off During Written off During the Quarter/Year the Period Account Charged Amount (d) (e) Debits (c) Balance at end of Current Quarter/Year (f) 1 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 2 Amortize through 2017 3 4 Income Taxes - Change in Rates 2,985,864 ( 15,081) 283 47,907 2,922,876 13,683,807 ( 69,525) various 1,512,269 12,102,013 8,129,251 various 1,881,513 56,476,151 5 Amortize through 2046 6 7 Income Taxes - Medicare Subsidy 8 Amortize through 2024 9 10 Income Taxes - Investment Tax Credit Basis Adjustmt 50,228,413 11 Amortize through 2046 12 13 Property Tax Deferral 73,199,778 50,452,422 22,747,356 45,506,450 62,648,771 400 46,848,244 61,306,977 2,942,299 3,811,182 400 5,165,470 1,588,011 1,859) 403 9,925,740 127,504,281 407 6,688,721 63,582,206 268,054,139 1,387,590,018 14 E-01345A-11-0224 15 16 Lost Fixed Cost Recovery 17 E-01345A-11-0224 18 Amortize through 2017 19 20 FERC Transmission Cost Adjustor 21 Amortize through 2018 22 23 Retired Power Plant Costs 137,431,880 ( 24 Amortize through 2033 25 26 Four Corners Cost Deferral 70,270,927 27 Amortize through 2024 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 1,334,174,106 Page 321,470,051 232.1 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 232 283, 410.1 Schedule Page: 232 Line No.: 7 Column: d Line No.: 19 Column: d Line No.: 40 Column: d Line No.: 7 Column: d 411.8, 426.5, 555 Schedule Page: 232 228.3, 926 Schedule Page: 232.1 283, 410.1 Schedule Page: 232.1 Line No.: 10 Column: d 283, 410.1 FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 Deferred Lease Payments (Through 2045) Redhawk Effluent Water Balance at Beginning of Year Debits (b) 93,901,760 CREDITS Account Charged (d) 257,555 931 (c) Amount (e) 3,391,613 Balance at End of Year (f) 90,767,702 200,000 143,750 232 143,750 200,000 Information Sys Leases & Maint. 7,258,966 5,077,958 165 2,449,681 9,887,243 Unamortized Arrangement Fees (Through 2021) 3,662,428 2,429,866 431,525 2,532,566 3,559,728 Transmission Debits (Through 2017) 7,542,591 1,027,881 6,514,710 Prepaid Payroll Agreements Prepaid Water Supply Agreements (Through 2050) 565 294,601 294,601 7,268,424 165 Debt Shelf Registration Freight in Transit Prepaid Monitoring Services (2014 to 2023) 176,738 various 176,738 340,368 232 84,233 340,368 713,597 165 44,387 669,210 11,438,550 165 11,438,550 790,494 Four Corners NEPA (Through 2041) Minor Items 7,048,655 84,233 Long Term Prepaid Insurance Rapid Response Center Equipment 219,769 407,331 232 790,494 4,547,758 506 4,547,758 1,114,527 various 1,545,478 -23,620 47 Misc. Work in Progress Deferred Regulatory Comm. 48 Expenses (See pages 350 - 351) 49 TOTAL FERC FORM NO. 1 (ED. 12-94) 122,124,425 124,596,849 Page 233 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 233 Line No.: 19 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) 03/31/2017 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 80,616,150 40,149,112 3 Pension and Other Post Retirement Liabilities 2 Risk Management Activities 181,786,916 194,981,280 4 Regulated Liabilities - Asset Retirement Obligation 107,885,455 107,958,597 5 Regulated Liabilities - Other 245,681,167 238,008,304 6 Other 236,971,165 245,477,196 852,940,853 826,574,489 852,940,853 826,574,489 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 Date of Report (Mo, Da, Yr) 03/31/2017 This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 1,314,677 4 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. Series 1998 16,870,000 162,004 5 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 12,850,000 125,419 6 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series B 26,710,000 157,868 7 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series D 32,000,000 -70,591 8 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series E 32,000,000 -90,685 9 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series A 35,975,000 576,013 10 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series C 11 Subtotal 32,000,000 445,268 303,555,000 3,682,944 200,000,000 2,049,339 12 13 Other Long Term Debt Account 224 14 5.625% Unsecured Senior Note 15 2,288,000 D 16 5.500% Unsecured Senior Note 250,000,000 17 18 6.250% Unsecured Senior Note 250,000,000 19 1,659,703 1,355,000 D 20 6.875% Unsecured Senior Note 150,000,000 1,333,769 500,000,000 4,301,413 300,000,000 3,096,550 21 226,500 D 22 8.750% Unsecured Senior Note 23 275,000 D 24 5.05% Unsecured Senior Note 25 2,022,000 D 26 4.50% Unsecured Senior Note 325,000,000 27 3,321,373 3,074,500 D 28 4.50% Unsecured Senior Note 100,000,000 29 1,148,640 -5,182,000 P 30 4.7% Unsecured Senior Note 250,000,000 31 2,501,050 1,000,000 D 32 3.35% Unsecured Senior Note 250,000,000 33 TOTAL FERC FORM NO. 1 (ED. 12-96) 2,362,692 2,147,500 D 4,458,241,078 Page 256 2,080,950 52,047,927 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 1 Total expense, Premium or Discount (c) 230,000 D 2 2.20% Unsecured Senior Note 250,000,000 2,103,800 300,000,000 2,384,360 3 35,000 D 4 3.15% Unsecured Senior Note 5 1,578,000 D 6 4.35% Unsecured Senior Note 250,000,000 7 2,518,924 460,000 D 8 3.75% Unsecured Senior Note 350,000,000 9 3,691,995 1,004,500 D 10 2.55% Unsecured Senior Note 250,000,000 11 2,118,925 1,157,500 D 12 APS Term Loan 2015 50,000,000 10,000 13 APS Term Loan 2016 100,000,000 10,000 14 15 COLI LOANS (Option II Benefits) 29,686,078 16 17 Subtotal 4,154,686,078 48,364,983 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 TOTAL FERC FORM NO. 1 (ED. 12-96) 4,458,241,078 Page 256.1 52,047,927 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 65,750,000 3,090,250 3 202,978 4 9/14/94 9/01/24 9/14/94 9/01/24 11/16/98 11/01/33 11/16/98 11/01/33 2 5/28/09 6/01/34 5/28/09 6/01/34 24,067 5 9/22/09 4/01/38 9/22/09 4/01/38 235,598 6 5/28/09 6/01/34 5/28/09 6/01/34 766,667 7 5/28/09 6/01/34 5/28/09 6/01/34 766,667 8 6/26/09 5/01/29 6/26/09 5/01/29 35,975,000 233,714 9 6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 560,000 10 183,125,000 8,201,741 11 12 13 5/07/03 5/15/33 5/07/03 5/15/33 200,000,000 11,250,000 14 8/22/05 9/01/35 8/22/05 9/01/35 250,000,000 13,750,000 16 8/03/06 8/01/16 8/03/06 8/01/16 8/03/06 8/01/36 8/03/06 8/01/36 2/26/09 3/01/19 2/26/09 8/25/11 9/01/41 1/13/12 1/13/12 15 17 9,114,583 18 150,000,000 10,312,500 20 3/01/19 500,000,000 43,750,000 22 8/25/11 9/01/41 300,000,000 15,150,000 24 4/01/42 1/13/12 4/01/42 325,000,000 14,625,000 26 4/01/42 1/13/12 4/01/42 100,000,000 4,500,000 28 19 21 23 25 27 29 1/10/14 1/15/44 1/10/14 1/15/44 250,000,000 11,750,000 30 6/18/14 6/15/24 6/18/14 6/15/24 250,000,000 8,375,000 32 4,087,811,078 188,460,145 33 31 FERC FORM NO. 1 (ED. 12-96) Page 257 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) Interest for Year Amount (i) Line No. 1 1/12/15 1/15/20 1/12/15 1/15/20 250,000,000 5,454,167 2 5/19/15 5/15/25 5/19/15 5/15/25 300,000,000 9,450,000 4 11/06/15 11/15/45 11/06/15 11/15/45 250,000,000 10,875,000 6 3 5 7 5/06/16 5/15/46 5/06/16 5/15/46 350,000,000 8,750,000 8 9/20/16 9/15/26 9/20/16 9/15/26 250,000,000 1,770,833 10 6/26/15 6/26/18 6/26/15 6/26/18 50,000,000 547,432 12 4/22/16 4/22/19 4/22/16 4/22/19 100,000,000 833,889 13 9 11 14 29,686,078 15 16 3,904,686,078 180,258,404 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 4,087,811,078 FERC FORM NO. 1 (ED. 12-96) Page 257.1 188,460,145 33 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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.: 15 Column: h The change in the loan balance for the Coli Loan is as follows: Total outstanding balance @ 12/31/15 2016 death repayments 2016 net premiums 2016 net interest Balance outstanding @ 12/31/16 Schedule Page: 256.1 Line No.: 17 $ 28,695,075 (775,959) 497,514 1,269,447 $ 29,686,078 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) Page 450.1 $ 189,828,017 $ (1,054,867) (239,572) (73,433) 188,460,145 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. Line Particulars (Details) No. (a) 1 Net Income for the Year (Page 117) Amount (b) 462,140,944 2 3 4 Taxable Income Not Reported on Books 5 Contributions in Aid of Construction 44,316,954 6 Tax Gain/Loss on Sale of Business Property -11,340,051 7 Other Taxable Income Not Reported on Books 1,374,125 8 9 Deductions Recorded on Books Not Deducted for Return 10 Book Depreciation and Amortization 561,348,108 11 Income Tax Per Books 246,004,507 12 Pension and Other Post-Retirement Benefits 10,794,568 13 Other Deductions Recorded on Books Not Deducted for Return (see footn) 212,838,449 14 Income Recorded on Books Not Included in Return 15 Book Gain/Loss on Sale of Business Property -4,499,181 16 Mark-to-Market Adjustments -2,148,195 17 Cash Surrender Value -1,173,471 18 Other Income Recorded on Books Not Included in Return -1,536,950 19 Deductions on Return Not Charged Against Book Income 20 Tax Depreciation and Amortization -866,518,989 21 Expenditures Capitalized for Book Not Tax -192,785,394 22 Other Deductions on Return Not Charged Against Book Income (see footn) -341,613,545 23 24 25 26 27 Federal Tax Net Income 117,201,878 28 Show Computation of Tax: 29 ($117,201,877) * 35% 41,020,657 30 31 Tax Attributes Utilized -30,794,564 32 33 Net Current Year Federal Tax Expense 10,226,093 34 35 Other (includes 2015 Return-to-Provision) -10,040,137 36 37 Net Federal Tax Expense per Income Statement 185,956 38 39 40 41 42 43 44 FERC FORM NO. 1 (ED. 12-96) Page 261 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 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: 261 198,412,345 7,543,947 6,882,157 $ 212,838,449 Line No.: 22 Column: b Other Deductions on Return Not Charged Against Book Income consists of the following: Book Accrued Expenses - Beginning of Year Pension and Other Post Retirement Benefits Regulatory Accounting Adjustments Contributions to Qualified Decommissioning Fund State Taxes Other Total FERC FORM NO. 1 (ED. 12-87) (188,266,812) (80,743,416) (59,688,667) (2,280,968) (6,619,114) (4,014,568) $(341,613,545) Page 450.1 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 20,954,724 2 FICA 3 Unemployment Taxes Charged During Year (d) 185,956 Taxes Paid During Year (e) 23,211,557 49,951,845 49,951,845 291,154 291,154 4 Heavy Vehicle Use -50,375 5 Fuel Tax -26,174 90,743 6 Subtotal 20,878,175 50,519,698 73,531,989 8,376,992 15,250,218 16,613,263 318,646 93,702 356,778 79,740 79,740 Adjustments (f) 89,959 -12,526 7 8 New Mexico: State and Local 9 Real and Personal Property 10 Income 11 Unemployment 12 Sales 13 Use -14,453 -286 8,368 10,305 8,680,899 15,432,028 17,060,086 89,034,216 178,652,310 178,388,837 1,039,372 4,187,667 3,126,882 17,002,047 265,332,110 264,857,041 21 State and City Use 1,512,753 20,073,964 21,214,830 22 State and City Tax Reserve 6,455,985 1,106,587 277,065 1,054,219 1,054,219 470,406,857 468,918,874 113,997 113,997 113,997 113,997 27,583 27,583 2,488 218,354 168,544 2,488 245,937 196,127 154,011,438 536,718,517 559,821,073 14 Subtotal 15 16 Arizona: State and Local 17 Real and Personal Property 18 Income 19 Diesel Fuel 20 State and City Sales 23 Unemployment 24 Subtotal 115,044,373 -1,062,000 -1,062,000 25 26 NV Real and Personal 27 Unemployment 28 Subtotal 29 30 California: State and Local 31 Real and Personal Property 32 Income 33 Unemployement 34 Subtotal 35 36 Utah: State 37 Income 38 Subtotal 39 40 41 TOTAL FERC FORM NO. 1 (ED. 12-96) Page 262 -129,488 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 9,405,503 932,512 9 Subtotal 9,405,503 932,512 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) 154,011,438 536,718,517 Page 262.1 559,821,073 -129,488 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. DISTRIBUTION OF TAXES CHARGED BALANCE AT END OF YEAR Extraordinary Items Prepaid Taxes (Taxes accrued Electric (Incl. in Account 165) (Account 408.1, 409.1) (Account 409.3) Account 236) (g) (h) (i) (j) 11,312,626 13,381,881 4,925,542 25,375,412 -49,591 Adjustments to Ret. Earnings (Account 439) (k) Other (l) -4,739,586 1 24,576,432 2 291,154 3 90,743 -13,648 11,249,387 Line No. 4 5 13,381,881 30,300,954 20,218,743 6 7 8 7,013,948 15,250,218 -55,570 9 115,094 -21,392 10 79,740 11 -14,453 12 -2,221 6,997,274 -55,570 15,365,312 8,368 13 66,716 14 15 16 89,297,689 -2,100,157 151,376,890 27,275,420 4,873,606 -685,939 17 18 19 17,477,116 371,896 6,223,507 113,370,208 -989,292 -2,100,157 155,261,204 265,332,110 20 20,073,964 21 1,033,879 22 1,054,219 23 314,083,653 24 25 113,997 26 113,997 28 27 29 30 27,583 -52,298 31 230,202 -11,848 32 33 -52,298 257,785 -11,848 34 35 36 37 38 39 40 141,954,872 FERC FORM NO. 1 (ED. 12-96) 11,173,856 201,299,252 Page 335,289,776 263 41 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 10,338,003 932,512 8 10,338,003 932,512 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 40 141,954,872 FERC FORM NO. 1 (ED. 12-96) 11,173,856 201,299,252 Page 335,289,776 263.1 41 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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% 183,579 255 6 30% 186,896,843 255 30,194,355 420 81,816 420 7,030,670 7 8 TOTAL 187,080,422 30,194,355 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 7,112,486 Name of Respondent This Report Is: Date of Report Year/Period of Report (Mo, Da, Yr) 2016/Q4 End of Arizona Public Service Company 03/31/2017 (2) A Resubmission ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Balance at End of Year (h) 101,763 210,060,528 Average Period of Allocation to Income (i) ADJUSTMENT EXPLANATION Line No. 1 2 3 4 5 6 7 8 9 1.24 years 29.88 years 210,162,291 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 $23,099 is associated with transmission investments. Schedule Page: 266 Line No.: 8 Column: h $12,611 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) 03/31/2017 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 (b) 4,806,955 DEBITS Contra Account (c) 182.3 Amount (d) Credits Balance at End of Year (e) (f) 954,137 131,359 3,984,177 4,934,570 6,618,006 195,996,820 2 3 Coal Reclamation 194,313,384 232 4 5 Navajo Retiree Health Care Costs 7,670,497 182.3, 501 594,984 3,573,000 10,648,513 5,979,579 131 912,188 284,777 5,352,168 300,000 143 50,000 143 701,638 165, 555 6 7 Legal Reserves 8 9 Imperial Irrigation Prepaid O&M 300,000 10 11 Construction Advances 50,000 12 13 Land Lease Obligations 14 139,668 841,306 Through 2048 15 16 Interconnection Studies 1,748,389 143 16,380,547 19,014,204 4,382,046 3,174,156 143 5,606,417 2,721,070 288,809 2,378,107 930.2 2,394,093 2,939,332 2,923,346 17 18 Retention 19 20 License Fees 21 22 Leasehold Improvements 23 51,331 131 208,822 170,661 13,170 45,990 131 73,363 85,371 57,998 19,669,473 232, 567 817,979 506,995 19,358,489 19,919,600 232 12,044,400 7,652,000 15,527,200 1,922,000 501 1,922,000 5,189,847 509, 242 2,726,174 7,224,233 1,157,965 1,426,513 Through 2017 24 25 Escheated Funds 26 27 SCE Right of Way 28 29 Tolling Agreements 30 31 Coal Severance Surtax Reserve 32 33 Carbon Allowance 691,788 34 35 OCC Modernization Overland Retentn 36 268,548 107 700,000 456 150,000 107 2,750,000 2,750,000 50,485,288 50,470,582 Through 2018 37 38 House Warranty Program 39 550,000 Through 2020 40 41 Solar Plant Insurance Proceeds 42 43 44 45 46 47 TOTAL FERC FORM NO. 1 (ED. 12-94) 268,889,494 Page 269 268,874,788 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 3,007,871,747 711,492,264 513,556,259 3,007,871,747 711,492,264 513,556,259 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 24,924,048 -161,860 3,032,795,795 711,330,404 513,556,259 2,692,585,203 613,082,342 423,965,558 340,210,592 98,248,062 89,590,701 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 3,205,807,752 2 3 4 3,205,807,752 5 6 7 24,762,188 8 3,230,569,940 9 10 2,881,701,987 11 348,867,953 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 54,109,619 77,436,825 70,458,426 4 Reg Assets - Mark to Market 55,019,758 1,996,239 35,619,902 5 Reg Assets - Pension and Other 240,691,949 38,668,447 5,176,213 6 Reg Assets - Other 172,585,228 29,418,656 18,942,935 7 Mark to Market 20,744,281 6,033,968 3,244,556 8 Other 66,406,574 22,260,490 29,464,242 609,557,409 175,814,625 162,906,274 609,557,409 175,814,625 162,906,274 527,524,018 149,308,009 134,155,735 82,033,391 26,506,616 28,750,539 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 61,088,018 3 21,396,095 4 274,184,183 5 183,060,949 6 2,404,301 21,129,392 7 59,202,822 8 2,404,301 620,061,459 9 10 11 12 13 14 15 16 17 18 2,404,301 620,061,459 19 20 2,182,327 540,493,965 221,974 79,567,494 21 22 23 NOTES (Continued) FERC FORM NO. 1 (ED. 12-96) Page 277 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) 8,000,000 DEBITS Account Credited (c) Amount Credits (d) (e) (f) 2,000,000 456 Balance at End of Current Quarter/Year 6,000,000 2 U-1345-90-269 Amortize through 2019 3 4 Asset Retirement Obligation 277,554,553 2,421,058 279,975,611 507,393) 729,876 71,725,574 3,839,028 16,254,446 113,194,633 1,609,200 15,287,400 858,891 75,592,485 5 FERC Order# 552 6 Amortize through 2057 7 8 Spent Nuclear Fuel Storage 70,488,305 518 100,779,215 190 ( 9 E-01345A-03-0437, E-01345A-05-0816, -0826, 10 -0827 Amortize through 2047 11 12 Income Taxes - Unamortized Investment Tax Credit 13 E-01345A-05-0816,-0826,-0827 14 Amortize through 2046 15 16 Sundance Maintenance 13,678,200 17 E-01345A-05-0816,-0826,-0827 18 Amortize through 2030 19 20 Income Tax - Change in Rates 76,552,911 various 1,819,317 21 Amortize through 2045 22 23 Amonix Promissory Note 6,161,929 6,161,929 24 Amortize through 2018 25 26 Renewable Energy Standard 47,337,673 400 133,205,838 112,677,365 26,809,200 27 E-01345A-03-0437,E-01345A-05-0816,-0826, 28 -0827 Amortize through 2017 29 30 Star Center Patent Rights 1,125,393 1,125,393 31 E-01345A-09-0357 32 Amortize through 2018 33 34 AZ Sun Program 800,130 400 800,130 3,520,000 190 1,801,641 25,193,308 908 56,053,075 51,332,012 20,472,245 259,672,459 194,258,592 814,110,646 35 E-01345A-09-0338 36 37 Excess Deferred Taxes 1,718,359 38 Amortize through 2019 39 40 Demand Side Management 41 TOTAL FERC FORM NO. 1/3-Q (REV 02-04) 879,524,513 Page 278 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) Balance at Begining of Current Quarter/Year (b) DEBITS Account Credited (c) Amount Credits (d) (e) Balance at End of Current Quarter/Year (f) 1 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 2 Amortize through 2019 3 4 Other Postretirement Benefits 213,620,450 228.3 33,164,494 ( 23,880,713) 156,575,243 400 13,965,140 12,862,074 539,364 440,219 13,982,876 5 E-01345A-08-0172 6 7 FERC Transmission True Up 1,642,430 8 Amortize through 2017 9 10 Removal costs Cholla 13,542,657 11 Amortize through 2033 12 13 Power Supply Adjuster 9,687,507 547, 555 9,687,507 421 1,151,674 14 Amortize through 2016 15 16 Power Supply Adjuster Interest 864,006 287,668 17 Amortize through 2017 18 19 Power Supply Adjuster Marked to Market 1,745,094 1,745,094 12,019,764 18,247,507 4,901,638 4,957,733 194,258,592 814,110,646 20 Amortize through 2017 21 22 Four Corners Coal Reclamation 8,919,751 501 2,692,008 23 E-013454A-05-0816, -0826, -0827 24 Amortize through 2031 25 26 Deferred Gain on Sale of Property 56,095 27 Amortize through 2018 28 29 30 31 32 33 34 35 36 37 38 39 40 41 TOTAL FERC FORM NO. 1/3-Q (REV 02-04) 879,524,513 Page 278.1 259,672,459 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 278 Line No.: 20 Column: c 190, 410.1, 411.1 FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 1,729,900,602 1,701,967,569 1,392,292,595 1,375,003,302 190,274,858 186,410,252 22,578,875 22,444,231 181,677 187,560 3,335,228,607 3,286,012,914 119,366,602 176,840,127 3,454,595,209 3,462,853,041 3,454,595,209 3,462,853,041 16 (450) Forfeited Discounts 8,154,228 8,400,013 17 (451) Miscellaneous Service Revenues 9,339,995 9,290,021 6,898,303 -1,185,197 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 7,800,261 5,519,062 29,548,008 34,768,234 61,740,795 56,792,133 3,516,336,004 3,519,645,174 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. MEGAWATT HOURS SOLD Year to Date Quarterly/Annual AVG.NO. CUSTOMERS PER MONTH Amount Previous year (no Quarterly) (d) Current Year (no Quarterly) (f) (e) Previous Year (no Quarterly) (g) Line No. 1 13,195,346 13,159,754 1,061,814 1,046,989 2 3 12,411,366 12,364,153 126,662 125,579 4 2,267,688 2,275,533 3,845 3,744 5 144,857 148,229 1,037 1,028 6 2,745 2,822 153 154 7 8 9 28,022,002 27,950,491 1,193,511 1,177,494 10 3,906,044 5,678,363 46 47 11 31,928,046 33,628,854 1,193,557 1,177,541 12 13 31,928,046 Line 12, column (b) includes $ Line 12, column (d) includes FERC FORM NO. 1/3-Q (REV. 12-05) 33,628,854 10,889,885 54,835 of unbilled revenues. MWH relating to unbilled revenues Page 301 1,193,557 1,177,541 14 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 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 $ $ 2,469,947 2,000,000 992,672 910,000 850,845 754,872 718,717 272,033 173,763 129,360 100,106 46,959 (1,619,013) 7,800,261 Column: c PCS Project PacifiCorp CT Deferred Gain Amortization Fuel Loading Facility Charges Effluent Water Rights Fee FERC FORM NO. 1 (ED. 12-87) 9,287,522 2,499 9,290,021 Column: b PCS Project PacifiCorp CT Deferred Gain Amortization Fuel Loading Bid Fee Proceeds Effluent Water Rights Fee Management/Administration Fees Facility Charges Other Home Warranty Program Participant Station Power Revenue Call Center Referrals Risk Management Surepay and Autopay Discount Total Schedule Page: 300 9,291,197 48,798 9,339,995 $ 2,596,707 2,000,000 985,646 946,676 682,764 Page 450.1 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Management/Administration Fees Other Call Center Referrals Participant Station Power Revenue Home Warranty Program Redhawk Miscellaneous Revenue Risk Management Surepay and Autopay Discount Total FERC FORM NO. 1 (ED. 12-87) $ 650,822 269,874 218,840 124,722 50,084 (9,426) (1,446,105) (1,551,542) 5,519,062 Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. MWh Sold Revenue Average Number KWh of Sales Revenue Per 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 3,728,697 529,403,680 470,273 7,929 0.1420 3 ET-1 1,913,943 247,522,334 120,768 15,848 0.1293 4 ET-2 4,460,085 581,887,029 304,510 14,647 0.1305 5 ECT-1R 2,171,852 254,316,612 94,484 22,986 0.1171 6 ECT-2 606,706 71,178,831 24,027 25,251 0.1173 7 ET-SP 28,660 3,713,296 2,051 13,974 0.1296 8 E-12 EPR-2,6 42,616 7,704,173 15,954 2,671 0.1808 9 ET-1 EPR-2,6 46,639 5,909,002 6,914 6,746 0.1267 10 ET-2 EPR-2,6 161,348 20,695,711 20,747 7,777 0.1283 17,667 2,684,650 1,375 12,849 0.1520 12 ECT-1R EPR-2,6 6,126 917,921 412 14,869 0.1498 13 ET-EV 7,249 843,843 299 24,244 0.1164 14 E-47 1,662 520,251 11 ECT-2 EPR-2,6 15 Green Power 16 Total Residential 0.3130 129,642 13,193,250 1,727,426,975 1,061,814 12,425 0.1309 17 18 442 Commercial 19 E-20 38,542 4,944,379 387 99,592 0.1283 20 E-30 4,952 1,272,551 4,337 1,142 0.2570 21 E-32 XS 1,468,934 239,780,723 98,717 14,880 0.1632 22 E-32 S 2,494,668 333,222,808 15,740 158,492 0.1336 23 E-32 M 2,807,201 307,619,810 3,650 769,096 0.1096 24 E-32 L 2,260,445 207,696,940 622 3,634,156 0.0919 5,422 862,421 249 21,775 0.1591 26 E-32 TOU S 26,727 3,406,541 127 210,449 0.1275 27 E-32 TOU M 69,328 7,217,733 70 990,400 0.1041 28 E-32 TOU L 178,786 16,043,287 41 4,360,634 0.0897 29 GS-Schools M 39,270 4,950,752 58 677,069 0.1261 30 GS-Schools L 38,437 4,408,589 27 1,423,593 0.1147 31 E-34 445,731 36,167,389 17 26,219,471 0.0811 32 E-35 852,276 61,022,133 18 47,348,667 0.0716 6,656 724,966 8 832,000 0.1089 25 E-32 TOU XS 33 E-36 M 576 611,803 1 576,000 1.0622 35 E-221 34 E-56 341,152 35,073,362 1,360 250,847 0.1028 36 EPR-2 7,608 776,802 22 345,818 0.1021 37 EPR-6 422,375 49,741,866 1,035 408,092 0.1178 38 E-56R 214,145 17,260,086 27 7,931,296 0.0806 39 AG-1 M & L 448,536 32,124,946 142 3,158,704 0.0716 11,669 632,503 1 11,669,000 0.0542 27,967,167 54,835 28,022,002 3,324,338,722 10,889,885 3,335,228,607 1,193,511 0 1,193,511 23,433 0 23,479 0.1189 0.1986 0.1190 40 AG-1 M & L TOU 41 42 43 TOTAL Billed Total Unbilled Rev.(See Instr. 6) TOTAL FERC FORM NO. 1 (ED. 12-95) Page 304 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. MWh Sold Revenue Average Number KWh of Sales Revenue Per Line Number and Title of Rate schedule KWh Sold Per Customer of Customers No. (a) (b) (c) (e) (f) (d) 1 AG-1 XL 118,718 7,901,109 4 29,679,500 0.0666 2 AG-1 XL TOU 40,820 2,760,512 3 E-47 20,426 8,451,918 4 Green Power 5 Total Commercial 2 20,410,000 0.0676 0.4138 164,686 12,363,400 1,384,840,615 126,662 97,609 0.1120 6 7 442 Industrial and Irrigation 8 E-30 58 17,412 72 806 0.3002 37,030 6,067,154 2,500 14,812 0.1638 10 E-32 S 88,884 13,491,460 694 128,075 0.1518 11 E-32 M 186,587 23,010,059 293 636,816 0.1233 12 E-32 L 9 E-32 XS 446,219 41,622,164 109 4,093,752 0.0933 13 E-32 TOU XS 276 35,698 7 39,429 0.1293 14 E-32 TOU S 804 94,920 3 268,000 0.1181 15 E-32 TOU M 3,299 408,423 5 659,800 0.1238 16 E-32 TOU L 39,975 3,751,878 9 4,441,667 0.0939 17 E-34 133,044 10,129,458 5 26,608,800 0.0761 18 E-35 750,762 52,524,065 15 50,050,800 0.0700 19 E-36 M 2,190 230,337 1 2,190,000 0.1052 20 E-36 XL 69,812 5,459,881 5 13,962,400 0.0782 650 171,659 22 E-221 10,904 1,127,757 96 113,583 0.1034 23 EPR-6 21,149 2,575,489 22 961,318 0.1218 945 117,384 2 472,500 0.1242 396,911 21,732,621 2 198,455,500 0.0548 73,393 6,742,607 5 14,678,600 0.0919 2,262,892 189,310,426 3,845 588,528 0.0837 21 E-47 24 AG-1 M & L 25 AG-1 XL TOU 26 Special Contracts 27 Total Industrial & Irrigation 0.2641 28 29 444 Public Street Lighting 144,880 22,579,029 1,037 139,711 0.1558 30 Total Public Street Lighting 144,880 22,579,029 1,037 139,711 0.1558 32 445 Other Public Authorities 2,745 181,677 153 17,941 0.0662 33 Total Other Public Authorities 2,745 181,677 153 17,941 0.0662 36 Residential Unbilled 2,096 2,473,627 1.1802 37 Commercial Unbilled 47,966 7,451,980 0.1554 4,796 964,432 0.2011 -23 -154 0.0067 27,967,167 54,835 28,022,002 3,324,338,722 10,889,885 3,335,228,607 31 34 35 Unbilled MWh & Revenue 38 Ind & Irrig. Unbilled 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 1,193,511 0 1,193,511 23,433 0 23,479 0.1189 0.1986 0.1190 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. MWh Sold Revenue Average Number KWh of Sales Revenue Per 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 54,835 10,889,885 0.1986 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) 27,967,167 54,835 28,022,002 3,324,338,722 10,889,885 3,335,228,607 Page 304.2 1,193,511 0 1,193,511 23,433 0 23,479 0.1189 0.1986 0.1190 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) (e) (f) (d) 0.190 0.190 0.189 (a) 1 Aguila Irrigation District Statistical Classification (b) RQ 2 Buckeye Irrigation District RQ 86306 0.005 0.005 0.005 3 City of Williams RQ MRT Vol 1 5.734 6.018 5.003 4 Electrical District No. 6 RQ 86307 0.011 0.011 0.011 5 Electrical District No. 7 RQ 86304 0.051 0.051 0.051 6 Electrical District No. 8 RQ 86310 1.241 1.241 1.240 7 Harquahala Valley Irrigation District RQ 86309 0.826 0.826 0.826 8 Maricopa County Municipal Water Conserv RQ 86058 0.113 0.113 0.113 9 McMullen Valley Irrigation District Line No. Name of Company or Public Authority (Footnote Affiliations) RQ 86311 1.536 1.536 1.535 10 Roosevelt Irrigation District RQ 86305 0.091 0.091 0.091 11 Tonopah Irrigation District RQ 86312 0.030 0.030 0.030 12 Town of Wickenburg RQ 85726 0.003 0.003 0.003 13 Constellation New Energy Inc. IF Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 14 Freeport-McMoRan Copper & Gold Energy C IF FERC FORM NO. 1 (ED. 12-90) Page 310 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) 1 Morgan Stanley Capital Group, Inc. Statistical Classification (b) IF 2 NextEra Energy Power Marketing LLC IF 3 Noble Americas Energy Solutions, LLC IF FERC Rate Schedule or Tariff Number (c) MRT Vol 3 4 Overton Power District #5 IF 5 Arizona Electric Power Cooperative SF WSPP 6 Bonneville Power Administration SF WSPP Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) MRT Vol 3 7 BP Energy Company SF WSPP 8 Brookfield Energy Marketing LP SF WSPP 9 California Independent System Operator SF MRT Vol 3 10 Cargill Power Markets, LLC SF WSPP 11 Central Arizona Water Conservation Dist SF WSPP MRT Vol 3 12 Citigroup Energy Inc. SF 13 Comision Federal de Electridad SF SA 14 ConocoPhillips Company SF WSPP Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.1 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) 1 EDF Trading North America LLC Statistical Classification (b) SF FERC Rate Schedule or Tariff Number (c) WSPP 2 El Paso Electric Company SF WSPP 3 Exelon Generation Company, LLC SF WSPP 4 Guzman Energy, LLC SF WSPP 5 Guzman Renewable Energy Partners LLC SF WSPP 6 IBERDROLA Renewables, Inc SF WSPP 7 Idaho Power Company SF WSPP 8 Imperial Irrigation District SF WSPP WSPP 9 J. Aron & Company SF 10 Los Alamos County SF WSPP 11 Los Angeles Dept of Water & Power SF WSPP 12 Macquarie Energy LLC SF WSPP 13 Morgan Stanley Capital Group, Inc. SF MRT Vol 3 14 Nevada Power Company SF WSPP 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) 1 NextEra Energy Power Marketing, LLC Statistical Classification (b) SF FERC Rate Schedule or Tariff Number (c) WSPP 2 PacifiCorp SF MRT Vol 3 3 Powerex Corp. SF WSPP 4 Public Service Co of Colorado SF WSPP 5 Public Service Co of New Mexico SF WSPP 6 Rainbow Energy Marketing Corporation SF WSPP 7 Salt River Project SF WSPP 8 Sempra Gas & Power Marketing, LLC SF WSPP 9 Shell Energy North America (US), L.P. SF WSPP 10 Southern California Edison Company SF WSPP 11 Talen Energy Marketing, LLC SF WSPP 12 Tenaska Power Services Company SF WSPP 13 Tohono O'Odham Utility Auth SF 87975 14 TransAlta Energy Marketing, US, Inc. SF WSPP Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.3 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Tucson Electric Power Co. Statistical Classification (b) SF 2 Twin Eagle Resource Management, LLC SF WSPP 3 UNS Electric, Inc. SF WSPP 4 WAPA, Colorado River Storage Project SF WSPP 5 WAPA, Desert Southwest Region SF WSPP 6 California Independent System Operator OS MRT Vol 3 7 PacifiCorp Supplemental Coal OS 182 8 PacifiCorp Supplemental Other OS 182 9 Southwest Reserve Sharing Group OS SRSG1 Line No. Name of Company or Public Authority (Footnote Affiliations) 10 Transmission Losses AD 11 Change in Estimate / Other AD Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) 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) 03/31/2017 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/Q4 End of OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Sold (g) 1,674 Demand Charges ($) (h) 23,039 REVENUE Energy Charges ($) (i) 59,199 Other Charges ($) (j) 365,030 Line No. Total ($) (h+i+j) (k) 447,268 1 2 42 597 1,499 247,181 249,277 39,259 995,782 824,422 39,600 1,859,804 3 4 98 1,387 3,473 29,870 34,730 456 6,208 13,508 390,856 410,572 5 5,925 81,219 209,509 1,835,014 2,125,742 6 5,457 75,912 192,944 698,458 967,314 7 987 13,763 34,900 398,170 446,833 8 12,495 172,250 441,762 789,697 1,403,709 9 785 11,049 27,773 416,392 455,214 10 105 1,458 3,703 174,545 179,706 11 25 1,772 898 163,241 165,911 12 15 515 515 13 172 9,017 9,017 14 67,308 1,384,436 1,813,590 5,548,054 8,746,080 3,838,736 0 104,794,954 5,825,568 110,620,522 3,906,044 1,384,436 106,608,544 11,373,622 119,366,602 FERC FORM NO. 1 (ED. 12-90) Page 311 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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) 146,995 9,172,488 9,172,488 1 153 9,512 9,512 2 43 2,037 2,037 3 193,690 12,086,256 12,086,256 4 216,585 3,938,998 3,938,998 5 14,908 381,348 381,348 6 100,200 2,226,981 2,226,981 7 50 1,500 1,500 8 571,855 15,684,675 15,684,675 9 204,907 4,325,356 4,325,356 10 96,735 1,629,637 1,629,637 11 100,143 1,682,243 1,682,243 12 5,882 209,275 209,275 13 800 26,200 26,200 14 67,308 1,384,436 1,813,590 5,548,054 8,746,080 3,838,736 0 104,794,954 5,825,568 110,620,522 3,906,044 1,384,436 106,608,544 11,373,622 119,366,602 FERC FORM NO. 1 (ED. 12-90) Page 311.1 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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) 127,195 Other Charges ($) (j) 2,804,017 Line No. Total ($) (h+i+j) (k) 2,804,017 1 2 6,700 203,270 203,270 74,200 1,688,388 1,688,388 3 4 835 24,713 24,713 62,120 2,017,128 2,017,128 5 8,200 206,350 206,350 6 40,900 1,290,600 1,290,600 7 67,352 1,693,572 1,693,572 8 135,100 9 5,200 135,100 23 488 488 10 6,630 139,570 139,570 11 44,775 1,089,450 1,089,450 12 193,845 3,927,700 3,927,700 13 1,019 43,255 43,255 14 67,308 1,384,436 1,813,590 5,548,054 8,746,080 3,838,736 0 104,794,954 5,825,568 110,620,522 3,906,044 1,384,436 106,608,544 11,373,622 119,366,602 FERC FORM NO. 1 (ED. 12-90) Page 311.2 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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) 7,975 187,344 187,344 1 123,405 2,593,966 2,593,966 2 21,977 483,976 483,976 3 14,000 337,780 337,780 4 19,456 425,353 425,353 5 1,682 40,762 40,762 6 232,056 4,889,833 4,889,833 7 39,718 910,162 910,162 8 56,717 1,259,727 1,259,727 9 38,200 837,900 837,900 10 17,136 479,154 479,154 11 238,274 4,440,092 4,440,092 12 41,344 1,554,670 169,885 3,854,969 494,347 2,049,017 13 3,854,969 14 67,308 1,384,436 1,813,590 5,548,054 8,746,080 3,838,736 0 104,794,954 5,825,568 110,620,522 3,906,044 1,384,436 106,608,544 11,373,622 119,366,602 FERC FORM NO. 1 (ED. 12-90) Page 311.3 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission SALES FOR RESALE (Account 447) (Continued) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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) 178,517 5,159,681 5,159,681 1 97,935 2,356,867 2,356,867 2 57,120 1,462,211 1,462,211 3 262 5,570 5,570 4 1,780 76,310 76,310 5 152,998 6,071,626 6,071,626 6 5,500 122,097 122,097 7 26,525 595,265 595,265 8 4,147 101,608 101,608 9 4,143,534 4,143,534 10 1,086,079 1,086,079 11 12 13 14 67,308 1,384,436 1,813,590 5,548,054 8,746,080 3,838,736 0 104,794,954 5,825,568 110,620,522 3,906,044 1,384,436 106,608,544 11,373,622 119,366,602 FERC FORM NO. 1 (ED. 12-90) Page 311.4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 FOOTNOTE DATA Schedule Page: 310.4 Line No.: 6 Column: b Line No.: 7 Column: b Line No.: 8 Column: b Line No.: 9 Column: b Line No.: 9 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 Rates are set per the Southwest Reserve Sharing Group participation agreement. Schedule Page: 310.4 Line No.: 10 Column: b Adjustment for transmission losses. Schedule Page: 310.4 Line No.: 11 Column: a The amounts shown on pages 310 and 311 are 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.: 11 Column: b The amounts shown on pages 310 and 311 are 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 14,465,641 243,789,424 18,221,926 14,158,948 273,234,222 28,399,409 4,862,010 14,696,564 1,316,174 2,834,992 300,186,731 5,688,711 16,305,917 1,263,460 7,439,715 346,490,382 7,341,999 9,242,420 55,065,542 15,837,331 10,982,099 98,469,391 398,656,122 8,094,353 5,483,435 40,944,344 8,863,236 15,559,791 78,945,159 425,435,541 26,232,569 79,688,967 12,934,179 11,694,791 25,826,204 78,581,781 13,082,524 11,964,589 8,349,317 40,221,101 22,757,675 201,878,599 8,420,379 39,909,231 45,199,895 222,984,603 6,230,976 2,508,512 14,303,492 14,623,970 3,455,428 41,122,378 243,000,977 6,008,938 2,171,342 14,171,173 16,342,376 3,397,129 42,090,958 265,075,561 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 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) Amount for Previous Year (c) Amount for Current Year (b) (a) Page 321 3,450,084 390,682,689 8,678,397 38,968,223 1,020,933 442,800,326 3,181,199 333,179,096 7,661,080 54,658,422 565,997 399,245,794 256,146 5,129,533 28,709,421 1,716,719 35,811,819 478,612,145 310,174 1,601,118 27,779,648 4,351,060 34,042,000 433,287,794 364,921,525 -3,400,047 4,999,576 366,521,054 1,486,790,298 410,042,292 -4,144,485 4,794,609 410,692,416 1,534,491,312 2,349,519 3,012,840 2,917,917 2,988,590 915,790 2,135,403 1,112,581 95,617 62,916 2,994,496 1,590,966 3,513,462 76,160 26,982,680 9,240,455 7,267,325 64,243,877 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 62,181,678 586,534 1,235,089 577,318 867,467 174,891 164,338 5,320,761 9,602,074 394,796 84,098 17,398,243 81,642,120 4,925,411 14,524,379 24,693 70,007 21,153,613 83,335,291 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 6,695,637 2,241,496 1,251,520 2,104,515 1,799,910 -1,024 8,471,763 12,587 42,356,722 708,327 65,641,453 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 1,887,558 285,225 3,733,248 18,832,297 7,164,127 2,918,319 440,137 2,739,119 252,338 3,383,396 20,411,819 9,902,185 2,724,211 539,741 3,909,178 39,170,089 104,811,542 3,495,143 43,447,952 95,468,610 1,933,983 2,497,722 45,567,772 4,025,012 232,563 54,257,052 1,922,661 2,173,367 44,012,091 4,073,429 273,867 52,455,415 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Previous Year (c) Amount for Current Year (b) 252,608 57,603,630 324,521 842,735 59,023,494 308,352 54,040,463 277,941 383,462 55,010,218 7,336,790 6,569,688 5,052,579 12,389,369 4,726,228 11,295,916 91,137,415 8,978,950 21,102,430 38,976,113 5,276,432 8,736,209 64,872,042 92,038,668 9,150,693 22,860,000 37,023,948 5,201,486 7,566,536 52,261,312 20,365,123 16,926,157 3,641,978 -51,847,022 5,858,387 174,893,197 3,572,429 -51,254,320 6,443,887 156,070,796 11,879,833 186,773,030 1,985,686,905 11,677,723 167,748,519 1,999,805,281 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Ajo Improvement Co. RQ N/A N/A N/A 2 Electrical District #4 RQ N/A N/A N/A 3 Electrical District #5 RQ N/A N/A N/A 4 Dynegy Arlington - Tolling Agreement RQ 308,366 5 Salt River Project Eastern Area RQ 10,813 6 Gila River Power - Tolling Agreement RQ 239,021 7 Constellation New Energy Inc. IF N/A N/A N/A 8 Direct Energy Business LLC IF N/A N/A N/A 9 Freeport-McMoRan Copper & Gold EnergyC IF N/A N/A N/A 10 NextEra Energy Power Marketing LLC IF N/A N/A N/A 11 Noble Americas Energy Solutions, LLC IF N/A N/A N/A 12 Arizona Electric Power Cooperative SF N/A N/A N/A 13 BP Energy Company SF N/A N/A N/A 14 California Independent System Operator SF N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 1 California Independent System Operator 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) SF N/A N/A N/A 2 Cargill Power Markets, LLC SF N/A N/A N/A 3 Central Arizona Water Conservation Dit SF N/A N/A N/A 4 Citigroup Energy Inc. SF N/A N/A N/A 5 City of Anaheim, Public Utilities Dep. SF N/A N/A N/A 6 EDF Trading North America LLC SF N/A N/A N/A 7 El Paso Electric Company SF N/A N/A N/A 8 Exelon Generation Company, LLC SF N/A N/A N/A 9 Guzman Energy, LLC SF N/A N/A N/A 10 Guzman Renewable Energy Partners 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 PacifiCorp SF N/A N/A N/A 6 Powerex Corp. SF N/A N/A N/A 7 Public Service Co of New Mexico SF N/A N/A N/A 8 Rainbow Energy Marketing Corporation SF N/A N/A N/A 9 Salt River Project SF N/A N/A N/A 10 San Diego Gas & Electric Co SF N/A N/A N/A 11 Sempra Gas & Power Marketing, LLC SF N/A N/A N/A 12 Shell Energy North America (US), L.P. SF N/A N/A N/A 13 Southern California Edison SF N/A N/A N/A 14 Southwest Reserve Sharing Group SF N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.2 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Tucson Electric Power Co. SF N/A N/A N/A 5 Twin Eagle Resource Management, LLC SF N/A N/A N/A 6 UNS Electric, Inc. SF N/A N/A N/A 7 WAPA, Colorado River Storage Project SF N/A N/A N/A 8 WAPA, Desert Southwest Region SF N/A N/A N/A 9 Westar Energy, Inc. 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 1 High Lonesome Mesa LLC 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) 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 City of Azusa Exchange EX N/A N/A N/A 11 Electric District #6 EX 126 N/A N/A N/A 12 Electric District #7 EX 128 N/A N/A N/A 13 Electric District #8 EX 140 N/A N/A N/A 14 Aguila Irrigation District EX 141 N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.4 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Buckeye Water Conservation & Drainaget EX 155 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 Conservation Dit 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 Banked Energy OS N/A N/A N/A 9 Co-Generation OS N/A N/A N/A 10 California Independent System Operator OS N/A N/A N/A 11 California Independent System Operator OS N/A N/A N/A 12 Net Inadvertent OS N/A N/A N/A 13 Options and Hedges OS N/A N/A N/A 14 Power Supply Adjustor OS N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.5 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 SFAS 133 OS N/A N/A N/A 2 Change in Estimate / Various AD N/A N/A N/A 3 4 5 6 7 8 9 10 11 12 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) 03/31/2017 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) Total (j+k+l) of Settlement ($) (m) Line No. 1 18 2,343 2,343 257 28,619 28,619 2 13 1,581 1,581 3 2,572,237 61,661,437 4 6,365,249 5 8,147,519 45,966,587 6 1,850,194 59,089,200 174,931 1,800,000 2,868,247 37,819,068 4,565,249 261,310 8,911,923 8,911,923 7 81,621 2,939,209 2,939,209 8 388,623 14,060,877 14,060,877 9 275,700 8,609,831 8,609,831 10 96,999 3,399,804 3,399,804 11 1,678 85,094 85,094 12 4,535 168,359 168,359 13 2,725,207 2,725,207 14 4,715,382 364,921,525 8,962,490 626,389 FERC FORM NO. 1 (ED. 12-90) 631,238 98,708,268 Page 327 261,497,875 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 ($) (j) 95,691 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) 3,904,512 Total (j+k+l) of Settlement ($) (m) 3,904,512 Line No. 1 1,703 92,128 92,128 2 2,766 74,935 74,935 3 340,686 20,781,806 20,781,806 4 225 3,375 3,375 5 19,896 1,072,962 1,072,962 6 2,565 32,785 32,785 7 77 1,236 1,236 8 271 8,600 8,600 9 478 12,751 12,751 10 1,730 101,820 101,820 11 179 7,295 7,295 12 336 6,725 6,725 13 400 24,800 24,800 14 8,962,490 626,389 FERC FORM NO. 1 (ED. 12-90) 631,238 98,708,268 Page 327.1 261,497,875 4,715,382 364,921,525 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 ($) (j) 1,010 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) 46,220 Total (j+k+l) of Settlement ($) (m) Line No. 46,220 1 2 300 -500 -500 14,389 1,043,709 1,043,709 3 4 21,669 793,175 793,175 145,354 4,206,936 4,206,936 5 41,592 2,485,717 2,485,717 6 12,426 274,495 274,495 7 200 2,100 2,100 8 16,027 698,822 698,822 9 470 23,265 23,265 10 2,217 64,969 64,969 11 155,235 4,423,436 4,423,436 12 159 5,770 5,770 13 3,185 137,398 137,398 14 8,962,490 626,389 FERC FORM NO. 1 (ED. 12-90) 631,238 98,708,268 Page 327.2 261,497,875 4,715,382 364,921,525 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) Total (j+k+l) of Settlement ($) (m) Line No. 13,750 498,152 498,152 1 9,709 269,804 269,804 2 7,612 182,782 182,782 3 13,264 325,974 325,974 4 3,674 90,489 90,489 5 1,303 29,852 29,852 6 80 1,520 1,520 7 1,361 1,151,148 1,151,148 8 7,781 328,207 328,207 9 268,209 16,055,394 16,055,394 10 643,675 83,860,514 83,860,514 11 77,325 5,597,816 5,597,816 12 41,341 3,557,173 3,557,173 13 15,479 1,314,937 1,314,937 14 8,962,490 626,389 FERC FORM NO. 1 (ED. 12-90) 631,238 98,708,268 Page 327.3 261,497,875 4,715,382 364,921,525 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 ($) (j) 286,435 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) 16,256,468 Total (j+k+l) of Settlement ($) (m) 16,256,468 Line No. 1 102,074 9,774,092 9,774,092 2 222,091 18,711,167 18,711,167 3 9,227 1,270,145 1,270,145 4 34,860 5,400,511 5,400,511 5 44,138 4,211,207 4,211,207 6 26,144 3,067,217 3,067,217 7 34,363 3,984,733 3,984,733 8 22,645 1,898,557 1,898,557 9 -123 -123 8,962,490 10 23 28 569 1,289 11 4,289 4,401 12 17,076 23,701 13 3,013 3,922 14 626,389 631,238 FERC FORM NO. 1 (ED. 12-90) 98,708,268 Page 327.4 261,497,875 4,715,382 364,921,525 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) Total (j+k+l) of Settlement ($) (m) 2,565 2,046 1 6,666 5,710 2 3,882 6,152 3 10,862 8,306 4 570,837 568,702 4,092 5,411 2,515 1,570 1,060,859 1,060,859 5 6 7 -186,296 335 9,794 1,170,187 189,119 -514,645 -186,296 8 9,794 9 1,170,187 10 -514,645 11 12 1,134 15,836,467 13 -14,793,120 -14,793,120 14 4,715,382 364,921,525 15,836,467 8,962,490 Line No. 626,389 FERC FORM NO. 1 (ED. 12-90) 631,238 98,708,268 Page 327.5 261,497,875 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) Total (j+k+l) of Settlement ($) (m) -9,189,259 -9,189,259 -1,567,560 -1,567,560 Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 8,962,490 626,389 FERC FORM NO. 1 (ED. 12-90) 631,238 98,708,268 Page 327.6 261,497,875 4,715,382 364,921,525 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 FOOTNOTE DATA Schedule Page: 326 Line No.: 2 Column: a Line No.: 3 Column: a Ended February 2016 Schedule Page: 326 Ended February 2016 Schedule Page: 326.5 Line No.: 8 Column: b Represents NonFirm Schedule Page: 326.5 Line No.: 10 Column: b Line No.: 11 Column: a Represents NonFirm Schedule Page: 326.5 Energy Imbalance Market Schedule Page: 326.5 Line No.: 11 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: 326.6 Line No.: 1 Column: b Line No.: 2 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.: 2 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) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) Arizona Public Service Company FNS Pinnacle West Capital Company Arizona Public Service Company FNS Arizona Public Service Company Arizona Public Service Company FNS 1 Arizona Public Service Company Arizona Public Service Company 2 Arizona Public Service Company 3 Arizona Public Service Company 4 Arizona Public Service Company Various Arizona Public Service Company FNS 5 Ajo Improvement Company N/A N/A FNO 6 Central Arizona Water Conservation District N/A N/A FNO 7 Navajo Tribal Utility Authority Tucson Electric Power Navajo Tribal Utility Authority FNO 8 Navopache Electric Cooperative, Inc. N/A N/A FNO 9 Public Service Company of New Mexico N/A N/A FNO 10 Southwest Transmission Cooperative N/A N/A FNO 11 CSE Operating 1, LLC N/A N/A LFP 12 Electrical District 3 N/A N/A LFP 13 NOVO BioPower LLC N/A N/A LFP 14 PacifiCorp N/A N/A LFP 15 Public Service Company of New Mexico N/A N/A LFP 16 Salt River Project (OATT General Service) N/A N/A LFP 17 Tucson Electric Power Company N/A N/A LFP 18 Arizona Public Service Company N/A N/A SFP 19 City of Anaheim N/A N/A SFP 20 Tucson Electric Power Company N/A N/A SFP 21 Arizona Electric Power Cooperative, Inc N/A N/A SFP 22 Arizona Public Service Company N/A N/A SFP 23 Cargill Power Markets, LLC N/A N/A SFP 24 Tenaska Power Services Co. N/A N/A SFP 25 Tucson Electric Power Company N/A N/A SFP 26 Rainbow Energy Marketing N/A N/A SFP 27 Arizona Electric Power Cooperative, Inc N/A N/A SFP 28 Arizona Public Service Company N/A N/A SFP 29 Brookfield Energy Marketing LP N/A N/A SFP 30 Cargill Power Markets, LLC N/A N/A SFP 31 City of Anaheim N/A N/A SFP 32 CXA Sundevil Power I, Inc. N/A N/A SFP 33 EDF Trading North America, LLC N/A N/A SFP 34 El Paso Electric Company N/A N/A SFP TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) 1 Guzman Power Markets LLC N/A N/A SFP 2 Iberdrola Renewables N/A N/A SFP 3 Macquarie Energy LLC N/A N/A SFP 4 Morgan Stanley N/A N/A SFP 5 Nevada Power Company N/A N/A SFP 6 PacifiCorp N/A N/A SFP 7 Powerex N/A N/A SFP 8 Public Service Company of New Mexico N/A N/A SFP 9 Salt River Project (OATT General Service) N/A N/A SFP 10 Sempra Generation N/A N/A SFP 11 Shell Energy North America LP N/A N/A SFP 12 Southern California Edison Company N/A N/A SFP 13 Sundevil Power Holdings N/A N/A SFP 14 Talen Energy Marketing LLC N/A N/A SFP 15 Tenaska Power Services Co. N/A N/A SFP 16 TransAlta Energy Marketing U.S. Inc. N/A N/A SFP 17 Tucson Electric Power Company N/A N/A SFP 18 City of Anaheim N/A N/A NF 19 Arizona Public Service Company N/A N/A NF 20 Arizona Public Service Company N/A N/A NF 21 City of Anaheim N/A N/A NF 22 Arizona Electric Power Cooperative, Inc N/A N/A NF 23 Arizona Public Service Company N/A N/A NF 24 Cargill Power Markets, LLC N/A N/A NF 25 City of Anaheim N/A N/A NF 26 EDF Trading North America, LLC N/A N/A NF 27 Guzman Power Markets LLC N/A N/A NF 28 Iberdrola Renewables N/A N/A NF 29 Idaho Power Company, BO N/A N/A NF 30 Imperial Irrigation District N/A N/A NF 31 Macquarie Energy LLC N/A N/A NF 32 Mag Energy Solutions, Inc N/A N/A NF 33 Morgan Stanley N/A N/A NF 34 Nevada Power Company N/A N/A NF TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) N/A N/A NF 2 Powerex N/A N/A NF 3 Public Service Company of New Mexico N/A N/A NF 4 Salt River Project (OATT General Service) N/A N/A NF 5 Sempra Generation N/A N/A NF 6 Shell Energy North America LP N/A N/A NF 7 Southern California Edison Company N/A N/A NF 8 Talen Energy Marketing LLC N/A N/A NF 9 Tenaska Power Services Co. N/A N/A NF 10 TransAlta Energy Marketing U.S. Inc. N/A N/A NF 11 Tri-State Generation and Transmission N/A N/A NF 12 Tucson Electric Power Company N/A N/A NF 13 Westar Energy Inc. N/A N/A NF 14 Yuma Cogeneration Associates N/A N/A NF 15 Arizona Public Service Company N/A N/A OLF 16 Imperial Irrigation District N/A N/A OS 17 Luke AFB Main Field DOE WAPA Lower Luke Air Force Base OS 18 Marine Corps. Air Station DOE WAPA Lower Marine Corps Air Station OS 19 NOVO BioPower LLC N/A N/A OS 20 PacifiCorp N/A N/A OLF 21 Public Service Company of New Mexico N/A N/A OLF 22 Salt River Project (Schedule F) N/A N/A OS 1 PacifiCorp 23 Salt River Project (Schedule Q) Pinnacle Peak Ocotillo 230 OS 24 Tucson Electric Power Company N/A N/A OLF 25 Unit B Irrigation and Drainage District N/A N/A OS 26 Yuma Cogeneration Associates Yuma Cogeneration Assoc. San Diego Gas and Elect. OLF 27 Yuma Mesa Irrigation and Drainage District DOE WAPA Lower Yuma-Mesa Irrigation Dist OS 28 Other N/A N/A AD 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) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 OATT Various Various OATT Various Various OATT Various Various OATT Various Various 2 20,612 20,612 5 OATT Various Various 42 273,373 273,373 6 OATT Various Various 4 53,425 53,425 7 OATT Various Various 55 531,712 531,712 8 OATT Various Various OATT Various Various 4 9,801 9,801 10 OATT Various Various 1 7,238 7,238 11 OATT Various Various 90 318,509 318,509 12 OATT N/A N/A 14 108,806 108,806 13 OATT Various Various 37 147,772 147,772 14 OATT Various Various 10 61,463 61,463 15 OATT Various Various 284 346,547 346,547 16 OATT Various Various 110 91,350 91,350 17 OATT Various Various 3 5,241 5,241 18 OATT Various Various 49 60,408 60,408 19 OATT Various Various 110 6,586 6,586 20 OATT Various Various 24 569 569 21 OATT Various Various 3 64 64 22 OATT Various Various 150 3,309 3,309 23 OATT Various Various 340 8,110 8,110 24 OATT Various Various 660 4,679 4,679 25 OATT Various Various 320 6,701 6,701 26 OATT Various Various 555 555 555 27 OATT Various Various 24,825 55,487 55,487 28 OATT Various Various 50 38 38 29 OATT Various Various OATT Various Various 4,792 15,858 15,858 31 OATT Various Various 68 68 68 32 OATT Various Various 720 23 23 33 OATT Various Various 50 50 50 34 152,291 38,799,934 38,795,543 FERC FORM NO. 1 (ED. 12-90) 158 Line No. MegaWatt Hours Delivered (j) 911,724 911,724 29,431,946 29,431,945 1 2 3 4 9 30 Page 329 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 OATT Various Various 50 75 75 2 OATT Various Various 352 16 16 3 OATT Various Various 426 479 479 4 OATT Various Various OATT Various Various 21,304 45,122 45,122 6 OATT Various Various 332 699 699 7 OATT Various Various 874 1,823 1,823 8 OATT Various Various 2,323 40,625 40,625 9 OATT Various Various 1,125 1,985 1,985 10 OATT Various Various 2,641 6,627 6,627 11 OATT Various Various OATT Various Various 3,091 5,437 5,437 13 OATT Various Various 461 301 301 14 OATT Various Various 7,042 15,305 15,305 15 OATT Various Various 229 330 330 16 OATT Various Various 10,772 30,735 30,735 17 OATT Various Various 49 32,955 32,955 18 OATT Various Various 12 1,552 1,552 19 OATT Various Various 15 304 304 20 OATT Various Various 1,323 171,186 171,186 21 OATT Various Various 1 1 1 22 OATT Various Various 9,443 40,546 40,546 23 OATT Various Various 3,600 7,035 7,035 24 OATT Various Various 744 505 505 25 OATT Various Various 3,091 OATT Various Various 168 210 210 27 OATT Various Various 372 716 716 28 OATT Various Various 500 500 500 29 OATT Various Various 15 10 10 30 OATT Various Various 3,320 3,758 3,758 31 OATT Various Various 982 1,047 1,047 32 OATT Various Various 1,293 3,687 3,687 33 OATT Various Various 150 150 150 34 152,291 38,799,934 38,795,543 FERC FORM NO. 1 (ED. 12-90) 8 Line No. MegaWatt Hours Delivered (j) 8 8 1 5 12 Page 329.1 26 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2016/Q4 End of 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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) 9,824 Line No. MegaWatt Hours Delivered (j) OATT Various Various 32,876 32,876 1 OATT Various Various 283 486 486 2 OATT Various Various 1,150 361 361 3 OATT Various Various 9,336 24,299 24,299 4 OATT Various Various 10,153 13,536 13,536 5 OATT Various Various 878 1,135 1,135 6 OATT Various Various 40 23 23 7 OATT Various Various 40 26 26 8 OATT Various Various 1,308 2,980 2,980 9 OATT Various Various 1,200 4,940 4,940 10 OATT Various Various 75 99 99 11 OATT Various Various 7,700 27,183 27,183 12 OATT Various Various 195 165 165 13 OATT Various Various 190 85 85 14 213,894 213,894 15 RS 183 N/A N/A OATT N/A N/A 16 RS 162 Pinnacle Peak Sub Luke Substation 17 RS 166 Gila Substation Marine Corps Air Stn 18 OATT N/A N/A 19 RS 183 N/A N/A RS 73 Palo Verde Four Corners RS 3 N/A N/A RS 3 Pinnacle Peak Ocotillo 230 RS 32 Four Corners Saguaro 130 4,566,610 4,566,611 20 884,895 884,895 21 100 22 23 51 119,603 115,212 10,985 10,985 24 RS 181 Gila Substation District Customer RS 198 Riverside Substation North Gila Sub 25 RS 31 Gila Substation Yuma Mesa Load 27 N/A N/A N/A 28 26 29 30 31 32 33 34 152,291 FERC FORM NO. 1 (ED. 12-90) Page 329.2 38,799,934 38,795,543 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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 ($) (k) 8,800,913 87,783 -141,747 1,360,079 260,176 -8,006 2,042,716 119,496 Line No. Total Revenues ($) (k+l+m) (n) 8,800,913 1 -8,800,913 -8,800,913 2 -273,019,387 -273,019,387 3 273,019,387 273,019,387 4 -1,812 -55,776 5 -33,201 1,326,878 6 45,130 297,300 7 -4,489 2,038,227 8 -9,202 -9,202 9 -1,614 117,882 10 34,161 7,170 103,615 144,946 11 3,458,218 219,735 12 -38,795 3,639,158 537,945 -17,436 520,509 13 1,421,528 -63,032 1,358,496 14 384,197 -11,182 373,015 15 7,212,764 -73,842 7,138,922 16 1,826,825 -2,479 1,824,346 17 418,634 15,517 434,151 18 325,507 -4,363 321,144 19 131,831 131,831 20 3,127 3,127 21 357 357 22 19,547 19,547 23 43,260 43,260 24 135,572 43,803 135,572 25 -805 42,998 26 4,154 27 -652 577,958 28 372 29 4,154 578,610 372 163,320 -107 -107 30 -40,635 122,685 31 310 32 14,523 33 356 34 310 9,424 5,099 356 28,470,609 FERC FORM NO. 1 (ED. 12-90) 78,051 Page 330 999,348 29,548,008 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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 ($) (k) 57 Line No. Total Revenues ($) (k+l+m) (n) 57 1 558 -26 532 2 3,068 -2,207 861 3 3,726 -1,167 2,559 4 -20 -20 5 -438 343,704 6 344,142 3,813 -799 3,014 7 15,653 2,197 17,850 8 15,972 9 15,972 12,005 -322 11,683 10 48,507 -130 48,377 11 -56 12 69,257 -56 69,257 13 4,131 4,131 14 106,742 -2,963 103,779 15 1,946 -56 1,890 16 360,294 6,944 367,238 17 162,753 162,753 18 8,398 8,398 19 1,729 1,073,079 -1,265 1,729 20 1,071,814 21 4 -4,746 -4,742 22 288,294 23,869 312,163 23 52,424 -671 51,753 24 5,249 25 -8 42,903 26 1,496 1,496 27 5,553 5,553 28 3,701 29 5,249 42,911 3,719 -18 112 3,431 3,543 30 27,274 27,274 31 10,664 10,664 32 27,595 33 1,220 34 27,638 -43 1,220 28,470,609 FERC FORM NO. 1 (ED. 12-90) 78,051 Page 330.1 999,348 29,548,008 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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) 98,336 98,336 1 4,198 4,198 2 9,511 9,511 3 125,495 1,293 126,788 4 80,142 -22 80,120 5 11,939 -20 11,919 6 298 -5 182 293 7 182 8 20,051 -8 20,043 9 28,884 -1,542 27,342 10 540 11 540 221,144 -16,574 204,570 12 1,479 13 -11 2,562 14 52,997 52,997 1,479 2,573 15 173,448 899 77,652 2,716 16 174,347 17 77,652 18 2,716 19 20 1,415,030 24,385 1,415,030 21 24,385 22 935,984 23 1,005,161 24 540 540 25 1,838,661 1,838,661 26 4,500 27 935,984 1,005,161 4,500 137,319 137,319 28 29 30 31 32 33 34 28,470,609 FERC FORM NO. 1 (ED. 12-90) 78,051 Page 330.2 999,348 29,548,008 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 FOOTNOTE DATA Schedule Page: 328 Line No.: 1 Column: a Service to Arizona Public Service Company pursuant to Part III of the OATT Schedule Page: 328 Line No.: 1 Column: m Direct Assignment Charges Schedule Page: 328 Line No.: 2 Column: a Service to Arizona Public Service Company pursuant to Part IV of the OATT Schedule Page: 328 Line No.: 2 Column: m AzISA Fees & Unreserved Use Credit Schedule Page: 328 Line No.: 3 Column: a Intracompany Transmission Schedule Page: 328 Line No.: 3 Column: m Intracompany Transmission Schedule Page: 328 Line No.: 4 Column: a Intracompany Transmission Schedule Page: 328 Line No.: 4 Column: m Intracompany Transmission Schedule Page: 328 Line No.: 5 Column: l Includes Schedule 4 Energy Imbalance activity Jan-Sep 2016 (prior to EIM go-live). Schedule Page: 328 Line No.: 5 Column: m Line No.: 6 Column: m Line No.: 7 Column: l Unreserved Use Credit Schedule Page: 328 Unreserved Use Credit Schedule Page: 328 Includes Schedule 4 Energy Imbalance activity Jan-Sep 2016 (Prior to Energy Imbalance Market). Schedule Page: 328 Line No.: 7 Column: m Direct Assignment Charges & Unreserved Use Credit Schedule Page: 328 Line No.: 8 Column: m Unreserved Use Penalty & Credit Schedule Page: 328 Line No.: 9 Column: m Unreserved Use Credit Schedule Page: 328 Line No.: 10 Column: m Line No.: 11 Column: l Unreserved Use Credit Schedule Page: 328 Includes Schedule 10 Generator Imbalance activity Jan-Sep 2016 (Prior to Energy Imbalance Market). Schedule Page: 328 Line No.: 11 Column: m Direct Assignment Charges & Unreserved Use Credit Schedule Page: 328 Line No.: 12 Column: l Includes Schedule 4 Energy Imbalance activity Jan-Sep 2016 (Prior to Energy Imbalance Market). Schedule Page: 328 Line No.: 12 Column: m Line No.: 13 Column: m Unreserved Use Credit Schedule Page: 328 Unreserved Use Credit Schedule Page: 328 Line No.: 14 Column: m Unreserved Use Credit Schedule Page: 328 Line No.: 15 Column: m Unreserved Use Credit FERC FORM NO. 1 (ED. 12-87) Page 450.1 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 328 Line No.: 16 Column: m Unreserved Use Penalty & Credit Schedule Page: 328 Line No.: 17 Column: m Line No.: 18 Column: h Unreserved Use Credit Schedule Page: 328 Monthly Demand Service Period Schedule Page: 328 Line No.: 18 Column: m Unreserved Use Penalty Schedule Page: 328 Line No.: 19 Column: h Monthly Demand Service Period Schedule Page: 328 Line No.: 19 Column: m Line No.: 20 Column: h Unreserved Use Credit Schedule Page: 328 Weekly Demand Service Period Schedule Page: 328 Line No.: 21 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 22 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 23 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 24 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 25 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 26 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 26 Column: m Line No.: 27 Column: h Unreserved Use Credit Schedule Page: 328 Hourly Demand Service Period Schedule Page: 328 Line No.: 28 Column: h Hourly Demand Service Period Schedule Page: 328 Line No.: 28 Column: m Line No.: 29 Column: h Unreserved Use Credit Schedule Page: 328 Hourly Demand Service Period Schedule Page: 328 Line No.: 30 Column: h Hourly Demand Service Period Schedule Page: 328 Line No.: 30 Column: m Line No.: 31 Column: h Unreserved Use Credit Schedule Page: 328 Hourly Demand Service Period Schedule Page: 328 Line No.: 31 Column: m Line No.: 32 Column: h Unreserved Use Credit Schedule Page: 328 Hourly Demand Service Period Schedule Page: 328 Line No.: 33 FERC FORM NO. 1 (ED. 12-87) Column: h Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Hourly Demand Service Period Schedule Page: 328 Line No.: 33 Column: m Unreserved Use Penalty & Credit Schedule Page: 328 Line No.: 34 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 1 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 2 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 2 Column: m Line No.: 3 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 3 Column: m Line No.: 4 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 4 Column: m Line No.: 5 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 5 Column: m Line No.: 6 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 6 Column: m Line No.: 7 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 7 Column: m Line No.: 8 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 8 Column: m Unreserved Use Penalty & Credit Schedule Page: 328.1 Line No.: 9 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 10 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 10 Column: m Line No.: 11 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 11 Column: m Line No.: 12 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 12 FERC FORM NO. 1 (ED. 12-87) Column: m Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Unreserved Use Credit Schedule Page: 328.1 Line No.: 13 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 14 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 15 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 15 Column: m Line No.: 16 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 16 Column: m Schedule Page: 328.1 Line No.: 17 Column: h Schedule Page: 328.1 Line No.: 17 Column: m Line No.: 18 Column: h Unreserved Use Credit Unreserved Use Penalty Schedule Page: 328.1 Monthly Demand Service Period Schedule Page: 328.1 Line No.: 19 Column: h Weekly Demand Service Period Schedule Page: 328.1 Line No.: 20 Column: h Daily Demand Service Period Schedule Page: 328.1 Line No.: 21 Column: h Daily Demand Service Period Schedule Page: 328.1 Line No.: 21 Column: m Line No.: 22 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 22 Column: m Line No.: 23 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 23 Column: m Unreserved Use Penalty & Credit Schedule Page: 328.1 Line No.: 24 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 24 Column: m Line No.: 25 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 26 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 26 Column: m Line No.: 27 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 28 FERC FORM NO. 1 (ED. 12-87) Column: h Page 450.4 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Hourly Demand Service Period Schedule Page: 328.1 Line No.: 29 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 29 Column: m Line No.: 30 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 30 Column: m Line No.: 31 Column: h Unreserved Use Penalty Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 32 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 33 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 33 Column: m Line No.: 34 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 1 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 2 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 3 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 3 Column: m Line No.: 4 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 4 Column: m Line No.: 5 Column: h Unreserved Use Penalty Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 5 Column: m Line No.: 6 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 6 Column: m Line No.: 7 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 7 Column: m Line No.: 8 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 9 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 9 FERC FORM NO. 1 (ED. 12-87) Column: m Page 450.5 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Unreserved Use Credit Schedule Page: 328.2 Line No.: 10 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 10 Column: m Line No.: 11 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 12 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 12 Column: m Line No.: 13 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 14 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 14 Column: m Line No.: 15 Column: e Unreserved Use Credit Schedule Page: 328.2 Exchange agreement pursuant to Pre888 contract Schedule Page: 328.2 Line No.: 16 Column: m Direct Assignment Charges Schedule Page: 328.2 Line No.: 17 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 18 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 19 Column: m Direct Assignment Charges Schedule Page: 328.2 Line No.: 20 Column: e Exchange agreement pursuant to Pre888 contract Schedule Page: 328.2 Line No.: 22 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 23 Column: m Direct Assignment Charges Schedule Page: 328.2 Line No.: 24 Column: e Contract terminated during 2016 Schedule Page: 328.2 Line No.: 25 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 27 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.2 Line No.: 28 Column: d FERC transmission rate true up, change in estimate, and timing difference Schedule Page: 328.2 Line No.: 28 Column: m FERC transmission rate true up, change in estimate, and timing difference FERC FORM NO. 1 (ED. 12-87) Page 450.6 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 Payment Received by Statistical FERC Rate Schedule Total Revenue by Rate Total Revenue (Transmission Owner Name) Classification or Tariff Number Schedule or Tarirff No. (a) (b) (c) (d) (e) 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) 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) (h) (g) 1 Arizona Public Service FNS 2 Bureau of Indian Affair OLF 3 Department of Energy OS 5,150 5,150 4 Department of Energy OS 34,551 34,551 5 Department of Energy FNS 423,654 6 Department of Energy OS 1,163,836 7 Department of Energy LFP 353,183 353,183 8 Department of Energy LFP 1,500 1,500 241,161 241,161 6,970,410 181,407 9 Department of Energy LFP 10 Department of Energy FNS 11 Department of Energy OS 1,334,755 1,334,755 153,600 153,600 130,919 -3,878 127,041 105,036 33,174 3 138,213 423,654 1,175,230 591,582 1,522 1,768,334 1,163,836 3,789,555 839,368 -56,345 4,572,578 48,952 240,488 34,545 1,981,125 368,539 92,085 24,513 24,513 52,776 3,141 323,985 2,349,664 10,242 7,162,059 -7,781 84,304 -2,219 53,698 12 Electric District # 3 LFP 2,132 2,132 83,095 902 83,997 13 Electric District # 4 OLF 1,925 1,925 57,920 -787 57,133 14 Salt River Project OLF 38,917 38,917 222,746 30,670 -30,530 222,886 15 Salt River Project OLF 339,806 339,806 1,357,037 254,337 -254,338 1,357,036 16 Salt River Project LFP 183,640 183,640 1,309,156 148,965 -7,233 1,450,888 5,190,855 5,190,855 23,131,040 4,035,633 -183,993 26,982,680 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) Page 332 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) TRANSFER OF ENERGY MagawattMagawatthours hours Received Delivered (c) (d) 470,539 EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Energy Other Total Cost of Charges Charges Charges Transmission ($) ($) ($) ($) (e) (f) (h) (g) 1 Salt River Project FNS 470,539 1,892,654 2 Salt River Project OLF 3 Salt River Project OS 98,944 98,944 228,893 1,733,475 1,733,475 4 Salt River Project FNS 357 357 1,748,791 5 Salt River Project OS 6 Southern Cal Edison LFP 100 100 180,405 7 Southwester Transmissio SFP 14,346 14,346 60,355 8 Tucson Electric Power OS 15,547 15,547 85,103 9 Public Srvs Co of NM 377,668 -1,295 2,269,027 79,791 -79,790 228,894 427,607 155,746 583,353 298,199 53,447 2,100,437 22,158 202,563 5,390 NF 2,837 2,837 39,780 726 10 SRP Misc AR OS 40,740 40,740 161,578 23,662 11 El Paso Electric Compay OS 2 2 3 5,190,855 5,190,855 23,131,040 1 60,356 -1,247 89,246 -17,116 168,124 40,506 3 12 13 14 15 16 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1 4,035,633 -183,993 26,982,680 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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, 2020 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.: 10 Column: g Prior period adjustment /Timing 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 FERC FORM NO. 1 (ED. 12-87) Column: b Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Terminates May 1, 2019 Schedule Page: 332 Line No.: 16 Column: g 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.: 5 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.: 9 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) 03/31/2017 2016/Q4 Name of Respondent 20170406-8017 FERC Arizona Public Service Company This Report Is: PDF (Unofficial) 03/31/2017 (1) X An Original Line No. Date of Report (Mo, Da, Yr) 03/31/2017 (2) A Resubmission MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC) Description (a) 1 Industry Association Dues Year/Period of Report 2016/Q4 End of Amount (b) 1,067,700 2 Nuclear Power Research Expenses 3 Other Experimental and General Research Expenses 4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 -2,066,823 6 Allocation of Parent Company Costs 13,915,882 7 Bank Fees 1,301,994 8 Billed to Others-Services Performed -65,366,811 9 Communication Service 570,212 10 Materials & Supplies 29,650 11 Payroll -2,021,041 12 Outside Services 260,651 13 Rents/Leases 122,589 14 Transportation Expense 11,060 15 Travel 327,915 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 (ED. 12-94) -51,847,022 Page 335 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 Depreciation Amortization of Expense for Asset Limited Term Depreciation Retirement Costs Expense Electric Plant (Account 404) (Account 403.1) (Account 403) (c) (b) (d) 58,358,535 Amortization of Other Electric Plant (Acc 405) (e) Total (f) 58,358,535 2 Steam Production Plant 57,620,361 3,053,616 612 60,674,589 3 Nuclear Production Plant 45,292,269 -2,173,588 3,674,265 46,792,946 6 Other Production Plant 68,105,311 3,500,673 7 Transmission Plant 48,274,313 7,874,686 56,148,999 128,660,918 896,005 129,556,923 40,409,854 6,411,781 46,821,635 77,215,884 469,959,611 4 Hydraulic Production Plant-Conventional 5 Hydraulic Production Plant-Pumped Storage 8 Distribution Plant 71,605,984 9 Regional Transmission and Market Operation 10 General Plant 11 Common Plant-Electric 12 TOTAL 388,363,026 4,380,701 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% 2.00% - 20.00% 1.67% - 50.00% 391 / 391.2 / 393 / 394 / 395 / 398 4.17% - 5.00% 321 / 322 / 323 / 324 / 325 / 326 / 371 / 390 / 397 amortized over the life of the lease * Note: Hydro expense relates to the Childs Irving Regulatory Liability balance being amorted over 3 years to clear the Regulatory "2540" balance upon final decommissioning per ACC Dec. 73183. FERC FORM NO. 1 (REV. 12-03) Page 336 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/Q4 End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) Line No. Account No. (a) 12 STEAM PRODUCTION C. Factors Used in Estimating Depreciation Charges Depreciable Estimated Net Plant Base Avg. Service Salvage (In Thousands) Life (Percent) (d) (b) (c) Applied Depr. rates (Percent) (e) Mortality Curve Type (f) Average Remaining Life (g) 13 311 172,665 18.00 -9.80 2.60 O1 8.00 14 312 1,224,743 24.00 -12.30 2.83 O1 11.00 15 314 214,593 24.00 -11.70 3.04 O1 12.00 16 315 133,152 24.00 -10.30 2.56 O1 10.00 17 316 104,761 21.00 -12.00 3.42 O1 11.00 19 321 847,932 52.00 -0.80 1.34 O1 34.00 20 322 1,235,401 49.00 -0.80 1.55 O1 33.00 21 323 407,923 50.00 -0.80 1.46 O1 33.00 22 324 293,628 54.00 -0.80 1.20 O1 33.00 23 325 206,209 49.00 -0.80 1.51 O1 34.00 18 NUCLEAR PRODUCTION 24 OTHER PRODUCTION 25 341 120,813 30.00 5.00 2.76 O1 23.00 26 342 55,640 29.00 5.00 2.95 O1 20.00 27 343 657,159 32.00 5.00 2.47 O1 26.00 28 344 1,429,584 29.00 5.00 2.72 O1 22.00 29 345 214,238 31.00 5.00 2.62 O1 23.00 30 346 30,378 27.00 5.00 3.20 O1 19.00 32 352 140,831 51.00 2.67 R4 17.00 33 353 1,134,576 46.00 2.42 S0.5 34.00 34 354 151,481 60.00 1.84 R3 37.00 35 355 539,431 55.00 -20.00 2.23 R1.5 48.00 36 356 493,718 60.00 -20.00 2.08 R3 47.00 37 357 37,567 60.00 1.55 R4 48.00 38 358 34,619 60.00 15.00 1.33 L1.5 45.00 40 361 85,517 60.00 -5.00 1.67 R3 50.00 41 362 546,410 43.00 10.00 1.99 L0.5 36.00 42 364.1 337,063 38.00 -5.00 2.27 L0 31.00 43 364.2 279,269 48.00 -10.00 2.81 SC 35.00 44 365 376,749 48.00 5.00 1.90 L0 40.00 45 366 697,739 60.00 -5.00 1.65 L1 50.00 46 367 1,674,628 35.00 -5.00 2.72 L1 27.00 47 368 859,274 55.00 -5.00 1.75 L1 44.00 48 369 395,856 41.00 -5.00 2.30 L1 30.00 49 370.1 17,617 15.00 6.21 R0.5 12.00 50 370.3 258,031 15.00 6.53 R0.5 14.00 31 TRANSMISSION -5.00 39 DISTRIBUTION FERC FORM NO. 1 (REV. 12-03) Page 337 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/Q4 End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) Line No. Account No. (a) 12 371 C. Factors Used in Estimating Depreciation Charges Depreciable Estimated Net Plant Base Avg. Service Salvage (In Thousands) Life (Percent) (d) (b) (c) 45,038 40.00 -15.00 13 373 74,602 55.00 -10.00 15 390 258,075 45.00 -5.00 16 391-1 189,017 8.00 17 397 263,286 18.00 Applied Depr. rates (Percent) (e) 2.68 L0 Mortality Curve Type (f) Average Remaining Life (g) 33.00 1.85 L0.5 45.00 2.32 L1 34.00 12.10 L3 5.00 14 GENERAL 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 337.1 5.35 S1.5 11.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) 8,455,970 5 Legal and Filing Fees 6 Consulting Fees 7 Payroll and Employee Expense 8 Est. ACC and RUCO Assessments on Unbilled Rev 8,455,970 22,548 22,548 416,748 416,748 2,732,912 2,732,912 26,743 9 Other 26,743 49,502 49,502 10 11 FERC Expenses 12 Regulatory Assessment by FERC 3,303,903 3,303,903 13 Legal and Filing Fees 14 Consulting Fees 15 Payroll and Employee Expenses 17,728 17,728 115,305 115,305 16 Other 17 18 NRC Expenses 19 NRC License Fees 5,223,764 5,223,764 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) 17,010,380 Page 350 3,354,743 20,365,123 Deferred in Account 182.3 at Beginning of Year (e) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. (g) (h) (f) AMORTIZED DURING YEAR Deferred to Account 182.3 (i) Contra Account Amount (j) (k) Deferred in Account 182.3 End of Year (l) Line No. 1 2 3 Electric 928 8,455,970 4 Electric 928 22,548 5 Electric 928 416,748 6 Electric 928 2,732,912 7 Electric 928 26,743 8 Electric 928 49,502 9 10 11 Electric 928 3,303,903 12 Electric 928 17,728 14 Electric 928 115,305 15 13 16 17 18 Electric 928 5,223,764 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 20,365,123 FERC FORM NO. 1 (ED. 12-96) 46 Page 351 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Classification No. (a) 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) 1 A(1)e RENEWABLES 2 B(1) EPRI 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 22,500 Unamortized Accumulation (g) AMOUNTS CHARGED IN CURRENT YEAR Account (e) 549 Amount (f) 22,500 Line No. 1 281,660 107 281,660 2 519,637 500 519,637 3 189,038 506 189,038 4 722,400 524 722,400 5 363,296 549 363,296 6 932,108 580 932,108 7 16,000 916 16,000 8 84,735 920 84,735 9 3,131,374 10 3,131,374 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. 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 Classification Direct Payroll Distribution (b) (a) 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) 118,399,369 17,269,953 43,223,613 24,903,884 2,311,442 6,662,602 86,483,464 299,254,327 43,691,425 3,602,350 22,324,309 4,287,412 73,905,496 162,090,794 20,872,303 65,547,922 24,903,884 2,311,442 6,662,602 90,770,876 373,159,823 354 373,159,823 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/Q4 End of DISTRIBUTION OF SALARIES AND WAGES (Continued) Line No. 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 Classification Direct Payroll Distribution (b) (a) 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 Four Corners 230/345 Morgan Pinnacle Peak PV-NG Yuma Navajo STS 500 KV Line Studies Streetlights 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) 373,159,823 373,159,823 167,841,933 167,841,933 167,841,933 167,841,933 396,537 103,847 47,095 115 3,424,979 59,280 212,302,900 17,306,937 10,361,364 1,903,929 86,639 473,719 242,120 999,113 52,453 737,037 955,963 249,454,027 790,455,783 396,537 103,847 47,095 115 3,424,979 59,280 212,302,900 17,306,937 10,361,364 1,903,929 86,639 473,719 242,120 999,113 52,453 737,037 955,963 249,454,027 790,455,783 20170406-8017 03/31/2017 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) 03/31/2017 Year/Period of Report End of 2016/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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/Q4 End of AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS 1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively. Description of Item(s) Line No. (a) Balance at End of Quarter 1 (b) Balance at End of Quarter 2 (c) Balance at End of Quarter 3 (d) Balance at End of Year (e) 1 Energy 2 Net Purchases (Account 555) 3 Net Sales (Account 447) 1,062,617 2,325,813 3,859,258 6,163,801 ( 5,163,012) ( 8,472,668) ( 12,548,938) ( 21,756,301) ( 4,100,395) ( 6,146,855) ( 8,689,680) ( 15,592,500) 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 397 Line No.: 2 Column: d True up difference reported in Q3 F3Q FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 Number of Units Dollars Measure (b) (c) (d) 1 Scheduling, System Control and Dispatch 60,761 MW 2 Reactive Supply and Voltage 60,761 MW 3 Regulation and Frequency Response 60,761 MW 4 Energy Imbalance 1,814,038 Usage - Related Billing Determinant Unit of Number of Units Dollars Measure (e) (f) (g) 66,567 MW 1,989,940 66,567 MW 6,970,843 MW 63,372 MW 7,104,011 -13,629 MW -221,351 5 Operating Reserve - Spinning 60,761 MW 15,987,073 63,383 MW 16,132,330 6 Operating Reserve - Supplement 60,761 MW 2,026,234 63,383 MW 2,048,615 7 Other 8 Total (Lines 1 thru 7) FERC FORM NO. 1 (New 2-04) MW MW 303,805 26,798,188 Page 398 309,643 27,053,545 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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 $33,402 of sold revenue in column (g) for 2016. Schedule Page: 398 Line No.: 2 Column: g Service currently provided at $0 per MW. Schedule Page: 398 Line No.: 4 Column: g Includes Schedule 4 Energy Imbalance activity and Schedule 10 Generator Imbalance activity from Jan-Sep 2016 (prior to EIM go-live). FERC FORM NO. 1 (ED. 12-87) Page 450.1 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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 5,047 Hour of Firm Network Monthly Service for Self Peak (d) 12 800 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) 4,240 94 432 281 2 February 5,207 3 800 4,390 104 432 281 3 March 4,524 21 2000 3,723 88 432 281 12,353 286 1,296 843 4 Total for Quarter 1 5 April 4,958 22 1800 4,141 104 432 281 6 May 5,711 13 1800 4,908 86 436 281 7 June 7,906 19 1800 8 Total for Quarter 2 7,233 113 279 281 16,282 303 1,147 843 114 279 281 9 July 7,818 27 1800 7,144 10 August 7,420 16 1700 6,751 99 389 181 11 September 6,662 1 1700 5,992 100 389 181 19,887 313 1,057 643 12 Total for Quarter 3 13 October 5,298 9 1700 4,647 81 389 181 14 November 4,464 8 1900 3,834 60 389 181 15 December 4,424 1 800 16 Total for Quarter 4 3,758 96 389 181 12,239 237 1,167 543 60,761 1,139 4,667 2,872 17 Total Year to Date/Year FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 400 Line No.: 10 Column: b Updated due to contract change. Schedule Page: 400 Line No.: 10 Column: g Updated due to contract change. Schedule Page: 400 Line No.: 10 Column: h Updated due to contract change. Schedule Page: 400 Line No.: 11 Column: b Updated due to contract change. Schedule Page: 400 Line No.: 11 Column: g Updated due to contract change. Schedule Page: 400 Line No.: 11 Column: h Updated due to contract change. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD Year/Period of Report 2016/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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 12,561,394 4 Nuclear 9,382,747 Interdepartmental Sales) 23 Requirements Sales for Resale (See 24 Non-Requirements Sales for Resale (See 6 Hydro-Pumped Storage 25 Energy Furnished Without Charge 24,835,334 26 Energy Used by the Company (Electric 8,962,490 27 Total Energy Losses 28 TOTAL (Enter Total of Lines 22 Through 11 Power Exchanges: 12 Received 626,389 13 Delivered 631,238 14 Net Exchanges (Line 12 minus line 13) 27) (MUST EQUAL LINE 20) -4,849 15 Transmission For Other (Wheeling) 16 Received 38,799,934 17 Delivered 38,795,543 18 Net Transmission for Other (Line 16 minus 4,391 line 17) 19 Transmission By Others Losses 20 TOTAL (Enter Total of lines 9, 10, 14, 18 33,797,366 and 19) FERC FORM NO. 1 (ED. 12-90) 60,924 Dept Only, Excluding Station Use) through 8) 10 Purchases 3,838,736 instruction 4, page 311.) 2,891,193 8 Less Energy for Pumping 9 Net Generation (Enter Total of lines 3 67,308 instruction 4, page 311.) 5 Hydro-Conventional 7 Other 28,022,002 Page 401a 1,808,396 33,797,366 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission MONTHLY PEAKS AND OUTPUT Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 2,592,766 395,067 4,217 12 8:00 30 February 2,246,595 323,493 4,379 3 8:00 31 March 2,292,934 315,592 3,726 21 20:00 32 April 2,184,642 215,062 4,162 22 18:00 33 May 2,792,888 521,712 4,949 13 18:00 34 June 3,463,247 278,080 7,275 19 18:00 35 July 3,830,902 278,879 7,180 27 18:00 36 August 3,550,420 279,541 6,783 16 17:00 37 September 3,017,440 308,891 6,008 1 17:00 38 October 2,806,662 339,272 4,671 9 17:00 39 November 2,352,451 321,719 3,829 8 19:00 40 December 2,666,419 418,312 3,745 1 8:00 33,797,366 3,995,620 41 TOTAL FERC FORM NO. 1 (ED. 12-90) Page 401b Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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: Cholla 3 (b) Coal Tons 79488 9212 120.820 127.027 6.895 0.082 11878.731 Page 402 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoors 1962 1981 113.60 116 1801 0 116 116 38 123463997 1427089 20632826 145652703 6435774 174148392 1532.9964 2831466 10222085 0 885763 0 0 241803 932261 0 64093 1264621 594482 3060591 748889 1026121 22990093 0.1862 Gas MCF 2535 859048 5.276 19.912 23.180 0.275 11878.747 (c) Coal Tons 349611 9211 82.584 85.035 4.616 0.052 11357.896 Steam Over 50% Outdoors 1980 1981 312.30 266 3746 0 271 271 59 568884892 3921650 56958215 402697402 15035298 478612565 1532.5410 4556793 30177582 0 1866136 0 0 123229 1599731 0 295323 2045078 2020153 4149650 657491 906863 48398029 0.0851 Oil Gas Bbls MCF 3818 0 128155 0 84.281 0.000 114.010 0.000 21.182 0.000 0.241 0.000 11357.896 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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: Ocotillo 2 (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: Navajo (b) 0 0 0.000 0.000 0.000 0.000 0.000 Page 402.1 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoors 1960 1960 113.60 111 1402 0 110 110 11 65601000 137462 2444276 27273774 5186294 35041806 308.4666 0 2314211 0 229998 0 0 1069810 197108 0 34055 0 194985 240462 366331 70566 2081169 0.0317 Gas MCF 708050 1041281 2.964 3.268 3.139 0.035 11238.839 (c) Steam Units 1, 2, 3 Over 50% Outdoors 1974 1976 337.34 2284 22877 0 0 0 0 1353617002 25111 33220283 242720935 1865912 277832241 823.5971 2806368 36683933 0 2780518 0 0 1110671 4033697 85176 0 1588845 360847 7698403 2164107 753835 60066400 0.0444 Coal Tons 670604 10742 50.209 53.753 2.502 0.027 10672.516 Oil Bbls 6898 136668 76.082 92.375 16.093 0.172 10672.515 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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: Yucca 4 (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 5 (b) 0 0 0.000 0.000 0.000 0.000 0.000 Page 402.2 Comb. Turbine Over 50% Outdoor 1974 2008 72.40 50 15 0 54 0 1 254000 0 695439 7598967 0 8294406 114.5636 1459 0 0 0 0 0 0 1318 0 0 156 9731 0 189243 18909 220816 0.8694 Oil Gas Bbls MCF 586 0 138063 0 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 13383.441 0.000 (c) 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 2007 2008 60.50 49 2703 0 48 0 3 72021000 13711 794034 35863588 0 36671333 606.1377 267318 4125257 0 0 0 0 0 274204 0 0 3840 170337 0 427125 183666 5451747 0.0757 Oil Gas Bbls MCF 0 855780 0 1036931 0.000 2.658 0.000 4.820 0.000 4.649 0.000 0.057 0.000 12321.198 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 2 (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) 0 0 0.000 0.000 0.000 0.000 0.000 Page 402.3 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 1973 2002 53.10 49 137 0 55 0 0 1118430 0 1644091 22785643 0 24429734 460.0703 0 111054 0 0 0 0 0 57633 0 0 2080 0 0 2782154 0 2952921 2.6402 Gas MCF 40718 1049841 1.504 2.727 2.598 0.099 38221.176 Plant Name: Saguaro 3 (c) 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 2002 2002 78.30 78 260 0 79 0 0 12544200 0 56451 29858026 0 29914477 382.0495 0 862168 0 0 0 0 0 0 0 0 919 85422 0 346988 8966 1304463 0.1040 Gas MCF 0 185185 0 1054125 0.000 2.567 0.000 4.656 0.000 4.417 0.000 0.069 0.000 15561.592 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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: West Phoenix 2 (b) 0 0 0.000 0.000 0.000 0.000 0.000 Page 402.4 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 1973 1973 53.10 53 130 0 55 0 1 1663700 0 1727575 19666557 0 21394132 402.9027 26578 87034 0 0 0 0 20401 0 0 0 185 12744 0 114677 1129 262748 0.1579 Gas MCF 55963 1040299 0.858 1.555 1.495 0.052 34993.244 Plant Name: Sundance (c) 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 2002 2002 605.00 501 8934 0 420 0 13 234920000 681252 14166335 278673359 0 293520946 485.1586 0 12719016 0 0 0 0 674899 2360772 0 0 13786 763162 0 3003606 37303 19572544 0.0833 Gas MCF 0 2447116 0 1034754 0.000 2.866 0.000 5.198 0.000 5.023 0.000 0.054 0.000 10778.827 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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: West Phoenix 4 (b) 0 0 0.000 0.000 0.000 0.000 0.000 Page 402.5 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoors 2001 2003 135.60 111 2154 0 117 0 9 190449300 32909 6584058 83319659 0 89936626 663.2495 345906 7934763 0 0 0 0 583350 108616 0 0 7620 209008 0 1603780 26143 10819186 0.0568 Gas MCF 1632410 1042117 2.680 4.861 4.664 0.042 8932.358 Plant Name: West Phoenix 5 (c) 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoors 2003 2003 569.60 480 11778 0 506 0 32 1978180000 18896 18262267 291947465 0 310228628 544.6430 1496605 78064191 0 0 0 0 3570875 2181222 0 0 65329 1700212 0 5535149 139190 92752773 0.0469 Gas MCF 0 17634789 0 2092582 0.000 2.441 0.000 4.427 0.000 4.231 0.000 0.039 0.000 9326.585 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 2 (b) 0 0 0.000 0.000 0.000 0.000 0.000 Page 402.6 Nuclear Under 50% Outdoors 1986 1988 410.82 394 8784 0 382 0 194 3403812402 1113635 201247658 540967425 -14626540 728702178 1773.7748 8674981 28661096 4310962 2973719 0 0 2818796 13335581 7585133 0 693479 537422 1816405 2689085 802491 74899150 0.0220 Nuclear Kg Uranium 520 0 66704 0 0.000 0.000 55098.539 0.000 0.819 0.000 0.008 0.000 10281.884 0.000 Plant Name: Palo Verde 3 (c) 0 0 0.000 0.000 0.000 0.000 0.000 Nuclear Under 50% Outdoors 1988 1988 410.82 401 8007 0 382 0 223 3048930821 1676721 326620210 785035713 -21654967 1091677677 2657.3139 8677642 26014923 4312255 4397142 0 0 2788992 13498362 7587409 0 1899242 966779 6060164 5454470 1423015 83080395 0.0272 Nuclear Kg Uranium 472 0 66704 0 2809.712 0.000 55098.539 0.000 0.830 0.000 0.009 0.000 10281.884 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 402.7 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 402.8 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 Plant Line Plant Name: Four Corners 5 Name: Ocotillo 1 No. Name: Four Corners 4 (d) (e) (f) Coal Tons 1369614 8765 56.625 60.352 3.443 0.033 9717.608 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoors 1969 1970 515.40 773 5684 0 485 485 90 2486107218 27608 16806752 130952960 9671566 157458886 305.5081 2056000 83911366 0 5829947 0 0 626314 3787676 390193 1290602 1219574 2766636 17639347 3228736 2927857 125674248 0.0506 Gas MCF 146649 1018824 7.748 8.544 8.386 0.081 9717.608 FERC FORM NO. 1 (REV. 12-03) Coal Tons 1171276 8757 61.617 65.572 3.744 0.036 9627.551 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoors 1969 1970 515.40 780 4963 0 485 485 92 2149620002 36438 15722690 182377738 9678744 207815610 403.2123 1680677 78015271 0 5833585 0 0 626314 3736462 390193 1115922 1219574 3053291 22059372 8553696 5074663 131359020 0.0611 Gas MCF 178745 1020098 6.152 6.783 6.649 0.064 9627.551 Page 403 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoors 1960 1960 113.60 102 1431 0 110 110 13 67415000 152894 2357069 27049964 5186294 34746221 305.8646 0 2458394 0 201381 0 0 1059038 197108 0 34997 0 150308 215372 120192 166182 4602972 0.0683 Gas MCF 779647 1040349 2.860 3.153 3.031 0.036 12031.525 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 Plant Line Plant Name: Yucca 2 Name: Yucca 3 No. Name: Yucca 1 (d) (e) (f) 0 0 0.000 0.000 0.000 0.000 0.000 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 1971 2008 23.60 19 91 0 19 0 2 676000 33986 2435042 3954612 0 6423640 272.1881 1776 43761 0 0 0 0 573259 1246 0 0 501 5379 0 85505 0 711427 1.0524 Gas MCF 14151 1033979 1.705 3.092 2.991 0.065 21645.044 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 1971 2008 23.60 20 69 0 19 0 1 613000 0 684940 2739274 0 3424214 145.0938 1408 39607 0 0 0 0 0 988 0 0 76 1648 0 62497 980 107204 0.1749 Gas MCF 11696 1033979 1.867 3.386 3.275 0.065 19728.597 Page 403.1 0 0 0.000 0.000 0.000 0.000 0.000 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 1973 2008 72.40 54 516 0 55 0 1 8284000 0 653060 15491999 0 16145059 222.9981 23932 834288 0 0 0 0 0 16789 0 0 661 8913 0 54310 0 938893 0.1133 Gas MCF 189258 1032872 1.480 2.685 2.599 0.061 23597.148 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) 03/31/2017 This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 Plant Line Plant Name: Douglas Name: Saguaro 1 No. Name: Yucca 6 (d) (e) (f) 0 0 0.000 0.000 0.000 0.000 0.000 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 2007 2008 60.50 48 2621 0 48 0 2 73082000 0 857328 35512486 0 36369814 601.1540 239337 4325864 0 0 0 0 0 293570 0 0 3765 129772 0 358479 -5234 5345553 0.0731 Gas MCF 767582 1037305 3.108 5.636 5.433 0.059 10894.843 FERC FORM NO. 1 (REV. 12-03) Comb. Turbine Over 50% Outdoors 1972 1972 26.10 9 16 0 16 0 0 84000 9557 103952 5447219 0 5560728 213.0547 0 155390 0 0 0 0 0 1887 0 0 326 71366 0 231000 2242 462211 5.5025 0 0 0.000 0.000 0.000 0.000 0.000 Oil Bbls 601 138480 258.488 258.488 44.443 1.850 41623.621 Page 403.2 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 Comb. Turbine Over 50% Outdoors 1972 2002 53.10 55 115 0 55 0 0 2086100 0 1472486 15534458 0 17006944 320.2814 0 212049 0 0 0 0 0 64371 0 0 297 0 0 143869 742 421328 0.2020 Gas MCF 59301 1055581 1.972 3.576 3.388 0.102 30006.864 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 Plant Line Plant Name: Ocotillo 2 Name: West Phoenix 1 No. Name: Ocotillo 1 (d) (e) (f) 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 1972 1973 53.10 49 97 0 55 0 1 1557000 0 1470427 25223545 0 26693972 502.7113 0 95400 0 0 0 0 62469 39667 0 0 1316 110170 0 1520895 38012 1867929 1.1997 Gas MCF 37230 1038005 1.413 2.562 2.469 0.061 24820.122 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 1973 1973 53.10 51 124 0 55 0 1 1429000 0 1719176 20062942 0 21782118 410.2094 0 96121 0 0 0 0 62469 45304 0 0 338 120455 0 154602 0 479289 0.3354 Gas MCF 44352 1038730 1.195 2.167 2.086 0.067 32239.167 Page 403.3 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 1972 1973 53.10 51 140 0 55 0 1 1499900 6294 2312027 18119409 0 20437730 384.8913 51257 96992 0 0 0 0 39344 0 0 0 284 35042 0 167309 13008 403236 0.2688 Gas MCF 58172 1042423 0.919 1.667 1.599 0.065 40429.242 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 Plant Line Plant Name: West Phoenix 2 Name: West Phoenix 3 No. Name: West Phoenix 1 (d) (e) (f) 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoors 1976 2003 132.00 89 3205 0 88 0 4 136318499 0 481503 35731446 0 36212949 274.3405 68417 6083815 0 0 0 0 0 88488 0 0 5019 75246 0 779783 24936 7125704 0.0523 Gas MCF 1517988 1042322 2.210 4.008 3.845 0.045 11606.874 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoors 1976 2003 132.00 84 2584 0 88 0 5 100386345 10962 6251932 72700765 0 78963659 598.2095 29674 4590874 0 0 0 0 0 38379 0 0 4907 33376 0 2242863 27310 6967383 0.0694 Gas MCF 1143628 1040686 2.214 4.014 3.857 0.046 11855.774 Page 403.4 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoors 1976 2003 132.00 83 2802 0 88 0 3 160893053 1379 2180185 40905907 0 43087471 326.4202 111409 6814337 0 0 0 0 0 144092 0 0 5763 104473 0 980701 21251 8182026 0.0509 Gas MCF 1545234 1043088 2.432 4.410 4.228 0.042 10017.932 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 Plant Line Plant Name: Redhawk 2 Name: Palo Verde 1 No. Name: Redhawk 1 (d) (e) (f) 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoors 2002 2002 573.10 608 22295 0 492 0 33 2648103000 1846217 20170355 273701904 0 295718476 515.9980 115485 87648291 0 0 0 0 1837822 4765475 0 0 70490 797397 0 4167960 676859 100079779 0.0378 Gas MCF 18374373 2085603 2.630 4.770 4.574 0.033 7235.799 FERC FORM NO. 1 (REV. 12-03) 0 0 0.000 0.000 0.000 0.000 0.000 0 0 0.000 0.000 0.000 0.000 0.000 Combined Cycle Over 50% Outdoors 2002 2002 567.20 574 21559 0 492 0 14 2510879000 338563 3698884 239285334 0 243322781 428.9894 94217 86432648 0 0 0 0 1837829 3887879 0 0 68489 659546 0 3756925 501307 97238840 0.0387 Gas MCF 18145496 2082766 2.627 4.763 4.574 0.034 7525.896 Page 403.5 Nuclear Under 50% Outdoor 1986 1988 410.82 409 7775 0 382 0 221 2930003771 1750365 331870701 822270666 -16823886 1139067846 2772.6689 8879947 25012948 4310962 4323931 0 0 2741530 13387158 7585133 0 3638255 1004312 6426922 6480415 1229922 85021435 0.0290 0 0 0.000 0.000 0.000 0.000 0.000 Nuclear Kg Uranium 454 66704 2859.829 55098.539 0.830 0.009 10281.884 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) 03/31/2017 This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 Plant Line Plant Name: Name: No. Name: (d) (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 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 403.6 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) 03/31/2017 This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 Plant Line Plant Name: Name: No. Name: (d) (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 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 403.7 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) 03/31/2017 This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report End of 2016/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 Plant Line Plant Name: Name: No. Name: (d) (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 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 FOOTNOTE DATA Schedule Page: 402.4 Line No.: 5 Column: c 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: 403.5 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: 402.6 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. Schedule Page: 402.6 Line No.: -1 Column: c 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: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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 5 Total installed cap (Gen name plate Rating in MW) 0.00 0.00 6 Net Peak Demand on Plant-Megawatts (60 minutes) 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 Date of Report (Mo, Da, Yr) 03/31/2017 This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 0 0 0 20 0.0000 0.0000 0.0000 21 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 22 FERC FORM NO. 1 (REV. 12-03) Page 407 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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: (a) (b) 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) 0 Page 408 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report End of 2016/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) 0 FERC Licensed Project No. Plant Name: (d) 0 FERC Licensed Project No. Plant Name: (e) 0 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) 03/31/2017 (2) A Resubmission GENERATING PLANT STATISTICS (Small Plants) 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company Year/Period of Report 2016/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. (In MW) Plant Use No. (60 min.) (d) (e) (f) (a) (b) (c) 1 Solar Plants 2 Flagstaff 1997 0.93 151 2,566,632 3 Star 1998 0.22 654 2,035,345 4 Tempe 1998 0.01 5 Glendale Airport 1999 0.07 86 114,593 6 Gilbert 2001 0.12 251 56,928 7 Scottsdale Covered Parking 1999 0.29 602 557,305 8 Municipal Rooftops 1999 9 Yuma 2002 0.17 329 550,117 2002 0.18 371 162,310 10 Prescott Earu 12,817 51,361 11 Prescott 2001 2.71 5,433 2,393,945 12 Red Rock 2016 40.00 8,924 91,551,915 13 Phoenix 1998 9.45 84 23,882,862 14 Hyder I 2011 16.00 40,655 73,340,993 15 Hyder II 2013 14.00 37,104 51,811,899 16 Cotton Center 2011 17.00 38,993 80,506,466 17 Paloma 2011 17.00 37,662 66,071,021 18 US Airways Center 2011 0.18 276 1,350,091 19 Chase Field 2011 0.06 83 1,284,717 20 Chino Valley 2012 19.00 45,734 86,992,112 21 Foothills I & II 2013 35.00 99,843 143,313,165 22 APS Solar for Schools 2012 12.72 24,662 64,152,427 23 DVN1 2013 0.02 44 24 Palo Verde Emergengy OPS Center 2013 0.03 67 25 Gila Bend I 2014 16.00 52,515 26 Gila Bend II 2014 16.00 52,304 10.00 21,230 27 Carol Spring 2015 28 Desert Star 2015 29 Luke AFB 2015 528,504 30 Total Solar Operation/Maintenance 10.00 33,099 30,668,105 501,155 866,460,637 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 Page 32,362,873 237.16 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) 2016/Q4 End of Arizona Public Service Company 03/31/2017 (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. 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (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 2,768,368 2 9,085,062 3 2,194,693 4 1,598,678 5 494,169 6 1,949,708 7 8 3,316,196 9 880,587 10 881,922 11 2,288,798 12 2,527,501 13 4,583,812 14 3,700,850 15 4,735,674 16 3,886,531 17 7,418,737 18 20,338,106 19 4,578,532 20 4,094,662 21 5,042,859 22 23 24 6,883,883 25 26 27 3,236,287 28 3,066,811 29 3,653,458 4,112,242 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 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.: 27 Column: c No Installed Capacity/Net Gen because this is off the grid solar equipment that is being used to run a communications site. 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 2016/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. Line No. DESIGNATION 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 1 881.25 82 256.00 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 5,307.85 (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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. Line No. DESIGNATION 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 PALM VALLEY TUBA CITY TAP SAGUARO PLANT ORACLE ADAMS SANTA ROSA ASARCO ASARCO VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 69.00 115.00 115.00 115.00 115.00 115.00 115.00 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 TILBY WASH POWELL SUB SAN MANUEL SAN MANUEL MURAL ASARCO VISTA VISTA Designed (d) 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 115.00 115.00 115.00 115.00 115.00 (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 (1) STEEL (2) WOOD (2) WOOD (2) WOOD (2) WOOD (2) WOOD (2) WOOD (1) 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 15.90 60.00 41.50 21.06 47.15 11.00 3.81 3.02 5,307.85 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 1 881.25 82 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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. Line No. DESIGNATION 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 WILLOW LAKE UNDERGROUND OVERHEAD (NON-SPEC) RELATED TRANSMISSION EHV STRUCTURES TEMP LAND AND LAND RIGHTS VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 115.00 69.00 69.00 BAGDAD Designed (d) 115.00 (2) WOOD 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 49.00 30.68 2,835.64 1.64 5,307.85 Number Of Circuits (h) 1 30.68 1 881.25 82 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) 4,014,276 2,321,510 743,746 55,612 1,350,823 8,522 494,861 1,175,680 50,610 12,237,938 284,676 16,016,710 4,744,391 515,099 138,023 40,721 322,268 803,802 35,944 157,325 7,663 9,660,020 220,297 112,180 820,160 1,840,509 136,363,949 FERC FORM NO. 1 (ED. 12-87) Construction and Other Costs (k) Total Cost Operation Expenses (m) (l) 19,901,128 5,971,160 39,917,113 8,926,324 1,208,159 5,855,722 60,391,579 5,151,452 4,831,769 17,090,839 626,769 23,915,404 5,971,160 42,238,623 9,670,070 1,208,159 5,911,334 61,742,402 5,159,974 5,326,630 18,266,519 677,379 29,540,970 776,503 32,430,667 3,178,473 104,642,446 30,649,195 947,577 3,424,030 3,855,251 2,537,537 2,210,643 3,352,137 3,761,039 3,250,560 2,265,279 7,704,155 536,518 3,218,080 6,759,381 1,826,612 3,529,102 17,978 41,778,908 1,061,179 48,447,377 3,178,473 104,642,446 35,393,586 947,577 3,939,129 3,993,274 2,578,258 2,532,911 4,155,939 3,796,983 3,407,885 2,272,942 17,364,175 756,815 3,330,260 7,579,541 1,826,612 5,369,611 17,978 1,256,816,747 1,393,180,696 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 27,400,985 423 10,397,658 7,267,325 45,065,968 36 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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/1361ACSR 795R/1113A 795 AA 954 SSAC 954 ACSR 954 ACSR 1750 ACSR 1750 ACSR 1780 ACSR 954 AA 954 AA 2156 ACSS 2156 KCMIL 954 ACSR 954 ACSR 556 ACSR 556 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 3,665,194 1,324,874 203,127 869,382 3,321,098 4,048,916 1,611,847 374,308 1,012,053 68,982 1,021,582 85,094 42,236 390,432 78,429 519,018 381,847 933,461 141,199 352,384 414 7,389,772 1,041,361 3,600,766 46,640 74,057 435,033 93,110 18,029 12,019 2,785,385 6,122,495 5,672,649 1,663,288 4,137,737 1,565,545 6,704,094 1,203,882 4,485,834 4,206,368 7,433,024 39,196 16,026,636 6,250,720 7,821,426 618,139 857,317 13,492,925 374,911 383,526 13,883,708 22,953,329 2,380,164 1,961,387 3,113,685 2,115,819 433,334 392,494 229,551 2,854,367 7,144,077 5,757,743 1,705,524 4,528,169 1,643,974 7,223,112 1,585,729 5,419,295 4,347,567 7,785,408 39,610 23,416,408 7,292,081 11,422,192 618,139 857,317 21,734,711 374,911 383,526 20,216,553 22,953,329 2,380,164 2,008,027 3,187,742 2,550,852 526,444 410,523 241,570 136,363,949 1,256,816,747 1,393,180,696 8,241,786 6,332,845 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 27,400,985 423.1 10,397,658 7,267,325 45,065,968 36 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) 795 ACSR EXPENSES, EXCEPT DEPRECIATION AND TAXES Land rights, and clearing right-of-way) Land (j) 365,101 37,352,673 21,621 Construction and Other Costs (k) 3,055,685 53,911,128 625,284,582 5,308,497 315,726 8,128,884 136,363,949 FERC FORM NO. 1 (ED. 12-87) 1,256,816,747 Total Cost Operation Expenses (m) (l) Maintenance Expenses (n) Rents (o) 3,420,786 53,911,128 662,637,255 5,330,118 315,726 8,128,884 1,393,180,696 Page 27,400,985 10,397,658 7,267,325 27,400,985 10,397,658 7,267,325 423.2 Total Expenses (p) Line No. 1 2 3 4 5 6 45,065,968 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 45,065,968 36 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 FOOTNOTE DATA Schedule Page: 422.2 Line No.: 4 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.: 6 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.: 7 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 FERC FORM NO. 1 (ED. 12-87) Page 450.1 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 FOOTNOTE DATA (5) CO-OWNERS OF LINE 10 ARE M-S-R PUBLIC POWER AGENCY, SALT RIVER PROJECT, CITY OF VERNON, SOUTHERN CALIFORNIA PUBLIC AUTHORITY, AND U.S. DEPARTMENT OF ENERGY (6) CO-OWNERS OF LINE 11 ARE M-S-R PUBLIC POWER AGENCY, SALT RIVER PROJECT, CITY OF VERNON, SOUTHERN CALIFORNIA PUBLIC AUTHORITY, AND U.S. DEPARTMENT OF ENERGY (7) CO-OWNERS OF LINE 1 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC SERVICE OF NEW MEXICO (8) CO-OWNERS OF LINE 2 ARE EL PASO ELECTRIC COMPANY, PUBLIC SERVICE OF NEW MEXICO, AND SALT RIVER PROJECT (9) CO-OWNERS OF LINE 14 ARE SALT RIVER PROJECT AND ARIZONA PUBLIC SERVICE COMPANY (10) CO-OWNERS OF LINE 15 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC 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 THESE 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 FERC FORM NO. 1 (ED. 12-87) Page 450.2 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 FOOTNOTE DATA SEGREGATED IN THE COMPANY'S BOOKS FOR EACH TRANSMISSION LINE FERC FORM NO. 1 (ED. 12-87) Page 450.3 2016/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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) CIRCUITS PER STRUCTURE Present Ultimate (f) (g) 1 PALO VERDE SUN VALLEY 43.00 STEEL/LATTICE 4.00 1 1 2 SUN VALLEY TRILBY WASH 14.13 STEEL/LATTICE 8.00 1 2 3 OCOTILLO KYRENE 0.23 STEEL 1 1 4 COCONINO SOLDIER'S TRAIL 0.02 STEEL 1 1 5 CAVE CREEK GAVILAN PEAK 9.00 STEEL 15.00 1 1 6 DELANEY EGG RANCH 3.70 STEEL 8.00 2 2 7 COMMERCE DEER VALLEY 0.25 STEEL 10.00 1 1 8 HARQUAHALA TONOPAH 16.50 STEEL 16.00 1 1 9 SAN PEDRO FAIRVIEW 9.90 STEEL 17.00 1 1 10 SAN PEFRO FAIRVIEW 0.33 11 DEER VALLEY UNION HILLS 1.00 78.00 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 98.06 44 TOTAL FERC FORM NO. 1 (REV. 12-03) Page 424 Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Year/Period of Report 2016/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 Land and Land Rights (l) LINE COST Poles, Towers Conductors Asset and Fixtures and Devices Retire. Costs (n) (o) (m) 47,984,212 20,564,662 Line No. (h) R1780V ACSR Configuration and Spacing (j) 3 BUNDLE 18 R2156X ACSS SINGLE 230 14,795,500 6,340,928 21,136,428 2 R2156X ACSS SINGLE 230 57,662 24,712 82,374 3 A795V AL various 69 295,163 2,616 297,779 4 R795X ACSS various 69 4,517,540 1,936,089 6,453,629 5 R795X ACSS various 69 9,461,910 4,055,104 13,517,014 6 A795V AL various 69 495,753 212,465 708,218 7 R795X ACSS various 69 6,362,391 2,726,738 9,089,129 8 R795X ACSS various 69 4,834,582 2,071,963 6,906,545 9 UA2500T KCMIL various 69 529,605 226,973 756,578 10 UA2500T KCMIL various 69 5,014,216 2,148,950 7,163,166 Specification (i) Total (p) 68,548,874 1 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 94,348,534 FERC FORM NO. 1 (REV. 12-03) Page 425 40,311,200 134,659,734 44 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 424 Line No.: 4 Column: j SINGLE CKT/DELTA Schedule Page: 424 Line No.: 5 Column: j DOUBLE CKT/DELTA Schedule Page: 424 Line No.: 6 Column: j DOUBLE CKT/DELTA Schedule Page: 424 Line No.: 7 Column: j SINGLE CKT/DELTA Schedule Page: 424 Line No.: 8 Column: j SINGLE CKT/DELTA Schedule Page: 424 Line No.: 9 Column: j SINGLE CKT/DELTA Schedule Page: 424 Line No.: 10 Column: j SINGLE /PARALLEL CIRCUIT Schedule Page: 424 Line No.: 11 Column: j SINGLE /PARALLEL CIRCUIT FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 ACOMA - SCOTTSDALE D Primary (c) 69.00 2 ADAMS - BENSON T 115.00 Secondary (d) 12.00 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 9 ANTELOPE - PRESCOTT D 69.00 12.00 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 12.00 21 BAGDAD NEW TOWN - BAGDAD T 115.00 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 BALD MOUNTAIN - PRESCOTT VALLEY D 69.00 26 BASELINE - BUCKEYE D 69.00 12.00 27 BEARDSLEY - SURPRISE D 69.00 12.00 28 BELL - PEORIA D 69.00 12.00 29 BISCUIT FLATS - PHOENIX D 69.00 30 BLACK MESA #2 - GRAY MOUNTAIN D 69.00 31 BLACK PEAK(BOUSE APA) - PARKER T 161.00 69.00 32 BLACK PEAK(BOUSE APA) - PARKER D 69.00 12.00 33 BLUE RIDGE - BLUE RIDGE D 69.00 21.60 34 BLUE WATER - N. OF PARKER D 34.50 12.00 35 BONNEYBROOK - FLORENCE D 115.00 12.00 36 BOOTHILL - E. OF TOMBSTONE D 115.00 21.00 37 BOULEVARD - SCOTTSDALE D 69.00 12.00 38 BUCKEYE - BUCKEYE T 230.00 69.00 39 BUCKEYE - BUCKEYE D 69.00 12.00 40 BUFFALO - PHOENIX D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426 Tertiary (e) 12.40 12.00 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 D Primary (c) 69.00 Secondary (d) 12.00 D 69.00 12.00 3 CACTUS-SCOTTSDALE T 230.00 69.00 4 CACTUS-SCOTTSDALE D 69.00 12.00 5 CALDERWOOD - PEORIA D 69.00 12.00 6 CAMELBACK - SCOTTSDALE D 69.00 12.00 7 CAMERON - CAMERON D 69.00 12.00 8 CANAL - PHOENIX D 69.00 12.00 9 CAPITAL BUTTE - SEDONA D 69.00 12.00 10 CASA GRANDE - CASA GRANDE T 230.00 69.00 11 CASA GRANDE - CASA GRANDE T 230.00 12.00 12 CASA GRANDE - CASA GRANDE D 69.00 12.00 13 CAVE CREEK - CAVE CREEK D 69.00 12.00 14 CEDAR MOUNTAIN - WILLIAMS T 525.00 15 CENTURY - SCOTTSDALE D 69.00 12.00 16 CHANDLER - CHANDLER D 69.00 12.00 17 CHAPARRAL - SCOTTSDALE D 69.00 12.00 18 CHERYL - PHOENIX D 69.00 12.00 (a) 1 BUNYAN - NW. OF GILA BEND 2 BUTTE - TEMPE (b) Tertiary (e) 12.00 12.00 19 CHILDS - CAMP VERDE D 69.00 20 CHINO VALLEY - CHINO VALLEY D 69.00 12.00 345.00 34.50 12.00 21 CHOLLA - JOSEPH CITY A,T 525.00 22 CHOLLA - JOSEPH CITY A,T 525.00 23 CHOLLA - JOSEPH CITY A,T 345.00 230.00 24 CHOLLA - JOSEPH CITY A,T 345.00 69.00 25 CHOLLA - JOSEPH CITY A,T 230.00 69.00 26 CIELO GRANDE - PHOENIX D 69.00 12.00 27 CLINIC - SCOTTSDALE D 69.00 12.00 28 COCONINO - FLAGSTAFF T 230.00 69.00 29 COCONINO - FLAGSTAFF D 69.00 12.00 30 COCOPAH - W. OF YUMA D 69.00 12.00 31 COLDWATER - GOODYEAR D 69.00 12.00 32 COLORADO - N. OF PARKER D 69.00 12.00 33 COLTER - AVONDALE D 69.00 12.00 34 COMMERCE - PHOENIX D 69.00 12.00 35 CONLEY - SNOWFLAKE T 69.00 36 COOLIDGE - N. OF COOLIDGE D 12.40 37 COPPER CANYON - N. OF CAMP VERDE D 69.00 12.00 38 CORDES - CORDES JUNCTION D 69.00 12.00 39 CORNVILLE - CORNVILLE D 69.00 12.00 40 COTTON CENTER - N. OF GILA BEND D 69.00 12.00 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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) 1 COTTONWOOD - COTTONWOOD (b) D 2 COTTONWOOD - COTTONWOOD D Primary (c) 69.00 Secondary (d) 12.00 3 COUNTRY CLUB - PHOENIX D 69.00 12.00 4 COUNTRY CLUB - PHOENIX T 230.00 69.00 5 COUNTY LINE - TONOPAH D 69.00 12.00 6 CROSSROADS - N. OF PARKER D 34.50 12.00 7 DALE - SCOTTSDALE D 69.00 12.00 8 DALE - SCOTTSDALE D 69.00 9 DAVENPORT - E OF WILLIAMS D 69.00 12.00 D 69.00 12.00 10 DEADMAN WASH - PHOENIX 11 DEADMAN WASH - PHOENIX D 69.00 12 DEER VALLEY - PHOENIX T 230.00 69.00 13 DEER VALLEY - PHOENIX D 69.00 12.00 14 DEL RIO - PEORIA D 69.00 12.00 15 DELANEY - TONOPAH T 525.00 69.00 16 DELANO - PRESCOTT D 69.00 12.00 17 DESERT RIDGE - SCOTTSDALE D 69.00 12.00 18 DESERT SANDS - YUMA T 69.00 19 DESERT SKY - BUCKEYE D 69.00 12.00 20 DESERT SPRINGS - PHOENIX D 69.00 12.00 21 DEWEY - N. OF DEWEY D 69.00 12.00 22 DIXILETA - N. OF SCOTTSDALE D 69.00 12.00 23 DON LUIS - BISBEE D 69.00 12.00 24 DOUBLETREE - PHOENIX D 69.00 12.00 25 DOVE VALLEY - PHOENIX D 69.00 12.00 26 DOWNING - SCOTTSDALE D 69.00 12.00 27 DRAKE - PAULDEN D 69.00 28 DRY LAKE - HOLBROOK D 69.00 7.20 69.00 29 DUGAS - MAYER T 525.00 30 DUGAS - MAYER T 525.00 31 DURANGO - PHOENIX D 69.00 12.00 32 DYSART - SURPRISE D 69.00 12.00 33 EAGLE EYE - W. OF AGUILA T 230.00 69.00 34 EAST END - SCOTTSDALE D 69.00 12.00 35 EASTERN OFFICE - PHOENIX D 69.00 12.00 36 EASTGATE - CASA GRANDE D 69.00 12.00 37 EGG RANCH - TONOPAH D 69.00 12.00 38 EHRENBERG - EHRENBERG D 34.50 12.00 39 EL SOL - YOUNGTOWN T 230.00 69.00 40 EL SOL - YOUNGTOWN D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.2 Tertiary (e) 12.00 12.00 34.50 34.50 12.00 12.00 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 ELDEN - FLAGSTAFF D Primary (c) 69.00 2 ENCANTO - PHOENIX D 69.00 12.00 3 ESTRELLITA - GOODYEAR D 69.00 12.00 4 EVANS CHURCHILL - PHOENIX D 69.00 12.00 5 FAIRVIEW - N. OF DOUGLAS D 69.00 12.00 Secondary (d) 12.00 Tertiary (e) 6 FARMER - SURPRISE T 69.00 7 FESTIVAL RANCH - BUCKEYE D 69.00 12.00 8 FILLMORE - PHOENIX D 69.00 12.00 9 FISH SAWMILL - N. OF FLAGSTAFF D 69.00 12.00 10 FLORES - CONGRESS D 69.00 12.00 11 FLYING E - WICKENBURG D 69.00 12.00 12 FOOTHILLS - YUMA D 69.00 12.00 13 FORTIETH PLACE - PHOENIX D 69.00 12.00 14 FOUR CORNERS - FRUITLAND, NM A,T 525.00 345.00 14.00 15 FOUR CORNERS - FRUITLAND, NM A,T 345.00 230.00 14.40 16 FOUR CORNERS - FRUITLAND, NM A,T 230.00 69.00 4.16 17 GARFIELD - PHOENIX D 69.00 12.00 18 GARLAND PRAIRIE - E. OF WILLIAMS D 69.00 12.00 19 GATEWAY - PHOENIX D 69.00 12.00 20 GAVILAN PEAK - PHOENIX T 230.00 69.00 21 GAVILAN PEAK - PHOENIX D 69.00 12.00 22 GILA BEND - GILA BEND T 230.00 69.00 23 GILA BEND - GILA BEND D 69.00 12.00 24 GILBERT - GILBERT D 69.00 12.00 25 GILLESPIE#1 - BUCKEYE D 69.00 12.00 26 GLENDALE - GLENDALE D 230.00 12.00 27 GRAND CANYON - GRAND CANYON D 69.00 12.00 28 GRANITE CREEK - CHINO VALLEY T 69.00 29 GRANITE REEF - SCOTTSDALE D 69.00 12.00 30 GRAY MOUNTAIN - CAMERON D 69.00 21.60 31 GREENBRIER - GLENDALE D 69.00 12.00 32 GREENWAY - GLENDALE D 69.00 12.00 33 GREY BEARS - CHINO VALLEY D 69.00 12.00 34 GRISWOLD - PHOENIX D 69.00 12.00 35 HAMBLIN - CAMERON D 69.00 12.00 36 HANKS - N. OF FLAGSTAFF D 69.00 12.00 37 HAPPY VALLEY TEMP - PEORIA D 69.00 12.00 38 HARBOR - PHOENIX D 69.00 12.00 39 HARQUAHALA - TONOPAH D 69.00 12.00 40 HASHKNIFE - HEBER D 69.00 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 HATFIELD - PEORIA D Primary (c) 69.00 2 HAVASU - PARKER D 69.00 3 HAYDEN - HAYDEN D 21.00 7.00 4 HAYES GULCH - GLOBE D 69.00 21.00 5 HEARN - SURPRISE D 69.00 12.00 6 HEDGEPETH HILLS - PHOENIX D 69.00 12.00 7 HOHOKAM - PHOENIX D 69.00 12.00 12.00 Secondary (d) 12.00 12.00 8 HONEYWELL - PHOENIX D 69.00 9 HOODOO WASH - DATELAND T 525.00 10 HORN - HORN D 69.00 12.00 11 HOWARD MESA - WILLIAMS D 69.00 12.00 12 HUMBUG - PEORIA D 69.00 12.00 13 HYDER - DATELAND D 69.00 12.00 14 INDIAN BEND - PHOENIX D 69.00 12.00 15 INDIANOLA - PHOENIX D 69.00 12.00 16 IVALON - YUMA D 69.00 12.00 17 JACKSON STREET - PHOENIX D 69.00 12.00 18 JAVELINA - SURPRISE D 69.00 12.00 19 JOMAX - SCOTTSDALE D 69.00 12.00 20 KACHINA - KACHINA VILLAGE D 69.00 12.00 21 KAIBAB - WILLIAMS D 69.00 12.00 22 KEAMS CANYON - W. OF KEAMS CANYON D 69.00 21.00 23 KEARNY - KEARNY D 21.00 24 KIRKLAND JUNCTION - SE.OF KIRKLAND D 69.00 12.00 25 LAGUNA - SOMERTON D 69.00 12.00 26 LE BARRON HILL - FLAGSTAFF D 69.00 7.20 27 LEROUX - N. OF HOLBROOK D 69.00 12.00 28 LEUPP JUNCTION - W. OF WINSLOW D 69.00 21.00 29 LIBERTY IRON - PHOENIX D 69.00 30 LINCOLN STREET (230kV) - PHOENIX T 230.00 69.00 31 LINCOLN STREET NORTH - PHOENIX D 69.00 12.00 32 LINCOLN STREET WEST - PHOENIX D 69.00 12.00 33 LITCHFIELD - LITCHFIELD PARK D 69.00 12.00 34 LOMA VISTA - PHOENIX D 69.00 12.00 35 LONE PEAK - PHOENIX T 230.00 69.00 36 LONE PEAK - PHOENIX D 69.00 12.00 37 LONESOME VALLEY - PRESCOTT D 69.00 12.00 38 LOOKOUT - PHOENIX D 69.00 12.00 39 LUKE FIELD NORTH - LUKE AFB D 69.00 12.00 40 MAGNOLIA - STANTON 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) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 MARINE AIR BASE - YUMA D Primary (c) 69.00 2 MARINETTE - SUN CITY D 69.00 3 MARTINEZ WASH - WICKENBURG D 69.00 7.20 4 MAZATZAL - RYE D 69.00 21.00 5 MCGUIREVILLE - RIM ROCK D 69.00 12.00 6 MCCORMICK - SCOTTSDALE D 69.00 12.00 7 MCDOWELL - PHOENIX D 69.00 12.00 Secondary (d) 12.00 12.00 8 MCMICKEN - SURPRISE D 69.00 12.00 9 MEADOWBROOK - PHOENIX T 230.00 69.00 10 MEADOWBROOK - PHOENIX D 69.00 12.00 11 MERIDIAN - GLENDALE D 69.00 12 MERRILL - FLORENCE D 69.00 12.00 13 METRO - PHOENIX D 69.00 12.00 14 MILLER WASH - VALLE D 69.00 7.20 15 MILLIGAN - ELOY T 230.00 69.00 12.00 16 MILLIGAN TEMP - ELOY D 69.00 17 MINGUS - JEROME D 69.00 7.20 18 MITTRY - YUMA D 69.00 12.00 19 MOENKOPI - CAMERON T 525.00 20 MOENKOPI - CAMERON T 525.00 21 MONTE CRISTO - PHOENIX D 69.00 22 MOON VALLEY - PHOENIX D 69.00 12.00 23 MORGAN - PEORIA T 525.00 230.00 24 MORRISTOWN - MORRISTOWN D 69.00 12.00 25 MOUNTAIN VIEW - SUN CITY D 69.00 12.00 26 MT. FLOYD - SELIGMAN T 230.00 12.00 27 MUMMY MOUNTAIN - PARADISE VALLEY D 69.00 12.00 28 MUNDS PARK - S.OF FLAGSTAFF D 69.00 21.00 29 MURAL - BISBEE D 69.00 12.00 T 115.00 69.00 69.00 7.20 31 NADASY - N. OF WILLIAMS D 32 NAVAJO - PAGE A,T 525.00 33 NAVAJO - PAGE A,T 525.00 34 NAVAJO ARMY DEPOT - FLAGSTAFF D 69.00 12.00 35 NEW RIVER - NEW RIVER D 69.00 12.00 36 NEWMAN PARK - S. OF FLAGSTAFF D 69.00 7.20 37 NORTH GILA - YUMA T 525.00 38 NORTH GILA - YUMA T 525.00 69.00 39 NORTH VALLEY - PHOENIX D 69.00 12.00 40 OAK CREEK - OAK CREEK D 69.00 12.00 Page 426.5 12.00 12.00 12.00 30 MURAL - BISBEE FERC FORM NO. 1 (ED. 12-96) Tertiary (e) 34.50 12.00 34.50 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 Primary (c) 69.00 Secondary (d) 12.00 A,T 230.00 69.00 3 OCOTILLO - TEMPE A,T 230.00 4 OCOTILLO - TEMPE A,T 69.00 5 OLD HOME MANOR - CHINO VALLEY D 69.00 (a) 1 OBERLIN TEMP - SURPRISE (b) D 2 OCOTILLO - TEMPE Tertiary (e) 12.00 6 ORANGEWOOD - PHOENIX D 69.00 12.00 7 ORMES - MAYER D 69.00 4.16 8 OSBORNE TANK - FLAGSTAFF D 69.00 12.00 9 PADRE - FLAGSTAFF D 69.00 12.00 10 PALM VALLEY - GOODYEAR T 230.00 69.00 11 PALM VALLEY - GOODYEAR D 69.00 12.00 12 PALOMA - W. OF GILA BEND D 69.00 12.00 13 PALOMINAS -HEREFORD D 69.00 12.00 14 PANDA - GILA BEND A,T 15 PAPAGO BUTTE - SCOTTSDALE D 69.00 12.00 16 PARADISE - PHOENIX D 69.00 12.00 17 PARKS - PARKS D 69.00 12.00 18 PATTERSON - OUT OF BUCKEYE D 69.00 12.00 19 PATTON - OUT OF MORRISTON D 69.00 12.00 20 PAULDEN - PAULDEN D 69.00 12.00 21 PEBBLECREEK - GOODYEAR D 69.00 12.00 22 PEORIA - PEORIA D 69.00 12.00 23 PERRYVILLE - PERRYVILLE D 69.00 12.00 24 PICKET - SUPERIOR T 115.00 12.00 25 PIMA - GOODYEAR D 69.00 12.00 26 PINAL - GLOBE T 115.00 69.00 27 PINAL - GLOBE D 69.00 21.00 28 PINE SPRINGS - W. OF WILLIAMS D 69.00 7.20 29 PINNACLE PEAK - PHOENIX T 525.00 230.00 34.50 30 PINNACLE PEAK - PHOENIX T 345.00 230.00 14.40 31 PINNACLE PEAK - PHOENIX T 230.00 69.00 12.40 32 PIONEER - PHOENIX D 69.00 12.00 33 PLANET - NE. OF PARKER D 69.00 12.00 34 PLEASANT - GLENDALE D 69.00 12.00 35 POLAND JUNCTION - NW. OF MAYER D 69.00 12.00 36 POLK - PHOENIX D 69.00 12.00 37 POLK - PHOENIX D 69.00 12.00 38 POLLOCK -CHINO VALLEY D 69.00 12.00 230.00 39 POPLAR WASH - PEEPLES VALLEY D 69.00 7.20 40 PREACHER CANYON - STAR VALLEY T 345.00 69.00 FERC FORM NO. 1 (ED. 12-96) Page 12.00 426.6 21.00 12.00 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 D Primary (c) 69.00 Secondary (d) 21.60 D 69.00 4.60 3 PRESCOTT CHINO WELLS - CHINO VALLEY D 69.00 12.00 4 PRESCOTT CITY - PRESCOTT D 69.00 12.00 5 PYRAMID PEAK - GLENDALE D 69.00 12.00 6 QUAIL SPRINGS - SE. OF COTTONWOOD D 69.00 12.00 7 QUARTZSITE - QUARTZSITE D 69.00 12.00 (a) 1 PREACHER CANYON - STAR VALLEY 2 PRESCOTT CHINO WELLS - CHINO VALLEY (b) 8 QUECHAN - YUMA D 69.00 12.00 9 RACEWAY - PEORIA T 230.00 69.00 10 RAINBOW VALLEY - SE.OF BUCKEYE D 69.00 12.00 11 RAINTREE - SCOTTSDALE D 69.00 12.00 12 RAMON ASO - RED LAKE,N. OF WILLIAMS D 69.00 12.40 13 RAWHIDE - SCOTTSDALE D 69.00 12.00 14 REACH - SCOTTSDALE T 230.00 69.00 15 RED LAKE - E. OF WILLIAMS D 69.00 21.00 16 RED ROCK - RED ROCK T 115.00 12.00 17 REDONDO - YUMA D 69.00 12.00 18 REIDHEAD - SNOWFLAKE D 69.00 7.20 19 RINCON - WICKENBURG D 69.00 7.20 20 RIO SALADO - TEMPE D 69.00 12.00 21 RIO VISTA - SUN CITY D 69.00 12.00 22 RIVERSIDE - YUMA D 69.00 12.00 23 ROAD RUNNER - PHOENIX D 69.00 12.00 24 ROBBINS BUTTE - OUT OF BUCKEYE D 69.00 12.00 25 ROCK SPRINGS - ROCK SPRINGS D 69.00 12.00 26 ROGERS LAKE - SW. OF FLAGSTAFF D 69.00 7.20 27 ROSE GARDEN - PHOENIX D 69.00 12.00 28 ROUND VALLEY - KINGMAN T 230.00 29 SADDLE MOUNTAIN - W. OF TONOPAH D 69.00 30 SADDLEBROOK - ORACLE T 115.00 Tertiary (e) 12.40 12.00 12.00 31 SAGE VALLEY - VALLE D 69.00 12.00 32 SAGUARO 525kV - RED ROCK A,T 525.00 115.00 34.50 33 SAGUARO 230kV - RED ROCK A,T 230.00 115.00 12.40 34 SAGUARO 115kV - RED ROCK A,D 115.00 12.00 35 SALOME - S.E. OF SALOME D 69.00 12.00 36 SAN LUIS - SAN LUIS D 69.00 12.00 37 SAN LUIS (MEXICO CONN.) - SAN LUIS D 69.00 34.50 38 SAN MANUEL - SAN MANUEL D 115.00 46.00 39 SAN MANUEL - SAN MANUEL D 115.00 12.00 40 SAN PEDRO - W. OF DOUGLAS D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.7 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 SANDVIG - FLAGSTAFF D Primary (c) 69.00 2 SANGUINETTI - YUMA T 69.00 3 SANTA ROSA - SE. OF MARICOPA T 230.00 69.00 4 SARIVAL - GOODYEAR D 69.00 12.00 5 SEDONA - SEDONA D 69.00 12.00 6 SELIGMAN COMPRESSER STATION - SELIGMAN D 230.00 7 SHAW - PHOENIX D 69.00 12.00 8 SHEA - SCOTTSDALE D 69.00 12.00 9 SHERMAN STREET - PHOENIX D 69.00 12.00 D 69.00 12.00 10 SHOW LOW - SHOW LOW Secondary (d) 12.00 11 SHOW LOW - SHOW LOW D 69.00 12 SHUMWAY - SHOW LOW D 69.00 13 SHUMWAY - SHOW LOW D 69.00 14 SKUNK CREEK - GLENDALE D 69.00 12.00 15 SNOWFLAKE - SNOWFLAKE D 69.00 12.00 16 SOLDIERS TRAIL - FLAGSTAFF D 69.00 12.00 17 SONORA - SUPERIOR D 69.00 21.60 18 SOUTH O'NEIL - YUMA T 69.00 Tertiary (e) 12.40 12.00 19 SPANISH GARDENS - SURPRISE D 69.00 12.00 20 SPIDER WEB - FLAGSTAFF D 69.00 4.16 21 STAGECOACH - SCOTTSDALE D 69.00 12.00 22 STANTON - S. OF YARNELL D 69.00 7.20 23 STARDUST - SUN CITY WEST D 69.00 24 STOUT - PHOENIX D 69.00 12.00 25 STRAWBERRY - STRAWBERRY D 69.00 21.00 26 STURM RUGER - N. OF PRESCOTT D 69.00 4.16 27 STURM RUGER - N. OF PRESCOTT D 69.00 12.40 28 SUGARLOAF - SNOWFLAKE T 525.00 69.00 34.50 29 SUN VALLEY PARKWAY - BUCKEYE T 525.00 230.00 34.50 30 SUNDOG - PRESCOTT D 69.00 12.00 31 SUNNYSLOPE - PHOENIX T 230.00 69.00 13.80 32 SUNNYSLOPE - PHOENIX T 230.00 69.00 12.40 33 SUNNYSLOPE - PHOENIX D 69.00 12.40 34 SUNSHINE - WINSLOW D 69.00 12.00 35 SURPRISE - SURPRISE T 230.00 69.00 36 SURPRISE - SURPRISE D 69.00 12.00 37 SWITZER CANYON - FLAGSTAFF D 69.00 12.00 38 SYCAMORE - DUGAS D 69.00 7.20 39 TABLE MESA - NEW RIVER D 69.00 7.20 40 TAPCO - E. OF CLARKDALE D 69.00 2.40 FERC FORM NO. 1 (ED. 12-96) Page 426.8 12.40 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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) 1 TARTESSO TEMPORARY - BUCKEYE D Primary (c) 69.00 2 TAT MOMOLI - CASA GRANDE T 230.00 3 TEMPE - TEMPE D 69.00 12.00 4 TENTH STREET - YUMA D 69.00 12.00 5 THAYER - THAYER D 69.00 12.00 6 THIRTY-SECOND STREET - YUMA D 69.00 12.00 7 THOMPSON PEAK - SCOTTSDALE D 69.00 12.00 8 TOLTEC - ELOY D 69.00 12.00 9 TONALEA - TUBA CITY D 69.00 21.60 10 TONOPAH - TONOPAH D 69.00 12.00 11 TONTO - PAYSON D 69.00 21.00 12 TONTO - PAYSON D 69.00 13 TRIBLY WASH - SURPRISE T 230.00 69.00 14 TUBA CITY - TUBA CITY D 69.00 12.00 15 TURF - PHOENIX D 69.00 12.00 16 TUSAYAN -TUSAYAN D 69.00 12.00 17 TUSAYAN -TUSAYAN D 69.00 18 TUTHILL - BUCKEYE D 69.00 12.00 19 TWENTY - THIRD STREET-PHOENIX D 69.00 12.00 20 TWIN ARROWS - FLAGSTAFF T 69.00 21 UNION HILLS - PHOENIX D 69.00 12.00 22 UTTING - SE. OF BOUSE D 69.00 12.00 23 VALENCIA - BUCKEYE D 69.00 12.00 (b) Secondary (d) 12.00 24 VALLE - WILLIAMS D 69.00 21.00 25 VALLEY FARMS - FLORENCE T 115.00 69.00 26 VALLEY FARMS - FLORENCE D 69.00 12.00 27 VARNEY - SURPRISE D 69.00 12.00 28 VERDE - CLARKDALE T 230.00 69.00 29 VICKSBURG - S. OF VICKSBURG JUNCTION D 69.00 12.00 30 VISTA - CASA GRANDE D 69.00 12.00 31 WADDELL - SURPRISE D 69.00 12.00 32 WALDRIP - YUMA T 69.00 33 WATSON - BUCKEYE D 69.00 34 WELCH - ASHFORK D 69.00 2.40 35 WELLFIELD - PRESCOTT VALLEY D 69.00 12.00 36 WENDON TEMP - LA PAZ D 69.00 12.00 37 WEST PHOENIX - PHOENIX T 230.00 69.00 38 WEST PHOENIX - PHOENIX D 69.00 12.40 39 WESTBROOK - PEORIA D 69.00 12.00 T 525.00 230.00 Page 426.9 12.00 12.40 12.40 12.00 40 WESTWING - SUN CITY FERC FORM NO. 1 (ED. 12-96) Tertiary (e) 12.40 34.50 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 03/31/2017 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS Year/Period of Report 2016/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 WESTWING - SUN CITY T Primary (c) 525.00 2 WESTWING - SUN CITY T 525.00 3 WESTWING - SUN CITY T 230.00 4 WESTWING - SUN CITY D 69.00 12.00 5 WESTWING - SUN CITY T 230.00 69.00 Secondary (d) 6 WHITE SPAR - PRESCOTT D 69.00 12.00 7 WHITE TANKS - AVONDALE T 230.00 69.00 8 WHY - AJO D 69.00 21.60 9 WICKENBURG - WICKENBURG D 69.00 12.00 10 WILD BURRO - NEW RIVER D 69.00 7.20 11 WILD FLOWER - GOODYEAR D 69.00 12.00 12 WILHOIT - PRESCOTT D 69.00 12.00 13 WILLIAMS - WILLIAMS D 69.00 12.00 Tertiary (e) 12.40 12.40 14 WILLIS - GOODYEAR D 69.00 12.00 15 WILLOW LAKE - PRESCOTT T 230.00 115.00 12.40 16 WILLOW LAKE - PRESCOTT T 230.00 69.00 12.40 17 WINDMILL - SEDONA D 69.00 7.20 18 WINONA - WINONA D 69.00 12.00 19 WINSLOW - WINSLOW D 69.00 12.00 20 WINTERSBURG - TONOPAH D 69.00 12.00 21 WOODRUFF - HOLBROOK D 69.00 21.00 22 WOODY MOUNTAIN - FLAGSTAFF D 69.00 12.00 23 WUPATKI - FLAGSTAFF D 69.00 12.00 24 YALE - PHOENIX D 69.00 12.00 25 YARNELL - YARNELL D 69.00 12.00 26 YAVAPAI - CHINO VALLEY T 525.00 230.00 12.40 27 YAVAPAI - CHINO VALLEY T 230.00 69.00 12.40 28 YORKSHIRE - PHOENIX D 69.00 12.00 29 YOUNG'S CANYON - DONEY PARK T 345.00 69.00 30 YUCCA - YUMA T 161.00 69.00 31 YUMA PALMS TEMP - YUMA D 69.00 12.00 32 ZENIFF - SNOWFLAKE D 69.00 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 83 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) 2 1 2 3 2 83 188 1 capacitor bank-69kV 1 48 4 20 1 capacitor bank-69kV 1 5 5 9 1 6 capacitor bank-69kV 1 48 7 8 83 2 20 1 40 2 57 2 capacitor bank-69kV 1 14 20 1 capacitor bank-12kV 1 4 16 1 83 2 42 1 15 9 1 16 capacitor bank-69kV 1 7 9 10 11 12 13 capacitor bank-69kV 1 22 14 9 1 17 20 1 18 4 1 19 20 1 20 30 1 21 capacitor bank-115kV 5 49 22 20 1 capacitor bank-69kV 1 14 23 83 2 capacitor bank-12kV 2 10 24 capacitor bank-69kV 1 7 25 capacitor bank-69kV 2 22 26 40 2 20 1 27 83 2 28 capacitor bank-69kV 1 14 29 30 31 112 1 9 1 32 10 1 33 15 1 34 13 1 35 20 1 36 83 2 37 267 2 38 20 1 39 83 2 40 FERC FORM NO. 1 (ED. 12-96) 1 Page 427 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Number of Transformers In Service Capacity of Substation (In Service) (In MVa) (f) Number of Spare Transformers (g) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Type of Equipment (h) (i) capacitor bank-69kV Number of Units (j) Line Total Capacity No. (In MVa) (k) 1 1 10 7 1 167 4 2 522 3 3 capacitor bank-69kV 3 83 2 5 125 3 6 2 1 7 83 2 8 40 2 100 1 50 1 20 1 12 40 2 13 83 2 15 83 2 16 83 2 17 40 2 18 capacitor bank-12kV 1 4 48 4 125 14 9 10 11 1 14 19 38 2 1002 6 203 1 20 1 capacitor bank-525kV 1 569 21 shunt reactor-525kV 4 167 22 capacitor bank-345kV 2 282 23 143 1 24 150 2 25 83 2 capacitor bank-12kV 2 7 capacitor bank-12kV 2 7 26 27 40 2 355 2 40 2 capacitor bank-69kV 2 36 29 83 2 capacitor bank-69kV 1 14 30 83 2 capacitor bank-69kV 1 29 31 28 9 1 32 83 2 33 42 1 capacitor bank-12kV 2 5 34 35 36 40 2 20 1 20 1 40 2 FERC FORM NO. 1 (ED. 12-96) capacitor bank-12kV 4 12 37 38 capacitor bank 69kv 1 7 39 40 Page 427.1 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 40 Number of Spare Transformers CONVERSION APPARATUS AND SPECIAL EQUIPMENT Type of Equipment (h) (i) capacitor bank-69kV 2 capacitor bank-12kV 125 Number of Units (j) Line Total Capacity No. (In MVa) (k) 1 1 11 2 6 3 3 355 2 40 2 20 1 83 2 3 1 83 2 564 3 125 3 22 1 269 3 40 2 83 2 2 4 capacitor bank-69kV 2 14 5 6 capacitor bank-12kV 2 7 7 capacitor bank-69kV 1 29 8 capacitor bank-12kV 2 7 10 capacitor bank-69kV 1 29 11 capacitor bank-69kV 1 48 9 12 13 14 15 1 16 capacitor bank-12kV 2 10 17 18 19 4 1 83 2 capacitor bank-12kV 2 10 20 40 2 capacitor bank-69kV 1 14 21 83 2 capacitor bank-12kV 2 7 20 1 23 42 1 24 83 2 capacitor bank-12kV 2 4 25 123 3 capacitor bank-69kV 1 48 26 capacitor bank-69kV 3 22 3 27 28 1 269 22 1 shunt reactor-525kV 1 190 29 capacitor bank525kV 1 536 30 capacitor bank-12kV 2 7 31 83 2 125 3 32 100 2 33 41 1 capacitor bank-12kV 2 41 1 capacitor bank-12kV 41 1 capacitor bank-12kV 40 2 20 1 376 2 83 2 FERC FORM NO. 1 (ED. 12-96) 5 34 1 5 35 2 14 36 37 1 capacitor bank-12kV 2 5 38 39 capacitor bank-69kV Page 427.2 1 48 40 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 40 2 83 2 2 41 1 capacitor bank-12kV 1 4 3 83 2 capacitor bank-12kV 4 10 4 41 1 capacitor bank-12kV 4 10 5 6 20 83 1 7 2 1 capacitor bank-69kV 1 29 8 9 2 20 1 capacitor bank-69kV 1 7 10 20 1 capacitor bank-69kV 2 22 11 83 2 capacitor bank-69kV 2 29 12 83 2 capacitor bank-12kV 2 7 13 1025 3 1 shunt reactor-525kV 3 125 14 1400 2 1 shunt reactor-345kV 4 125 15 16 106 2 shunt reactor-230kV 2 200 167 4 capacitor bank-12kV 4 10 10 1 18 42 1 19 188 1 20 1 21 41 17 22 200 2 83 2 capacitor bank-69kV 2 30 23 83 2 capacitor bank-12kV 2 8 24 40 2 capacitor bank-69kV 1 14 100 2 9 1 25 26 27 28 29 41 1 1 2 30 1 31 41 capacitor bank-12kV 3 11 32 125 3 20 1 33 41 1 34 1 35 1 36 18 1 37 125 3 38 1 39 20 40 FERC FORM NO. 1 (ED. 12-96) Page 427.3 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 41 1 1 20 1 2 10 1 3 20 1 83 2 capacitor bank-69kV 1 14 5 83 2 capacitor bank-69kV 1 29 6 20 1 capacitor bank-12kV 2 5 7 83 2 8 10 1 10 1 11 2 12 4 9 40 13 capacitor bank-12kV 2 7 14 83 2 125 3 15 40 2 16 125 3 17 83 2 18 41 1 19 9 1 20 20 1 21 9 1 22 23 9 1 36 2 24 capacitor bank-69kV 2 29 25 1 26 20 1 27 6 1 28 29 30 188 1 83 2 capacitor bank-69kV 1 35 167 4 capacitor bank-12kV 8 19 83 2 33 83 2 34 31 32 376 2 35 41 1 36 40 2 37 83 2 38 40 2 39 1 40 FERC FORM NO. 1 (ED. 12-96) Page 427.4 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) (i) capacitor bank-12kV Line No. Total Capacity (In MVa) (k) Number of Units (j) 2 7 1 83 2 83 2 2 1 3 20 1 4 16 1 5 83 2 6 83 2 7 83 2 8 188 1 125 3 9 capacitor bank-69kV 1 48 10 11 41 1 capacitor bank-69kV 2 14 12 125 3 capacitor bank-12kV 4 10 13 188 1 14 1 15 1 16 1 2 17 7 1 18 capacitor bank-525kV 4 2,041 shunt reactor-525kV 10 646 19 20 21 83 2 83 2 600 1 9 1 capacitor bank-69kV 1 11 83 2 capacitor bank-69kV 1 48 22 23 1 24 25 50 1 26 83 2 27 9 1 28 9 1 1 50 1 1 capacitor bank-12kV 4 10 29 30 31 1 shunt reactor-525kV 2 380 capacitor bank-525kV 2 1,738 32 33 6 1 34 20 1 35 36 1 509 6 83 2 40 2 FERC FORM NO. 1 (ED. 12-96) shunt reactor-525kV 4 328 capacitor bank-525kV 2 979 37 38 39 capacitor bank-12kV Page 427.5 2 5 40 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 16 1 1 355 2 2 capacitor bank230kV 2 314 3 capacitor bank-69kV 1 48 4 5 125 3 6 4 1 7 1 8 9 1 10 188 1 1 83 2 11 20 1 12 20 1 13 40 2 15 125 3 14 capacitor bank-12kV 2 7 16 5 1 17 16 1 18 9 1 19 20 1 20 41 1 21 83 2 22 20 1 23 13 1 36 2 25 84 1 26 41 1 27 24 1 1 28 1872 3 190 29 2025 3 159 31 shunt reactor-525kV 1 30 1 752 4 83 2 4 1 33 1 34 20 9 1 83 2 capacitor bank-230kV 3 32 35 capacitor bank-69kV 2 29 36 capacitor bank-12kV 2 10 37 2 3 38 1 1 39 162 2 40 FERC FORM NO. 1 (ED. 12-96) Page 427.6 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 16 1 1 3 3 2 9 1 3 40 2 4 41 1 5 40 2 capacitor bank-69kV 2 22 6 16 1 capacitor bank-69kV 2 7 7 83 2 8 188 1 9 9 1 10 83 2 11 1 1 12 83 2 13 capacitor bank-69kV 1 48 14 376 2 4 1 50 1 20 1 17 1 18 1 19 83 2 20 83 2 21 15 capacitor bank-12kV 2 9 16 9 1 22 83 2 23 1 3 24 16 1 25 1 26 2 27 83 28 20 1 capacitor bank-69kV 1 7 29 30 31 1 1450 2 896 2 1 shunt reactor-525kV 22 1 2 20 40 4 167 32 33 capacitor bank-115kV 2 49 34 1 capacitor bank-69kV 2 7 35 2 capacitor bank-69kV 1 7 36 4 37 20 1 65 4 38 138 5 39 20 1 40 FERC FORM NO. 1 (ED. 12-96) capacitor bank34.5kV Page 427.7 1 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 60 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 2 355 2 capacitor bank-230kV 2 94 3 83 2 capacitor bank-69kV 2 29 4 40 2 5 6 83 2 7 83 2 8 83 2 40 2 9 9 1 capacitor bank-12kV 4 10 10 capacitor bank-69kV 2 22 11 capacitor bank-12kV 2 6 12 capacitor bank-69kV 2 14 13 83 2 14 40 2 15 20 1 1 2 capacitor bank-69kV 1 7 16 17 18 83 83 19 2 1 20 2 21 1 1 22 83 2 23 83 2 24 9 1 25 5 3 20 1 269 3 26 1 27 1 capacitor bank-69kV 1 14 28 29 600 1 shunt reactor-525kV 1 190 40 2 capacitor bank-69kV 2 14 167 1 188 1 83 2 30 31 32 capacitor bank-69kV 1 43 33 34 2 3 564 3 125 3 36 56 3 37 1 38 1 39 2 40 FERC FORM NO. 1 (ED. 12-96) capacitor bank-69kV Page 427.8 1 53 35 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Number of Transformers In Service Capacity of Substation (In Service) (In MVa) (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 1 83 2 3 40 2 4 20 1 5 83 2 6 83 2 7 41 1 1 2 16 9 2 capacitor bank-69kV 2 14 8 1 capacitor bank-69kV 1 10 10 40 2 capacitor bank-69kV 1 7 11 capacitor bank-21kV 4 10 188 1 20 1 83 2 9 1 41 1 18 83 2 19 83 2 21 11 1 22 40 2 23 2 3 24 188 1 25 41 1 41 1 200 2 9 12 13 capacitor bank-12kV 2 6 14 15 capacitor bank-12kV 6 7 capacitor bank-69kV 1 7 16 17 20 20 1 83 2 capacitor bank-69kV 1 7 capacitor bank-69kV 4 29 26 27 28 29 capacitor bank-12kV 4 14 30 83 2 31 83 2 33 1 34 20 1 35 10 1 36 564 3 capacitor bank-69kV 1 35 83 2 capacitor bank-12kV 4 10 32 41 1 4500 9 FERC FORM NO. 1 (ED. 12-96) 37 38 39 40 4 Page 427.9 This Report Is: Name of Respondent 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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) 41 1 376 2 CONVERSION APPARATUS AND SPECIAL EQUIPMENT Type of Equipment (i) shunt reactor-525kV Number of Units (j) Line Total Capacity No. (In MVa) (k) 1 3 571 capacitor bank-525kV 1 236 2 shunt reactor-230kV 2 212 3 4 5 1 40 2 376 2 7 3 1 8 36 2 83 capacitor bank-12kV capacitor bank-69kV 4 1 12 6 12 9 1 10 2 11 12 3 1 16 2 capacitor bank-69kV 1 41 1 capacitor bank-69kV 166 2 shunt reactor-230kV 6 13 1 7 14 1 25 15 376 2 16 1 1 17 3 1 18 20 2 19 18 1 20 4 1 21 20 1 capacitor bank-69kV 1 7 22 23 1 2 9 1 25 2 26 672 capacitor bank-12kV 4 10 24 83 100 1 27 20 1 28 150 1 84 1 20 1 capacitor bank-69kV 1 14 capacitor bank-69kv 1 25 29 30 31 1 32 33 34 35 36 37 38 39 40 FERC FORM NO. 1 (ED. 12-96) Page 427.10 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/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 STAETS (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 CORNERS SWITCHYARD ARE SALT RIVER PROJECT, FOUR CORNERS ACQUISITION, PUBLIC SERVICE OF NEW MEXICO, SOTHERN 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 FERC FORM NO. 1 (ED. 12-87) Page 450.1 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 FOOTNOTE DATA (9) CO-OWNERS OF WESTWING 525KV SWITCHYARD ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, TUCON ELECTRIC POWER COMPANY, PUBLIC SERVICE COMPANY 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 (D) SUBSTATIONS THAT APS DOES NOT OWN THE MAJORITY PORTION AND IS NOT OPERATING AGENT ARE NOT LISTED ON THIS REPORT Schedule Page: 426 Line No.: 1 Column: b Line No.: 1 Column: c A-ATTENDED D-DISTRIBUTION T-TRANSMISSION Schedule Page: 426 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 Line No.: 5 Column: k Line No.: 9 Column: k 4.8 MVa Schedule Page: 426 7.2 MVa Schedule Page: 426 Line No.: 11 Column: k Line No.: 12 Column: k Line No.: 14 Column: k Line No.: 19 Column: f Line No.: 22 Column: k Line No.: 23 Column: k Line No.: 24 Column: k Line No.: 25 Column: k 14.4 MVa Schedule Page: 426 3.6 MVa Schedule Page: 426 21.6 MVa Schedule Page: 426 3.5 MVA Schedule Page: 426 48.6 MVa Schedule Page: 426 14.4 MVa Schedule Page: 426 9.6 MVa Schedule Page: 426 7.2 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.2 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426 Line No.: 26 Column: k Line No.: 29 Column: k Line No.: 33 Column: f 21.6 MVa Schedule Page: 426 14.4 MVa Schedule Page: 426 10.4 MVa Schedule Page: 426.1 Line No.: 1 Column: k Line No.: 9 Column: k 9.6 MVa Schedule Page: 426.1 14.4 MVa Schedule Page: 426.1 Line No.: 21 Column: k Line No.: 22 Column: k Line No.: 23 Column: k Line No.: 26 Column: k Line No.: 27 Column: k Line No.: 30 Column: k Line No.: 31 Column: k Line No.: 34 Column: k Line No.: 39 Column: k 568.9 MVa Schedule Page: 426.1 166.7 MVa Schedule Page: 426.1 281.8 MVa Schedule Page: 426.1 7.2 MVa Schedule Page: 426.1 7.2 MVa Schedule Page: 426.1 14.4 MVa Schedule Page: 426.1 28.8 MVa Schedule Page: 426.1 4.8 MVa Schedule Page: 426.1 7.2 MVa Schedule Page: 426.2 Line No.: 1 Column: k Line No.: 5 Column: k Line No.: 7 Column: k Line No.: 8 Column: k 10.8 MVa Schedule Page: 426.2 14.4 MVa Schedule Page: 426.2 7.2 MVa Schedule Page: 426.2 28.8 MVa Schedule Page: 426.2 Line No.: 10 Column: k Line No.: 11 Column: k Line No.: 17 Column: k Line No.: 19 Column: f Line No.: 20 Column: k Line No.: 21 Column: k 7.2 MVa Schedule Page: 426.2 28.8 MVa Schedule Page: 426.2 9.6 MVa Schedule Page: 426.2 3.5 MVa Schedule Page: 426.2 9.6 MVa Schedule Page: 426.2 14.4 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.2 Line No.: 22 Column: k Line No.: 25 Column: k Line No.: 27 Column: k Line No.: 28 Column: f Line No.: 30 Column: k Line No.: 31 Column: k Line No.: 34 Column: k Line No.: 35 Column: k Line No.: 36 Column: k Line No.: 38 Column: k 7.2 MVa Schedule Page: 426.2 3.6 MVa Schedule Page: 426.2 21.6 MVa Schedule Page: 426.2 0.25 MVa Schedule Page: 426.2 535.8 MVa Schedule Page: 426.2 7.2 MVa Schedule Page: 426.2 4.8 MVa Schedule Page: 426.2 4.8 MVa Schedule Page: 426.2 14.4 MVa Schedule Page: 426.2 4.8 MVa Schedule Page: 426.3 Line No.: 3 Column: k Line No.: 4 Column: k Line No.: 5 Column: k Line No.: 8 Column: k Line No.: 9 Column: f 3.6 MVa Schedule Page: 426.3 9.6 MVa Schedule Page: 426.3 9.6 MVa Schedule Page: 426.3 28.8 MVa Schedule Page: 426.3 0.3 MVa Schedule Page: 426.3 Line No.: 10 Column: k Line No.: 11 Column: k Line No.: 12 Column: k Line No.: 13 Column: k Line No.: 17 Column: k Line No.: 24 Column: k Line No.: 25 Column: k Line No.: 30 Column: f Line No.: 32 Column: k 7.2 MVa Schedule Page: 426.3 21.6 MVa Schedule Page: 426.3 28.8 MVa Schedule Page: 426.3 7.2 MVa Schedule Page: 426.3 9.6 MVa Schedule Page: 426.3 7.6 MVa Schedule Page: 426.3 14.4 MVa Schedule Page: 426.3 0.81 MVa Schedule Page: 426.3 10.8 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.4 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.3 Line No.: 35 Column: f Line No.: 36 Column: f 0.1 MVa Schedule Page: 426.3 0.1 MVa Schedule Page: 426.4 Line No.: 5 Column: k Line No.: 6 Column: k Line No.: 7 Column: k 14.4 MVa Schedule Page: 426.4 28.8 MVa Schedule Page: 426.4 4.8 MVa Schedule Page: 426.4 Line No.: 11 Column: f Line No.: 14 Column: k Line No.: 25 Column: k Line No.: 26 Column: f Line No.: 31 Column: k Line No.: 32 Column: k Line No.: 40 Column: f 0.373 MVa Schedule Page: 426.4 7.2 MVa Schedule Page: 426.4 28.8 MVa Schedule Page: 426.4 0.1 MVa Schedule Page: 426.4 35.03 MVa Schedule Page: 426.4 19.2 MVa Schedule Page: 426.4 0.1 MVa Schedule Page: 426.5 Line No.: 1 Column: k Line No.: 3 Column: f 7.2 MVa Schedule Page: 426.5 0.1 MVa Schedule Page: 426.5 Line No.: 12 Column: k Line No.: 13 Column: k Line No.: 14 Column: f Line No.: 19 Column: k Line No.: 24 Column: k Line No.: 29 Column: k Line No.: 31 Column: f Line No.: 33 Column: k Line No.: 34 Column: f Line No.: 36 Column: f 14.4 MVa Schedule Page: 426.5 9.6 MVa Schedule Page: 426.5 0.1 MVa Schedule Page: 426.5 2,041.3 MVa Schedule Page: 426.5 10.8 MVa Schedule Page: 426.5 9.6 MVa Schedule Page: 426.5 0.1 MVa Schedule Page: 426.5 1,737.6 MVa Schedule Page: 426.5 6.25 MVa Schedule Page: 426.5 0.1 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.5 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.5 Line No.: 37 Column: k Line No.: 38 Column: k Line No.: 40 Column: k 328.4 MVa Schedule Page: 426.5 978.6 MVa Schedule Page: 426.5 4.8 MVa Schedule Page: 426.6 Line No.: 3 Column: k Line No.: 7 Column: f Line No.: 8 Column: f Line No.: 9 Column: f 313.5 MVa Schedule Page: 426.6 3.5 MVa Schedule Page: 426.6 0.1 MVa Schedule Page: 426.6 0.1 MVa Schedule Page: 426.6 Line No.: 16 Column: k Line No.: 24 Column: f Line No.: 28 Column: f Line No.: 29 Column: k Line No.: 33 Column: f Line No.: 36 Column: k Line No.: 37 Column: k Line No.: 38 Column: f Line No.: 39 Column: f 7.2 MVa Schedule Page: 426.6 12.5 MVa Schedule Page: 426.6 0.1 MVa Schedule Page: 426.6 190.4 MVa Schedule Page: 426.6 3.5 MVa Schedule Page: 426.6 28.8 MVa Schedule Page: 426.6 9.6 MVa Schedule Page: 426.6 1.5 MVa Schedule Page: 426.6 0.56 MVa Schedule Page: 426.7 Line No.: 2 Column: f Line No.: 3 Column: f Line No.: 6 Column: k Line No.: 7 Column: k 3.3 MVa Schedule Page: 426.7 9.38 MVa Schedule Page: 426.7 21.6 MVa Schedule Page: 426.7 7.2 MVa Schedule Page: 426.7 Line No.: 12 Column: f Line No.: 15 Column: f Line No.: 16 Column: k Line No.: 18 Column: f 0.56 MVa Schedule Page: 426.7 3.5 MVa Schedule Page: 426.7 8.5 MVa Schedule Page: 426.7 0.1 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.6 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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.: 19 Column: f Line No.: 24 Column: f Line No.: 26 Column: f Line No.: 29 Column: k Line No.: 31 Column: f Line No.: 32 Column: k Line No.: 34 Column: f Line No.: 34 Column: k Line No.: 35 Column: k Line No.: 36 Column: k Line No.: 37 Column: k 0.1 MVa Schedule Page: 426.7 0.75 MVa Schedule Page: 426.7 0.25 MVa Schedule Page: 426.7 7.2 MVa Schedule Page: 426.7 0.25 MVa Schedule Page: 426.7 166.8 MVa Schedule Page: 426.7 22.4 MVa Schedule Page: 426.7 49.2 MVa Schedule Page: 426.7 7.2 MVa Schedule Page: 426.7 7.2 MVa Schedule Page: 426.7 3.6 MVa Schedule Page: 426.8 Line No.: 3 Column: k Line No.: 4 Column: k 93.6 MVa Schedule Page: 426.8 28.8 MVa Schedule Page: 426.8 Line No.: 10 Column: k Line No.: 11 Column: k Line No.: 13 Column: k Line No.: 16 Column: k Line No.: 17 Column: f Line No.: 20 Column: f Line No.: 22 Column: f Line No.: 26 Column: f Line No.: 28 Column: k Line No.: 29 Column: k Line No.: 30 Column: k 9.6 MVa Schedule Page: 426.8 21.6 MVa Schedule Page: 426.8 14.4 MVa Schedule Page: 426.8 7.2 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 4.5 MVa Schedule Page: 426.8 14.4 MVa Schedule Page: 426.8 190.4 MVa Schedule Page: 426.8 14.4 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.7 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.8 Line No.: 33 Column: k Line No.: 34 Column: f Line No.: 38 Column: f Line No.: 39 Column: f Line No.: 40 Column: f 43.2 MVa Schedule Page: 426.8 1.68 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 Line No.: 8 Column: k Line No.: 9 Column: f 14.4 MVa Schedule Page: 426.9 1.12 MVa Schedule Page: 426.9 Line No.: 10 Column: k Line No.: 11 Column: k Line No.: 12 Column: i Line No.: 12 Column: k Line No.: 16 Column: k Line No.: 17 Column: k Line No.: 22 Column: f Line No.: 24 Column: f Line No.: 26 Column: k Line No.: 28 Column: k Line No.: 30 Column: k Line No.: 34 Column: f Line No.: 36 Column: f Line No.: 37 Column: k Line No.: 38 Column: k Line No.: 1 Column: k Line No.: 2 Column: k 9.6 MVa Schedule Page: 426.9 7.2 MVa Schedule Page: 426.9 capacitor bank - 21.6kV Schedule Page: 426.9 9.6 MVa Schedule Page: 426.9 7.2 MVa Schedule Page: 426.9 7.2 MVa Schedule Page: 426.9 10.5 MVa Schedule Page: 426.9 1.5 MVa Schedule Page: 426.9 7.2 MVa Schedule Page: 426.9 28.8 MVa Schedule Page: 426.9 14.4 MVa Schedule Page: 426.9 0.15 MVa Schedule Page: 426.9 10.4 MVa Schedule Page: 426.9 35.03 MVa Schedule Page: 426.9 9.6 MVa Schedule Page: 426.10 571.2 MVa Schedule Page: 426.10 236.1 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.8 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Name of Respondent This Report is: (1) X An Original (2) A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.10 Line No.: 10 Column: f Line No.: 13 Column: f Line No.: 14 Column: k Line No.: 17 Column: f Line No.: 21 Column: f Line No.: 22 Column: k Line No.: 23 Column: f Line No.: 24 Column: k Line No.: 29 Column: k Line No.: 30 Column: k 0.25 MVa Schedule Page: 426.10 15.6 MVa Schedule Page: 426.10 7.2 MVa Schedule Page: 426.10 0.5 MVa Schedule Page: 426.10 3.5 MVa Schedule Page: 426.10 7.2 MVa Schedule Page: 426.10 0.1 MVa Schedule Page: 426.10 9.6 MVa Schedule Page: 426.10 14.4 MVa Schedule Page: 426.10 25.2 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.9 Date of Report Year/Period of Report (Mo, Da, Yr) 03/31/2017 2016/Q4 Name of Respondent This Report Is: 20170406-8017 FERC PDF (Unofficial) 03/31/2017 (1) X An Original Arizona Public Service Company (2) A Resubmission Date of Report (Mo, Da, Yr) 03/31/2017 Year/Period of Report 2016/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 Credited Credited Company (a) (b) (c) (d) 1 Non-power Goods or Services Provided by Affiliated 2 Common stock dividends Pinnacle West Capital Corporation 438 281,300,000 3 Share of estimated income taxes Pinnacle West Capital Corporation 236 26,863,761 4 Share of withholding and payroll taxes Pinnacle West Capital Corporation 236,241,408 250,381,854 Pinnacle West Capital Corporation 228.3 100,479,039 5 Share of pension and other post retirement 6 benefits contributions 7 Share of employee benefits (excluding pension and Pinnacle West Capital Corporation 228.3,925,926 149,669,870 Pinnacle West Capital Corporation 143,232,242 79,979,284 10 Shared services Pinnacle West Capital Corporation various 26,614,490 11 Compensation paid in stock Pinnacle West Capital Corporation various 22,680,736 21 Equity Infusion Pinnacle West Capital Corporation 207 42,000,000 22 VEBA (Benefits) Reimbursement Pinnacle West Capital Corporation 128 14,590,322 23 Shared services- 4CA Pinnacle West Capital Corporation various 11,220,675 24 Four Corners Capital- 4CA Pinnacle West Capital Corporation 131 26,510,844 25 Four Corners Reclamation Funding- 4CA Pinnacle West Capital Corporation 131 991,874 26 Four Corners Coal- 4CA Pinnacle West Capital Corporation 131 248,325 27 Four Corners Liquidated Damanges- 4CA Pinnacle West Capital Corporation 131 1,487,621 28 Four Corners O&M- 4CA Pinnacle West Capital Corporation 131 4,491,811 29 Four Corners Shared Services- 4CA Pinnacle West Capital Corporation 131 539,492 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 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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) 03/31/2017 2016/Q4 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 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 20170406-8017 FERC PDF (Unofficial) 03/31/2017 Document Content(s) Form120161200007.PDF..................................................1-364