20180509-8003 FERC PDF (Unofficial) 05/09/2018 THIS FILING IS Item 1: An Initial (Original) Submission OR X 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) 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 1,168 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 168 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 "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. 20180509-8003 FERC PDF (Unofficial) 05/09/2018 1/3-Q: REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER IDENTIFICATION 02 Year/Period of Report 2017/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 EVP Public Policy/Gen Counsel 07 Address of Contact Person (Street, City, State, Zip Code) 400 North 5th Street, Phoenix, AZ 85004 08 Telephone of Contact Person,Including 09 This Report Is Area Code (1) An Original (602) 250-2952 (2) X A Resubmission 10 Date of Report (Mo, Da, Yr) 05/09/2018 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 05/09/2018 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission LIST OF SCHEDULES (Electric Utility) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA". Line No. Title of Schedule Reference Page No. (b) (a) 1 General Information 101 2 Control Over Respondent 102 3 Corporations Controlled by Respondent 103 4 Officers 104 5 Directors 105 6 Information on Formula Rates 106(a)(b) 7 Important Changes During the Year 108-109 8 Comparative Balance Sheet 110-113 9 Statement of Income for the Year 114-117 10 Statement of Retained Earnings for the Year 118-119 11 Statement of Cash Flows 120-121 12 Notes to Financial Statements 122-123 13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b) 14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201 15 Nuclear Fuel Materials 202-203 16 Electric Plant in Service 204-207 17 Electric Plant Leased to Others 213 18 Electric Plant Held for Future Use 214 19 Construction Work in Progress-Electric 216 20 Accumulated Provision for Depreciation of Electric Utility Plant 219 21 Investment of Subsidiary Companies 224-225 22 Materials and Supplies 227 23 Allowances 228(ab)-229(ab) 24 Extraordinary Property Losses 230 25 Unrecovered Plant and Regulatory Study Costs 230 26 Transmission Service and Generation Interconnection Study Costs 231 27 Other Regulatory Assets 232 28 Miscellaneous Deferred Debits 233 29 Accumulated Deferred Income Taxes 234 30 Capital Stock 250-251 31 Other Paid-in Capital 253 32 Capital Stock Expense 254 33 Long-Term Debt 256-257 34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261 35 Taxes Accrued, Prepaid and Charged During the Year 262-263 36 Accumulated Deferred Investment Tax Credits 266-267 FERC FORM NO. 1 (ED. 12-96) Page 2 Remarks (c) Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission LIST OF SCHEDULES (Electric Utility) (continued) Year/Period of Report 2017/Q4 End of Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA". Line No. Title of Schedule Reference Page No. (b) (a) 37 Other Deferred Credits 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission LIST OF SCHEDULES (Electric Utility) (continued) Year/Period of Report 2017/Q4 End of Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA". Line No. Title of Schedule Reference Page No. (b) (a) 67 Transmission Line Statistics Pages 422-423 68 Transmission Lines Added During the Year 424-425 69 Substations 426-427 70 Transactions with Associated (Affiliated) Companies 429 71 Footnote Data 450 Stockholders' Reports Check appropriate box: Two copies will be submitted No annual report to stockholders is prepared FERC FORM NO. 1 (ED. 12-96) Page 4 Remarks (c) 20180509-8003 05/09/2018 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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 20180509-8003 05/09/2018 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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, 2017, as filed with the Securities and Exchange Commission. FERC FORM NO. 1 (ED. 12-96) Page 102 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission CORPORATIONS CONTROLLED BY RESPONDENT 1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. 2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. 3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions 1. See the Uniform System of Accounts for a definition of control. 2. Direct control is that which is exercised without interposition of an intermediary. 3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. 4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party. Line No. Name of Company Controlled Kind of Business (a) (b) 1 Bixco, Inc. Percent Voting Stock Owned (c) Inactive 100 3 APS Foundation, Inc. A non-profit corporation N/A 4 which makes distributions 5 to charitable organizations Footnote Ref. (d) 2 6 7 Axiom Power Solutions, Inc. Inactive 100 Inactive 100 8 9 PWENewco, Inc. 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 FERC FORM NO. 1 (ED. 12-96) Page 103 (1) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission OFFICERS Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. 2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made. Line No. 1 Title Name of Officer President and Chief Executive Officer (b) Donald E. Brandt Salary for Year (c) 1,353,461 Executive Vice President & Chief Operations Officer Mark A. Schiavoni 708,846 Executive Vice President and Advisor to the CEO of APS Randall K. Edington 287,692 Executive Vice President and General Counsel David P. Falck 584,231 Executive Vice President and Chief Financial Officer James R. Hatfield 639,231 Executive Vice President and Chief Nuclear Officer Robert S. Bement 599,038 Senior Vice President, Transmission, Distribution & Daniel T. Froetscher 379,423 Executive Vice President, Public Policy and General Jeffrey B. Guldner 498,269 Vice President, Controller and Chief Accounting Officer Denise R. Danner 344,615 Vice President, Communications John S. Hatfield 311,538 Vice President and Treasurer Lee R. Nickloy 307,654 Senior Vice President, Human Resources and Ethics Barbara M. Gomez 230,192 Vice President, Regulation Barbara D. Lockwood 298,462 Vice President, Human Resources and Ethics Donna M. Easterly 305,615 (a) 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 (ED. 12-96) Page 104 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 Advisor to the CEO of APS until his retirement in March 2017. Schedule Page: 104 Line No.: 7 Column: a Mr. Falck served as Executive Vice President and General Counsel of APS until May 2017, at which time he was appointed as Executive Vice President, Law of Pinnacle West. 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, PVGS, APS Schedule Page: 104 Line No.: 13 Column: a Senior Vice President, Transmission, Distribution & Customers Schedule Page: 104 Line No.: 15 Column: a Executive Vice President, Public Policy and General Counsel Mr. Guldner served as Senior Vice President, Public Policy until May 2017, at which time he was appointed as Executive Vice President, Public Policy and General Counsel. Schedule Page: 104 Line No.: 15 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.: 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 Senior Vice President, Human Resources and Ethics of APS until her retirement in July 2017. Schedule Page: 104 Line No.: 25 Column: a Ms. Lockwood was designated as a Section 16 Officer in May 2017. Schedule Page: 104 Line No.: 27 Column: a Ms. Easterly was appointed as Vice President, Human Resources and Ethics in February 2017 and was designated as a Section 16 Officer in May 2017. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission DIRECTORS Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated titles of the directors who are officers of the respondent. 2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk. Line No. Name (and Title) of Director (a) 1 Donald E. Brandt, Chairman, President and CEO Principal Business Address (b) Phoenix, Arizona 2 3 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 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) (1)05/09/2018 An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission INFORMATION ON FORMULA RATES FERC Rate Schedule/Tariff Number FERC Proceeding Does the respondent have formula rates? Year/Period of Report End of 2017/Q4 Yes X 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 ER18-1133 2 FERC Electric Tariff, Volume 5 ER16-1877 3 FERC Electric Rate Schedule No. 182 ER11-3926 4 FERC Electric Tariff, Volume 6 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 FOOTNOTE DATA Schedule Page: 106 Line No.: 4 Column: a Tariff Title updated to accurately reflect FERC.gov. The FERC Electric Tariff, Volume 6 (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. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) (1)05/09/2018 An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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)? Yes X No 2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website Line No. Accession No. 1 20180315-5190 Document Date \ Filed Date Docket No. Description 03/15/2018 ER18-1133 see footnote FERC Electric Tariff, Volume 2 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 FERC FORM NO. 1 (NEW. 12-08) Formula Rate FERC Rate Schedule Number or Tariff Number Page 106a 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 ER18-1133. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) (1)05/09/2018 An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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: 20180509-8003 FERC PDF (Unofficial) (1) 05/09/2018 An Original Arizona Public Service Company (2) X A Resubmission Date of Report 05/09/2018 Year/Period of Report 2017/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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 1. During the first quarter of 2017, the Taylor franchise renewal was approved by voters on March 14, 2017, and became effective June 16, 2017. During the fourth quarter of 2017, the Somerton franchise renewal was approved by voters on November 7, 2017, and will become effective April 27, 2018. As with all of Arizona Public Service Company’s (“APS”) municipal franchises, the referenced franchises include a 2% franchise fee, which is collected from the customers in the same way that transaction privilege tax (sales tax) is collected, and are renewed for terms of 25 years. County franchises do not include the collection and payment of franchise fees. 2. None 3. None 4. During quarter one: LFA038 Madison Subproperty: Grant Date: 2/10/2017 Grant Expires: 2/28/2020 Length of Terms: Paid in full Name of Parties: Cowley Companies, LLC Rent: $4,830.00 Other Conditions: Option to renew During quarter two: None. During quarter three: LTA058: Grant Date: 8/1/2017 Grant Expires: 7/31/2019 Length of Terms: One time; 2 years Name of Parties: APS & NNP III – Estrella Mountain Ranch, LLC Rent: $12,000.00 Other Conditions: N/A LTA070: Grant Date: 8/1/2017 Grant Expires: 8/1/2037 Length of Terms: 3 years Name of Parties: APS & Town of Wickenburg Rent: $18,545.00 Other Conditions: Next payment 8/1/2020 FERC FORM NO. 1 (ED. 12-96) Page 109.1 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) During quarter four: None. 5. The second 500/345 kV transformer at Four Corners was placed into service December 2017. 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, 2017 and 2016 (dollars in thousands): Commitments under Credit Facilities Outstanding Commercial Paper and Revolving Credit Facility Borrowings Amount of Credit Facilities Available Weighted-Average Commitment Fees December 31, 2016 December 31, 2017 $ 1,000,000 $ 1,000,000 — 1,000,000 $ 0.100% $ (135,500) 864,500 0.100% On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022. At December 31, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in May 2021 and the above-mentioned $500 million facility. 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, 2017, APS had no 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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, 2017 and 2016 (dollars in thousands): December 31, Maturity Dates (a) APS Pollution control bonds: Variable Fixed Total pollution control bonds Other Long-Term Debt Unamortized discount Unamortized premium Total Long-Term Debt (a) (b) Interest Rates 2029 2024-2029 (b) 1.75%-4.70% 2018-2046 1.43%-8.75% 2017 $ $ 35,975 147,150 183,125 4,455,988 (11,288) 8,049 4,635,874 2016 $ $ 35,975 147,150 183,125 3,904,686 (11,816) 4,506 4,080,501 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 1.77% at December 31, 2017 and 0.81% at December 31, 2016. The following table shows principal payments due on APS’s total long-term debt (dollars in thousands): APS Year 2018 2019 2020 2021 2022 Thereafter Total $ $ 82,000 600,000 250,000 — — 3,707,113 4,639,113 Credit Facilities and Debt Issuances On March 21, 2017, APS issued an additional $250 million par amount of its outstanding 4.35% senior unsecured notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures. On September 11, 2017, APS issued $300 million of 2.95% senior unsecured notes that mature on FERC FORM NO. 1 (ED. 12-96) Page 109.3 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) September 15, 2027. The net proceeds from the sale were used to refinance commercial paper and other indebtedness and to replenish cash used to fund capital expenditures. On November 30, 2017, PNW contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes. Contractual Obligations The following table summarizes APS’s contractual requirements as of December 31, 2017 (dollars in millions): 2018 Long-term debt payments, including interest: (a) $ Fuel and purchased power commitments (b) Renewable energy credits (c) Purchase obligations (d) Coal reclamation Nuclear decommissioning funding requirements Operating lease payments Total contractual commitments (a) (b) (c) (d) $ 290 2019-2020 $ 1,192 2021-2022 $ 310 Thereafter $ 5,959 Total $ 7,751 539 1,099 1,084 6,271 8,993 40 80 80 370 570 173 27 18 204 422 31 53 43 191 318 2 4 4 55 65 36 66 57 236 395 1,111 $ 2,521 $ 1,596 $ 13,286 $ 18,514 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, 2017. 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. Estimated minimum required pension contributions are zero for 2018, 2019 and 2020. 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, 2017, standby letters of credit totaled $5 million and will expire in 2018. As of December 31, 2017, surety bonds expiring through 2019 totaled $62 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. FERC FORM NO. 1 (ED. 12-96) Page 109.4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Authorizations On February 6, 2013, the ACC issued a financing order (Decision No. 73659) 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 was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. 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 2017 through December 31, 2017, were as follows: a. b. c. d. Total Type of Cost Union Negotiated Non-Union Base Salary Increases Special Increases Promotions Number of Increases 1,261 3,893 653 995 6,802 Annualized Costs $ 3,359,741 11,849,655 2,043,307 7,617,567 $ 24,870,270 COMMENTS: a. There were wage increases for a small number of IBEW employees during the first quarter who met special eligibility criteria. There were general wage increases for the IBEW (averaging 3.00%) 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 are 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. FERC FORM NO. 1 (ED. 12-96) Page 109.5 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 9. Legal Proceedings I. LITIGATION & ENVIRONMENTAL MATTERS UPDATE 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 coal combustion residuals (“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 pollution control 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. The Environmental Protection Agency (“EPA”) 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 best available retrofit technology (“BART”) determination for this facility. See below for details of the Cholla BART approval. Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 is approximately $400 million. In addition, APS and El Paso Electric Company (“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. The Navajo Transitional Energy Company, LLC (“NTEC”) had 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 purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. 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 Federal Implementation Plan (“FIP”), could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs. Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of selective catalytic reduction ("SCR") controls, was unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan (“SIP”) and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program. In September 2014, APS met with EPA to propose a compromise BART strategy. APS would permanently close Cholla Unit 2 and FERC FORM NO. 1 (ED. 12-96) Page 109.6 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. 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 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. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017. 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. The Arizona Department of Environmental Quality (“ADEQ”) has initiated a process to evaluate how to develop a state CCR permitting program that would cover electric generating units ("EGUs"), including Cholla. FERC FORM NO. 1 (ED. 12-96) Page 109.7 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR. Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. At this time, it is not clear whether EPA will initiate further notice-and-comment rulemaking to revise the federal CCR rules, nor is it clear what aspects of the federal CCR rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of these federal CCR regulations, on September 27, 2017 the United States Court of Appeals for the D.C. Circuit, the court overseeing these judicial challenges, ordered EPA to file by November 15, 2017, a list of federal regulatory provisions addressing CCR that are or likely will be revised through EPA’s reconsideration proceedings. While this filing identified certain provisions of the federal CCR regulations that EPA intends to revise, including allowances for risk-based groundwater protection standards for regulated CCR constituents for which no federal maximum contaminant level has been set, it is not clear at this time which specific provisions of the federal CCR rules will be modified, how they will be modified, or when such modification will occur. 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 2 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 APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings. 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 $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment FERC FORM NO. 1 (ED. 12-96) Page 109.8 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) monitoring program by April 15, 2018. If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by January 2019. Depending upon the results of such groundwater monitoring and data evaluations 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. Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. 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. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. At this time, the D.C. Circuit Court proceedings evaluating the legality of the Clean Power Plan remain on hold. Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. That proposal relies on EPA's current view as to the Agency's legal authority under Clean Air Act Section 111(d), which (in contrast to the Clean Power Plan) would limit the scope of any future Section 111(d) regulations to measures undertaken exclusively at a power plant's source of greenhouse gas ("GHG") emissions. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act. We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to develop regulations replacing the Clean Power Plan. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal. Other environmental rules that could involve material compliance costs include those related to effluent 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 FERC FORM NO. 1 (ED. 12-96) Page 109.9 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 the Office of Surface Mining Reclamation and Enforcement (“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 Endangered Species Act ("ESA") and National Environmental Policy Act ("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. 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. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings. Four Corners Coal Supply Agreement Arbitration On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the 2016 Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant. NTEC was originally seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC also alleged a shortfall in the Buyer’s purchases for the initial contract year of approximately $30 million. APS’s share of this amount is approximately $17 million. On September 20, 2017, NTEC amended its Demand for Arbitration removing its request for a declaratory judgment and at this time is only seeking relief for the alleged shortfall in the Buyer's purchases for the initial contract year. We cannot predict the timing or outcome of this arbitration; however we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. 4CA Matter On July 6, 2016, 4C Acquisition, LLC, a wholly-owned subsidiary of Pinnacle West (“4CA”), purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the FERC FORM NO. 1 (ED. 12-96) Page 109.10 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% interest in the event NTEC does not purchase the interest. At this time, since NTEC has not yet purchased the 7% interest, the alternate pricing provisions are applicable to 4CA as the holder of the 7% interest. These terms include a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula at December 31, 2017 is approximately $20 million, which is due to 4CA at December 31, 2018. In future years, there may be similar payments due from NTEC to 4CA under this formula. 4CA believes NTEC should continue to satisfy its contractual obligations related to these payments; however, if NTEC fails to meet its contractual obligations when due, 4CA will consider appropriate measures and potential impacts to the Company's financial statements. 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 United States Department of Energy (“DOE”) in the United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019. APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 retail rate case settlement, this regulatory liability is being refunded to customers (see Note 3). APS's next claim pursuant to the terms of the August 18, 2014, settlement agreement was submitted to the DOE in the fourth quarter of 2017 in the amount of $9 million (APS's share is $2.6 million). In February 2018, the DOE approved this claim. FERC FORM NO. 1 (ED. 12-96) Page 109.11 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 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"). Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS, APS anticipates finalizing the RI/FS in the summer or fall of 2018. 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, 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 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. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. 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. II. REGULATORY MATTERS Retail Rate Case Filings with the Arizona Corporation Commission (“ACC”) 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 excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 FERC FORM NO. 1 (ED. 12-96) Page 109.12 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%). On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement is an increase of 3.28% (the average annual bill impact for a typical APS residential customer is 4.54%). Other key provisions of the agreement include the following: • • • • • • • • • • an agreement by APS not to file another general retail rate case application before June 1, 2019; an authorized return on common equity of 10.0%; a capital structure comprised of 44.2% debt and 55.8% common equity; a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project; a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at Four Corners; a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate; an expansion of the PSA to include certain environmental chemical costs and third-party battery storage costs; a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year, and not more than $15 million per year; an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account; rate design changes, including: • a change in the on-peak time of use period from noon-7 p.m. to 3 p.m.-8 p.m. Monday through Friday, excluding holidays; • non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component; • a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and FERC FORM NO. 1 (ED. 12-96) Page 109.13 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) • an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC. Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the 2017 Settlement Agreement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition. On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated and APS has filed a motion to intervene. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact. On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant is requesting that the ACC hold a hearing on her amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS), and if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. APS cannot predict the outcome of this matter. FERC FORM NO. 1 (ED. 12-96) Page 109.14 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Prior Rate Case Filing with the Arizona Corporation Commission On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement (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. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. Renewable Energy Standard. In 2006, the ACC approved the Renewable Energy Standard (“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 5-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015. In 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 costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision. On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 FERC FORM NO. 1 (ED. 12-96) Page 109.15 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement. On August 15, 2017, the ACC approved the 2017 RES Implementation Plan. On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million. APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor. On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program requiring APS to spend $10-$15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. The ACC has not yet ruled on APS's 2018 RES Implementation Plan. In September 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 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. On January 30, 2018, ACC Commissioner Tobin proposed a new standard in this proceeding which would broaden the RES to include a series of energy reform policies tied to clean energy sources. The proposal would rename the RES to the Clean Resource Energy Standard and Tariff ("CREST"). 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") annually for review by and approval of the ACC. 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 Plan 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 Plan budget on November 25, 2015. In its decision, the ACC also ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standards; however, the ACC FERC FORM NO. 1 (ED. 12-96) Page 109.16 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its Lost Fixed Cost Recovery Mechanism (“LFCR”) mechanism. On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed 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 Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan. On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million. 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 Commissioners 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. Power Supply Adjustor Mechanism and Balance. The Power Supply Adjustor (“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; FERC FORM NO. 1 (ED. 12-96) Page 109.17 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) • 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 or refunded 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 2017 and 2016 (dollars in thousands): Twelve Months Ended December 31, 2017 Beginning balance $ 2016 12,465 $ (9,688) Deferred fuel and purchased power costs — current period 48,405 60,303 Amounts refunded/(charged) to customers 14,767 (38,150) Ending balance $ 75,637 $ 12,465 The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017, the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh. On November 30, 2017, APS submitted its calculation for the 2018 PSA year beginning February 1, 2018. The current PSA rate is $.004555 per kWh consisting of a forward component of $.002009 per kWh and a historical component of $.002546 per kWh. FERC FORM NO. 1 (ED. 12-96) Page 109.18 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, the Federal Energy Regulatory Commission (“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, 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. Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 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, 2017. On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans. A transmission customer intervened and protested certain aspects of APS’s filing. FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed. APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 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 FERC FORM NO. 1 (ED. 12-96) Page 109.19 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were first 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. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. 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. DG sales losses are determined from the metered output from the DG units. 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). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its LFCR Adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease over 2017 levels). Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS. Tax Expense Adjustor Mechanism (“TEAM”) and FERC Tax Filing. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018. On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps. The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit. APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million annually through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction will be effective March 1, 2018. The second step will address the amortization of excess deferred taxes previously collected from customers. APS is analyzing the final impact of the Tax Act provisions related to deferred taxes and intends to make a second TEAM filing later in 2018. The TEAM expressly applies to APS's retail rates with the exception noted above. The Company expects to make a filing with FERC in the first quarter of 2018 seeking authorization to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates. FERC FORM NO. 1 (ED. 12-96) Page 109.20 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Net Metering In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG 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 Administrative Law Judge 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 opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended opinion and order by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 Rate Case Decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems was replaced by a more formula-driven approach that utilizes 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 RCP 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 RCP method will be updated annually (between general retail 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 general retail rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS 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 August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility; • 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 general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017. FERC FORM NO. 1 (ED. 12-96) Page 109.21 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 asserted 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 filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review. 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. This adjustment is subsumed within the 2017 Settlement Agreement and its associated revenue requirement. Subpoena from Arizona Corporation Commissioner Robert Burns On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on 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 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 FERC FORM NO. 1 (ED. 12-96) Page 109.22 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 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 the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter. In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition. Renewable Energy Ballot Initiative On February 20, 2018, a coalition of renewable energy advocates filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to procure 50% of their energy supply from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The stated goal of the Clean Energy for a Healthy Arizona coalition is to complete the necessary steps to allow the initiative to be placed on the November 2018 Arizona elections ballot. The coalition must present over 225,000 verifiable signatures to the Secretary of State by July 5, 2018 to meet that goal. APS intends to oppose this effort. We believe the initiative is irresponsible and would result in negative impacts to Arizona utility customers, the Arizona economy and our company. We cannot predict the outcome of this matter. Clean Resource Energy Standard and Tariff On January 30, 2018, ACC Commissioner Tobin proposed the CREST, which consists of a series of energy reform policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the Integrated Resource Plan process. The ACC has not yet initiated any formal proceedings with respect to Commissioner Tobin’s proposal; however, on February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. APS cannot predict the outcome of this matter. FERC FORM NO. 1 (ED. 12-96) Page 109.23 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Four Corners SCE-Related Matters. On December 30, 2013, APS purchased Southern California Edison’s (“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 retail 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 included 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 provided 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 $56 million as of December 31, 2017 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment. 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. 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 other deductions 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. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending and APS cannot predict the outcome of the proceeding. SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a FERC FORM NO. 1 (ED. 12-96) Page 109.24 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Notice of Intent to file its SCR Rate Rider to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS intends to file the SCR Rate Rider in April 2018. Consistent with the 2017 Rate Case Decision, the rate rider filing will be narrow in scope and will address only costs associated with this specific environmental compliance equipment. Also, as provided for in the 2017 Rate Case Decision, APS will request that the rate rider become effective no later than January 1, 2019. Cholla On September 11, 2014, APS announced that it would close Unit 2 of Cholla 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. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($105 million as of December 31, 2017), 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. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026. Navajo Plant The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019. 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($99 million as of December 31, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant 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 this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted. 10. None 11. (RESERVED) 12. N/A 13. Directors – No changes during 2017. Officers – The following changes became effective February 13, 2017: • Donna Easterly was appointed Vice President, Human Resources and Ethics (formerly Vice President and Chief Procurement Officer); • Ann Becker was appointed Vice President and Chief Procurement Officer (formerly Vice President, Environmental and Chief Sustainability Officer); • Pat Dinkel was appointed Vice President, Environmental and Chief Sustainability Officer (formerly Vice President, Transmission & Distribution Operations); Jacob Tetlow was appointed Vice President, Transmission and Distribution Operations on February 22, 2017. On March 22, 2017, Randall K. Edington, Executive Vice President and Advisor to the CEO, retired. The following changes became effective May 17, 2017: • David Falck’s title changed from Executive Vice President and General Counsel of APS and Pinnacle West Capital Corporation to Executive Vice President, Law of Pinnacle West Capital Corporation; • Jeffrey Guldner’s title changed from Senior Vice President, Public Policy of APS to Executive Vice President, Public Policy and General Counsel of APS and Pinnacle West Capital Corporation. Barbara Gomez, Senior Vice President, Human Resources and Ethics, retired from the Company on July 28, 2017. Tammy McLeod, Vice President, Resource Management, retired from the Company on September 16, 2017. FERC FORM NO. 1 (ED. 12-96) Page 109.26 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) Bradley Albert was appointed Vice President, Resource Management on October 18, 2017. 14. N/A FERC FORM NO. 1 (ED. 12-96) Page 109.27 2017/Q4 Name of RespondentFERC PDF (Unofficial) This Report Is: 20180509-8003 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report 05/09/2018 End of 2017/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) 18,671,016,713 1,154,425,945 19,825,442,658 6,838,877,327 12,986,565,331 112,209,946 1,933,681 259,545,143 0 0 144,070,412 229,618,358 13,216,183,689 0 0 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 6,773,458 1,608,454 0 0 6,088,343 1,585,306 0 0 0 0 0 0 0 1,166,637,675 0 1,291,649 0 1,173,094,328 0 0 0 0 0 956,182,908 0 6,704,345 0 967,390,290 0 930,054 0 2,112,670 10,808,403 0 245,282,900 47,493,881 2,513,432 0 13,678 17,197,828 0 0 262,835,713 0 0 0 8,060,182 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 Name of RespondentFERC PDF (Unofficial) This Report Is: 20180509-8003 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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 -205,223 0 0 39,146,744 0 0 0 112,433,531 33,669,716 6,718,355 1,291,649 0 0 782,693,351 31,594,342 0 0 1,698,661,211 6,996,198 0 0 330,186 0 122,452,709 0 0 16,942,274 916,790,609 0 2,793,767,529 17,965,738,897 Prior Year End Balance 12/31 (d) 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 110 Line No.: 72 Column: c Deficient Deferred Income Taxes Regulatory Gross Up Schedule Page: 110 Line No.: 82 Column: c Excess Deferred Income Taxes Regulatory Gross Up FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of RespondentFERC PDF (Unofficial) This Report is: 20180509-8003 05/09/2018 (1) An Original Arizona Public Service Company (2) x A Resubmission Date of Report (mo, da, yr) Year/Period of Report 05/09/2018 end of 2017/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 2,590,807,686 18,400,365 0 0 37,511,652 2,533,954,091 0 0 0 -26,983,411 5,256,829,447 178,162,368 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 4,905,680,056 183,125,000 0 0 4,455,988,231 8,048,849 11,287,565 4,635,874,515 183,125,000 0 0 3,904,686,078 4,506,087 11,816,370 4,080,500,795 170,996,665 0 50,902 358,395,705 0 219,756 38,411,381 0 670,718,643 1,238,793,052 178,775,422 0 64,451 539,614,017 0 219,756 53,941,700 0 615,936,293 1,388,551,639 0 247,858,840 0 91,764,883 70,387,521 173,870,594 57,294,434 0 0 135,500,000 259,171,351 0 72,901,602 82,519,751 141,954,872 53,791,554 0 0 Name of RespondentFERC PDF (Unofficial) This Report is: 20180509-8003 05/09/2018 (1) An Original Arizona Public Service Company (2) x A Resubmission Date of Report (mo, da, yr) 05/09/2018 Year/Period of Report end of 2017/Q4 (continued) COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS) Line No. 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 Ref. Page No. (b) Title of Account (a) Matured Interest (240) Tax Collections Payable (241) Miscellaneous Current and Accrued Liabilities (242) Obligations Under Capital Leases-Current (243) Derivative Instrument Liabilities (244) (Less) Long-Term Portion of Derivative Instrument Liabilities Derivative Instrument Liabilities - Hedges (245) (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges Total Current and Accrued Liabilities (lines 37 through 53) DEFERRED CREDITS Customer Advances for Construction (252) Accumulated Deferred Investment Tax Credits (255) Deferred Gains from Disposition of Utility Plant (256) Other Deferred Credits (253) Other Regulatory Liabilities (254) Unamortized Gain on Reaquired Debt (257) Accum. Deferred Income Taxes-Accel. Amort.(281) Accum. Deferred Income Taxes-Other Property (282) Accum. Deferred Income Taxes-Other (283) Total Deferred Credits (lines 56 through 64) TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) FERC FORM NO. 1 (rev. 12-03) Page 113 266-267 269 278 272-277 Current Year End of Quarter/Year Balance (c) Prior Year End Balance 12/31 (d) 0 -6,412 233,378,715 7,778,757 97,937,711 38,411,381 0 0 941,853,662 0 -10,569 230,469,912 7,433,638 102,572,995 53,941,700 1,550,885 0 1,033,914,291 113,996,154 205,575,015 0 266,494,383 2,621,211,846 241,775 0 2,192,974,630 491,894,418 5,892,388,221 17,965,738,897 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 112 Line No.: 60 Column: c Excess Deferred Income Taxes Regulatory Gross Up Schedule Page: 112 Line No.: 64 Column: c Deficient Deferred Income Taxes Regulatory Gross Up FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission STATEMENT OF INCOME Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of Quarterly 1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. 2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. 3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. 4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. 5. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable 5. Do not report fourth quarter data in columns (e) and (f) 6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. 7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. 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 3,590,567,358 3,528,336,004 4 Operation Expenses (401) 320-323 1,700,647,667 1,741,835,152 5 Maintenance Expenses (402) 320-323 215,555,730 243,851,753 6 Depreciation Expense (403) 336-337 410,405,975 388,363,026 7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337 10,332,839 4,380,701 8 Amort. & Depl. of Utility Plant (404-405) 336-337 92,959,218 77,215,884 9 Amort. of Utility Plant Acq. Adj. (406) 336-337 10,873,443 10,873,443 3 Operating Expenses 10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 5,286 11 Amort. of Conversion Expenses (407) 12 Regulatory Debits (407.3) 15,413,637 6,688,721 13 (Less) Regulatory Credits (407.4) 10,812,474 5,867,920 14 Taxes Other Than Income Taxes (408.1) 262-263 209,852,878 191,154,808 15 Income Taxes - Federal (409.1) 262-263 24,846,914 8,943,120 16 262-263 2,651,314 5,828,524 - Other (409.1) 17 Provision for Deferred Income Taxes (410.1) 234, 272-277 825,305,721 718,918,056 18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 578,003,636 470,172,298 22 (Less) Gains from Disposition of Allowances (411.8) 52,764 31,586 23 Losses from Disposition of Allowances (411.9) 19,527 26,794 25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 2,929,995,989 2,922,013,464 26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 660,571,369 606,322,540 19 Investment Tax Credit Adj. - Net (411.4) 266 20 (Less) Gains from Disp. of Utility Plant (411.6) 21 Losses from Disp. of Utility Plant (411.7) 24 Accretion Expense (411.10) FERC FORM NO. 1/3-Q (REV. 02-04) Page 114 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission STATEMENT OF INCOME FOR THE YEAR (Continued) 9. Use page 122 for important notes regarding the statement of income for any account thereof. 10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. 11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income, and expense accounts. 12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122. 13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. 14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. 15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule. ELECTRIC UTILITY Current Year to Date Previous Year to Date (in dollars) (in dollars) (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 3,590,567,358 3,528,336,004 2 3 1,700,647,667 1,741,835,152 4 215,555,730 243,851,753 5 410,405,975 388,363,026 6 10,332,839 4,380,701 7 92,959,218 77,215,884 8 10,873,443 10,873,443 9 5,286 10 11 15,413,637 6,688,721 12 10,812,474 5,867,920 13 209,852,878 191,154,808 14 24,846,914 8,943,120 15 2,651,314 5,828,524 16 825,305,721 718,918,056 17 578,003,636 470,172,298 18 19 20 21 52,764 31,586 22 19,527 26,794 23 24 2,929,995,989 2,922,013,464 25 660,571,369 606,322,540 26 FERC FORM NO. 1 (ED. 12-96) Page 115 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission 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 Date of Report (Mo, Da, Yr) 05/09/2018 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) 660,571,369 606,322,540 1,615,595 1,284,485 23,726 4,665 2,593,422 2,268,268 1,500 24,125 5,805 2,504,171 47,010,623 90,678,130 2,048,061 142,553,034 261,158 42,140,186 84,594,492 5,744,862 133,049,032 5,423,892 1,245,727 3,077,950 2,099,141 2,483,399 101,136,116 112,121,357 3,134,998 105,051,238 111,531,104 275,140 -4,659,644 125,919 9,357,657 2,839,109 285,200 -8,757,164 -1,328,801 581,486 1,520,860 8,111,738 -5,851,775 36,283,452 7,112,486 -17,852,625 39,370,553 200,211,147 3,519,104 1,636,987 279,738 43,303 189,828,017 3,415,015 1,567,557 180,243 43,304 9,613,072 22,111,671 192,545,598 504,309,223 8,445,697 19,480,590 183,552,149 462,140,944 504,309,223 462,140,944 119 262-263 262-263 262-263 234, 272-277 234, 272-277 262-263 Page 117 Year/Period of Report 2017/Q4 End of Current 3 Months Ended Quarterly Only No 4th Quarter (e) Prior 3 Months Ended Quarterly Only No 4th Quarter (f) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 114 Line No.: 2 Column: h FERC Accounting Order on SCE Expiration Payment AC18-13-000 Schedule Page: 114 Line No.: 15 Column: h FERC Accounting Order on SCE Expiration Payment AC18-13-000 Schedule Page: 114 Line No.: 16 Column: h FERC Accounting Order on SCE Expiration Payment AC18-13-000 Schedule Page: 114 Line No.: 49 Column: d FERC Accounting Order on SCE Expiration Payment AC18-13-000 Schedule Page: 114 Line No.: 53 Column: d FERC Accounting Order on SCE Expiration Payment AC18-13-000 Schedule Page: 114 Line No.: 54 Column: d FERC Accounting Order on SCE Expiration Payment AC18-13-000 FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) Date of Report (Mo, Da, Yr) 05/09/2018 X A Resubmission STATEMENT OF RETAINED EARNINGS Year/Period of Report 2017/Q4 End of 1. Do not report Lines 49-53 on the quarterly version. 2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated undistributed subsidiary earnings for the year. 3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 - 439 inclusive). Show the contra primary account affected in column (b) 4. State the purpose and amount of each reservation or appropriation of retained earnings. 5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items in that order. 6. Show dividends for each class and series of capital stock. 7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings. 8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. 9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 Contra Primary Account Affected (b) Item (a) Line No. UNAPPROPRIATED RETAINED EARNINGS (Account 216) Balance-Beginning of Period Changes Adjustments to Retained Earnings (Account 439) Stock Compensation cumulative effect adjustment 146 TOTAL Credits to Retained Earnings (Acct. 439) Federal Income Taxes State Income Taxes 190 190 Current Quarter/Year Year to Date Balance (c) 2,331,244,870 Previous Quarter/Year Year to Date Balance (d) 2,148,493,189 8,803,672 ( ( ( TOTAL Debits to Retained Earnings (Acct. 439) Balance Transferred from Income (Account 433 less Account 418.1) Appropriations of Retained Earnings (Acct. 436) 8,803,672 2,913,624) 479,311) 504,309,223 3,392,935) 462,140,944 -301,600,002 ( 284,800,000) -301,600,002 ( 284,800,000) 2,533,954,091 2,331,244,870 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) Date of Report (Mo, Da, Yr) 05/09/2018 X A Resubmission STATEMENT OF RETAINED EARNINGS Year/Period of Report 2017/Q4 End of 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) 2,533,954,091 Previous Quarter/Year Year to Date Balance (d) 2,331,244,870 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 FOOTNOTE DATA Schedule Page: 118 Line No.: 4 Column: d 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. On August 3, 2017 the Commission approved the request via a Letter Order in Docket No. AC17-45-000. Schedule Page: 118 Line No.: 10 Column: d Income taxes related to the adoption of ASU 2016-09. Schedule Page: 118 Line No.: 11 Column: d 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission STATEMENT OF CASH FLOWS Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost. Line No. Description (See Instruction No. 1 for Explanation of Codes) (a) Current Year to Date Quarter/Year (b) Previous Year to Date Quarter/Year (c) 1 Net Cash Flow from Operating Activities: 2 Net Income (Line 78(c) on page 117) 504,309,223 462,140,944 4 Depreciation and Depletion 420,738,814 392,743,727 5 Amortization of UTL PLT; ACQ; ADJ; Prop Loss; Reg Study; Nuclear Fuel 184,945,634 169,846,214 3 Noncash Charges (Credits) to Income: 6 7 Deferred Fuel and Purchased Power -63,172,143 -22,152,543 8 Deferred Income Taxes (Net) 250,296,171 217,612,029 9 Investment Tax Credit Adjustment (Net) -4,587,276 23,081,869 10 Net (Increase) Decrease in Receivables -72,525,415 -13,310,332 11 Net (Increase) Decrease in Inventory 12 Net (Increase) Decrease in Allowances Inventory 13 Net Increase (Decrease) in Payables and Accrued Expenses -6,981,505 -267,615 477,840 -1,186,675 -12,498,319 -83,127,969 14 Net (Increase) Decrease in Other Regulatory Assets 14,966,453 -18,780,278 15 Net Increase (Decrease) in Other Regulatory Liabilities 76,677,143 16,585,435 16 (Less) Allowance for Other Funds Used During Construction 47,010,623 42,140,186 17 (Less) Undistributed Earnings from Subsidiary Companies 18 Other (provide details in footnote): 19 Other Current Assets 11,967,530 -2,590,342 20 Other Current Liabilities 47,904,600 46,996,386 21 Other Long Term Assets/Liabilities Net -166,523,041 -158,247,356 1,138,985,086 987,203,308 -1,320,765,123 -1,192,481,662 -76,011,687 -86,603,552 22,111,671 19,480,590 22,993,000 60,782,000 -1,395,895,481 -1,237,783,804 542,246,027 633,410,106 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission STATEMENT OF CASH FLOWS Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost. Line No. Description (See Instruction No. 1 for Explanation of Codes) (a) Current Year to Date Quarter/Year (b) Previous Year to Date Quarter/Year (c) 46 Loans Made or Purchased 47 Collections on Loans 48 Investment in Nuclear Decommissioning Trust and Sales (a) 49 Net (Increase) Decrease in Receivables -544,527,027 -635,691,074 715,473 3,514,388 14,846,823 31,075,486 -16,567,986 -13,544,694 -1,970,166 -320,127 -1,401,152,337 -1,219,339,719 549,478,000 693,150,500 50 Net (Increase ) Decrease in Inventory 51 Net (Increase) Decrease in Allowances Held for Speculation 52 Net Increase (Decrease) in Payables and Accrued Expenses 53 Other (provide details in footnote): 54 Investment in coal mine reclamation trust 55 Investments and Other Assets 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 150,000,000 66 Net Increase in Short-Term Debt (c) 42,000,000 135,500,000 67 Other (provide details in footnote): 68 69 70 Cash Provided by Outside Sources (Total 61 thru 69) 699,478,000 870,650,500 71 72 Payments for Retirement of: 73 Long-term Debt (b) -370,430,000 74 Preferred Stock 75 Common Stock 76 Other (provide details in footnote): 77 78 Net Decrease in Short-Term Debt (c) -135,500,000 79 80 Dividends on Preferred Stock 81 Dividends on Common Stock -296,800,000 -281,300,000 267,178,000 218,920,500 5,010,749 -13,215,911 8,840,378 22,056,289 13,851,127 8,840,378 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) FOOTNOTE DATA Schedule Page: 120 Line No.: 19 Column: b Income Tax Receivable Risk Management Other Prepaids $ $ Schedule Page: 120 Line No.: 19 Column: c Income Tax Receivable Cumulative Adjustment - Stock Comp Adjustment Prepaids Other Risk Management $ $ Schedule Page: 120 Line No.: 20 $ $ Line No.: 20 31,915,722 13,368,362 6,906,515 5,448,603 3,502,880 2,217,600 2,000,000 1,972,473 (606,254) (847,359) (919,914) (4,921,798) (12,132,230) 47,904,600 Column: c Ocotillo Modernization Project Four Corners Take or Pay Red Rock Accruals Customer Deposits SCE Right of Way Software License Agreements Exchange Other Carbon Allowance Tolling Agreements Interest Accrued Employee Benefits Payroll Accrual Accrued Taxes SCE Transmission Termination Agreement FERC FORM NO. 1 (ED. 12-87) (11,173,856) (3,392,935) (2,309,704) 468,793 13,817,360 (2,590,342) Column: b Accrued Taxes Payroll Accrual Carbon Allowance SCE Right of Way Interest Accrued Tolling Agreements Sun Edison Bankruptcy Four Corners Take or Pay Exchange Other Employee Benefits Software License Agreements Customer Deposits Schedule Page: 120 11,173,856 5,189,673 (48,086) (4,347,913) 11,967,530 $ Page 450.1 47,444,127 16,942,062 11,838,795 9,447,138 8,618,272 3,935,736 848,495 (246,324) (1,281,266) (2,329,346) (3,015,614) (6,081,865) (9,067,257) (12,056,567) (18,000,000) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) FOOTNOTE DATA $ Schedule Page: 120 Line No.: 21 Column: b Decommissioning Trust Pension and other benefits Utility Plant (Removal Costs) Postretirement assets Carbon Allowance Tolling Agreements Other Long-Term Assets/Liabilities Net Margin and collateral accounts - liabilities Rouse Lease Retention Coal Reclaimation Customer advances for construction Schedule Page: 120 Line No.: 21 Line No.: 55 $ (89,133,034) (47,976,000) (33,531,776) (17,026,963) (7,217,847) (6,610,000) (6,203,637) (533,000) 3,129,921 4,070,092 9,185,122 25,324,080 $ (166,523,041) Column: c Pension and other benefits Decommissioning Trust Utility Plant (Removal Costs) Customer advances for construction FIN39 Adjustment APSCO Share of Four Corners NEPA Tolling Agreements Other Long-Term Assets/Liabilities Net Postretirement assets Margin and collateral accounts - assets Retention Carbon Allowance Rouse Lease Coal Reclamation Margin and collateral accounts - liabilities Schedule Page: 120 46,996,386 $ (44,502,000) (42,108,862) (41,569,427) (26,937,309) (18,060,000) (4,547,758) (4,392,400) (3,483,322) (2,042,590) 673,450 1,157,965 2,034,385 3,134,059 4,661,452 17,735,000 $ (158,247,356) Column: b Post-Employment Benefits Other $ (1,308,129) (662,037) (1,970,166) $ Schedule Page: 120 Line No.: 55 Column: c Post-Employment Benefits Other $ $ FERC FORM NO. 1 (ED. 12-87) Page 450.2 (510,800) 190,673 (320,127) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) (1) 05/09/2018 An Original Arizona Public Service Company (2) X A Resubmission Date of Report 05/09/2018 Year/Period of Report End of 2017/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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 (FERC) 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 (GAAP). The primary differences in the accompanying FERC financial statements as compared to GAAP include presenting certain decommissioning and reclamation activities, deferred tax assets and liabilities, regulatory assets and liabilities and risk management assets and liabilities on a gross versus net basis; presenting cost of removal liabilities in accumulated provision for depreciation; presenting tax liabilities related to uncertain tax positions as deferred income tax liabilities; presenting intangible assets in net utility plant; presenting certain regulatory disallowances in other deductions rather than operating revenue; deconsolidating certain variable interest entities and presenting debt issuance costs in deferred debits rather than as a reduction of long term debt. Additionally, the accompanying FERC financial statements do not separately present the current portion of such items as long term debt, asset retirement obligations and regulatory assets and liabilities as required by GAAP. APS’s notes to financial statements have been combined with Pinnacle West Capital Corporation’s financial statements and are prepared in accordance with GAAP; 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to 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. Allowance for Doubtful Accounts FERC FORM NO. 1 (ED. 12-88) Page 123.2 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 and amortization 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, 2017 were as follows: • • • • • • Fossil plant — 21 years; Nuclear plant — 26 years; Other generation — 25 years; Transmission — 38 years; Distribution — 33 years; and General plant — 6 years. FERC FORM NO. 1 (ED. 12-88) Page 123.3 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. For the years 2015 through 2017, the depreciation rates ranged from a low of 0.18% to a high of 16.44%. The weighted-average depreciation rate was 2.80% in 2017, 2.66% in 2016, and 2.74% in 2015. 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. See Note 12 for further information on Asset Retirement Obligations. 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 6.68% for 2017, 7.17% for 2016, and 8.02% for 2015. 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. Fair Value Measurements FERC FORM NO. 1 (ED. 12-88) Page 123.4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) We account for derivative instruments, investments held in our nuclear decommissioning trust, coal reclamation escrow accounts, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 7). Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. See Note 13 for additional information about fair value measurements. Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Comparative Statements of Income, but does not impact our financial condition, net income or cash flows. We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as FERC FORM NO. 1 (ED. 12-88) Page 123.5 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 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 reduced the fee to zero. 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 2019. See Note 11 for information on spent nuclear fuel disposal costs. Income Taxes FERC FORM NO. 1 (ED. 12-88) Page 123.6 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates. Pinnacle West Capital Corporation files our 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, 2017 2016 Cash paid (received) during the period for: Income taxes, net of refunds Interest, net of amounts capitalized Significant non-cash investing and financing activities: Accrued capital expenditures Dividends declared but not paid $ (14,098) 184,210 $ 26,864 181,809 $ 130,057 77,700 $ 114,874 72,900 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 $72 million in 2017, and $58 million in 2016. Estimated amortization expense on existing intangible assets over the next five years is $53 million in 2018, $38 million in 2019, $28 million in 2020, $22 million in 2021, and $17 million in 2022. At December 31, 2017, the weighted-average remaining amortization period for intangible assets was 6 years. Investments Our investments in the nuclear decommissioning trust fund, and coal reclamation escrow, 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. See Note 3 for new accounting guidance relating to financial instruments including investments in equity FERC FORM NO. 1 (ED. 12-88) Page 123.7 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) securities, effective for us in 2018. Preferred Stock At December 31, 2017, 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 23, 2018, 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 19, 2018. The accompanying statements contain all adjustments and disclosures necessary for fair presentation. Restatement Subsequent to the issuance of the 2017 financial statements, certain balance sheet accounts related to excess and deficient deferred taxes were reclassified to be presented on a gross basis for FERC reporting purposes. Other Regulatory Assets (Account 182.3), Other Regulatory Liabilities (Account 254) and Accumulated Deferred Income Taxes (Accounts 190 and 283) have been updated to present the “excess” deferred taxes (deferred federal income tax liabilities in excess of the new federal statutory 21% income tax rate which the company had previously collected from ratepayers, but not yet paid in taxes), and “deficient” deferred taxes (tax federal income tax benefits recorded in excess of the new federal statutory 21% income tax rate which ratepayers have previously received the benefit of, but for which the company has not realized the tax benefit) on a gross basis versus net basis. See Footnote 5 for more information. In addition, the 2016 write-off of a disallowed expiration payment to SCE was improperly recorded as an adjustment to Operating Revenues (Account 400) rather than to Other Deductions (Account 426.5). As a result of a FERC Letter Order received on April 5, 2018 in Docket No. AC18-13-000, the 2016 write-off of a disallowed expiration payment to SCE has been reclassified from Operating Revenues (Account 400) to Other Deductions (Account 426.5) and a corresponding adjustment was recorded for the impact on income taxes (Accounts 409.1 and 409.2). See SCE-Related Matters in Footnote 4 for more information. The 2017 and 2016 financial statements have been restated to reflect the following adjustments: FERC FORM NO. 1 (ED. 12-88) Page 123.8 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Comparative Balance Sheet Line # 72 82 60 64 FERC Account Number Assets and Other Debits Other Regulatory Assets (182.3) Accumulated Deferred Income Taxes (190) Liabilities and Other Credits Other Regulatory Liabilities (254) Accum. Deferred Income Taxes-Other (283) As originally reported in FERC Form 1 12/31/2017 $ 1,417,103,527 846,994,501 Reclassifications $ 2,339,654,162 422,098,310 281,557,684 69,796,108 As restated on FERC Form 1 Resubmission 12/31/2017 $ 1,698,661,211 916,790,609 281,557,684 69,796,108 2,621,211,846 491,894,418 Reclassifications As restated on FERC Form 1 Resubmission 12/31/2016 Statement of Income Line # FERC Account Number As originally reported in FERC Form 1 12/31/2016 2 Operating Revenues (400) 15 Income Taxes - Federal (409.1) 4,925,542 4,017,578 8,943,120 16 Income Taxes- Other (409.1) 5,218,902 609,622 5,828,524 49 Other Deductions (426.5) 93,051,238 12,000,000 105,051,238 53 Income Taxes-Federal (409.2) (4,739,586) (4,017,578) (8,757,164) 54 Income Taxes-Other (409.2) (719,179) (609,622) (1,328,801) 3. $ 3,516,336,004 $ 12,000,000 $ 3,528,336,004 New Accounting Standards 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, became 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 adopted this standard on January 1, 2018 using the modified retrospective transition approach. The adoption of this standard will not have significant impact on our financial statement results. Our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment the FERC FORM NO. 1 (ED. 12-88) Page 123.9 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) adoption of this guidance does not generally impact the timing of our revenue recognition relating to these customers. The adoption of the new standard will result in expanded revenue related disclosures. 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 became effective for us on January 1, 2018. Certain aspects of the standard require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We adopted this standard on a prospective basis on January 1, 2018. The adoption of this standard will not have a significant impact on our financial statement results, as we did not have significant equity investments impacted by this standard. 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. In January 2018, additional lease guidance was issued specifically relating to land easements and how entities may elect to account for these arrangements at transition. The new standard, and related amendments, 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 plan on adopting this standard, and related amendments, on January 1, 2019, and are evaluating the transition practical expedients we may elect. Our evaluation of this new accounting standard and the impacts it will have on our financial statements is on-going. We expect the adoption of the new guidance will impact our Comparative Balance Sheets as we will be required to reflect lease assets and lease liabilities relating to certain operating lease arrangements. We are currently evaluating the significance of the expected balance sheet impacts, and the impacts, if any, the lease guidance will have on our other financial statements. Our evaluation includes assessing leasing activities, implementing new processes and procedures, and preparing the expanded lease disclosures. ASU 2016-13, Financial Instruments: Measurement of Credit Losses FERC FORM NO. 1 (ED. 12-88) Page 123.10 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. The adoption of this guidance will not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard. ASU 2016-18, Statement of Cash Flows: Restricted Cash In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and will be adopted, during the first quarter of 2018 using a retrospective transition method. We do not expect the adoption of this guidance will impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents are generally insignificant. 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 acquisitions, disposals, goodwill, and consolidation. The new standard became effective for us on January 1, 2018 using a prospective approach. We adopted this new standard on January 1, 2018, using a prospective approach with FERC FORM NO. 1 (ED. 12-88) Page 123.11 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) no impacts on our financial statements on the date of adoption. ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard became effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. We adopted this standard on January 1, 2018 using a modified retrospective transition approach. The adoption of this guidance did not have a significant impact on our financial statement results. ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs) on their SEC financial statements. The presentation changes will require net benefit costs to be disaggregated on the SEC income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance became effective for us on January 1, 2018. We adopted this new accounting standard on January 1, 2018. Upon adoption, we will no longer capitalize a portion of the non-service cost components of net benefit costs. In 2018, because the non-service cost components are a reduction to total benefit costs, we estimate this change will result in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income. The adoption of this guidance changes our net benefit costs eligible for capitalization; however, it will not change the presentation of net benefit costs on our regulatory income statements. See Note 8 for additional information related to our pension plans and other postretirement benefits. ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard is effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal FERC FORM NO. 1 (ED. 12-88) Page 123.12 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We are evaluating the new guidance, but at this time we do not expect the adoption of this guidance will have a significant impact on our financial statement results as we are currently not applying hedge accounting. ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the 2017 Tax Cuts and Jobs Act legislation on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Cuts and Jobs Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Cuts and Jobs Act was recognized. We are currently evaluating this new guidance to determine whether we will elect this reclassification adjustment. The adoption of this guidance will not impact our income from continuing operations. See Note 5 for additional discussion of the Tax Cuts and Jobs Act. 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 excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested 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 had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%). On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement is an increase of 3.28% (the average annual bill impact for a typical APS residential customer is 4.54%). FERC FORM NO. 1 (ED. 12-88) Page 123.13 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Other key provisions of the agreement include the following: • • • • • • • • • • • an agreement by APS not to file another general retail rate case application before June 1, 2019; an authorized return on common equity of 10.0%; a capital structure comprised of 44.2% debt and 55.8% common equity; a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project; a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at Four Corners; a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate; an expansion of the PSA to include certain environmental chemical costs and third-party battery storage costs; a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year, and not more than $15 million per year; an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account; rate design changes, including: • a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays; • non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component; • a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC. Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. FERC FORM NO. 1 (ED. 12-88) Page 123.14 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the ACC's order approving the 2017 Settlement Agreement so that alleged issues of disqualification and bias on the part of the other Commissioners can be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition. On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated and APS has filed a motion to intervene. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact. On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant is requesting that the ACC hold a hearing on her amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS), and if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. APS cannot predict the outcome of this matter. Prior Rate Case Filing with the Arizona Corporation Commission On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement (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. Cost Recovery Mechanisms FERC FORM NO. 1 (ED. 12-88) Page 123.15 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a 5-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015. In 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 costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision. 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. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement. On August 15, 2017, the ACC approved the 2017 RES Implementation Plan. On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million. APS’s budget request supports existing approved projects and commitments and includes the FERC FORM NO. 1 (ED. 12-88) Page 123.16 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor. On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program requiring APS to spend $10-$15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. The ACC has not yet ruled on APS's 2018 RES Implementation Plan. In September 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 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. On January 30, 2018, ACC Commissioner Tobin proposed a new standard in this proceeding which would broaden the RES to include a series of energy reform policies tied to clean energy sources. The proposal would rename the RES to the Clean Resource Energy Standard and Tariff ("CREST"). 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") annually for review by and approval of the ACC. 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 ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standards; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism. On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed 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 Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to FERC FORM NO. 1 (ED. 12-88) Page 123.17 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan. On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million. 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 Commissioners 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. Power Supply Adjustor 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 FERC FORM NO. 1 (ED. 12-88) Page 123.18 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered or refunded 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 2017 and 2016 (dollars in thousands): Twelve Months Ended December 31, 2017 Beginning balance $ 2016 12,465 $ (9,688) Deferred fuel and purchased power costs — current period 48,405 60,303 Amounts refunded/(charged) to customers 14,767 (38,150) Ending balance $ 75,637 $ 12,465 The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017, the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh. On November 30, 2017, APS submitted its calculation for the 2018 PSA year beginning February 1, 2018. The current PSA rate is $.004555 per kWh consisting of a forward component of $.002009 per kWh and a historical component of $.002546 per kWh. Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, the 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 FERC FORM NO. 1 (ED. 12-88) Page 123.19 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 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. Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 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, 2017. On January 31, 2017, APS made a filing to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans. A transmission customer intervened and protested certain aspects of APS’s filing. FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed. APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 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 DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were first 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. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. 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. DG sales losses are determined from the metered output from the DG units. 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). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million (a FERC FORM NO. 1 (ED. 12-88) Page 123.20 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. On February 15, 2018, APS filed its LFCR Adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million (a $3 million per year decrease over 2017 levels). Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, a one or two month delay in implementation does not have an adverse effect on APS. Tax Expense Adjustor Mechanism and FERC Tax Filing. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018. On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps. The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit. APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million annually through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction will be effective March 1, 2018. The second step will address the amortization of excess deferred taxes previously collected from customers. APS is analyzing the final impact of the Tax Act provisions related to deferred taxes and intends to make a second TEAM filing later in 2018. The TEAM expressly applies to APS's retail rates with the exception noted above. The Company expects to make a filing with FERC in the first quarter of 2018 seeking authorization to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates. Net Metering FERC FORM NO. 1 (ED. 12-88) Page 123.21 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG 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 Administrative Law Judge 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 opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended opinion and order by a 4-1 vote. As a result of the ACC’s action, effective as of APS’s 2017 Rate Case Decision, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems was replaced by a more formula-driven approach that utilizes 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 RCP 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 RCP method will be updated annually (between general retail 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 general retail rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS 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 August 19, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility; • 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 general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on August 19, 2017. 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 asserted that the ACC improperly ignored the Administrative Procedure FERC FORM NO. 1 (ED. 12-88) Page 123.22 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 filed a Notice of Appeal in the Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review. 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. This adjustment is subsumed within the 2017 Settlement Agreement and its associated revenue requirement. Subpoena from Arizona Corporation Commissioner Robert Burns On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on 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 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 the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On FERC FORM NO. 1 (ED. 12-88) Page 123.23 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel. On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ complaint. The matter is subject to appeal. APS and Pinnacle West cannot predict the outcome of this matter. In addition to the Superior Court proceedings discussed above, on August 20, 2017, Commissioner Burns filed a special action petition in the Arizona Supreme Court seeking to vacate the 2017 Rate Case Decision so that alleged issues of disqualification and bias on the part of the other Commissioners could be fully investigated. APS opposed the petition, and on October 17, 2017, the Arizona Supreme Court declined to accept jurisdiction over Commissioner Burns’ special action petition. Renewable Energy Ballot Initiative On February 20, 2018, a coalition of renewable energy advocates filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to procure 50% of their energy supply from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The stated goal of the Clean Energy for a Healthy Arizona coalition is to complete the necessary steps to allow the initiative to be placed on the November 2018 Arizona elections ballot. The coalition must present over 225,000 verifiable signatures to the Secretary of State by July 5, 2018 to meet that goal. APS intends to oppose this effort. We believe the initiative is irresponsible and would result in negative impacts to Arizona utility customers, the Arizona economy and our company. We cannot predict the outcome of this matter. Clean Resource Energy Standard and Tariff On January 30, 2018, ACC Commissioner Tobin proposed the CREST, which consists of a series of energy reform policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the Integrated Resource Plan process. The ACC has not yet initiated any formal proceedings with respect to Commissioner Tobin’s proposal; however, on February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. APS cannot predict the outcome of this matter. Four Corners FERC FORM NO. 1 (ED. 12-88) Page 123.24 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) SCE-Related Matters. 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 retail 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 included 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 provided 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 $56 million as of December 31, 2017 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment. 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. 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 other deductions 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. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending and APS cannot predict the outcome of the proceeding. SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Rate Rider to permit recovery of costs associated with the installation of SCR FERC FORM NO. 1 (ED. 12-88) Page 123.25 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) equipment at Four Corners Units 4 and 5. APS intends to file the SCR Rate Rider in April 2018. Consistent with the 2017 Rate Case Decision, the rate rider filing will be narrow in scope and will address only costs associated with this specific environmental compliance equipment. Also, as provided for in the 2017 Rate Case Decision, APS will request that the rate rider become effective no later than January 1, 2019. Cholla On September 11, 2014, APS announced that it would close Unit 2 of Cholla 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. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017. Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($105 million as of December 31, 2017), 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. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026. Navajo Plant The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the Navajo Plant will cease operations in December 2019. 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 123.26 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($99 million as of December 31, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant 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 this interest, 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. Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in thousands): December 31, Pension (a) Deficient deferred income taxes- Tax Cuts and Jobs Act (b) Retired power plant costs Income taxes - AFUDC equity Deferred fuel and purchased power — mark-to-market (Note 15) Four Corners cost deferral Income taxes — investment tax credit basis adjustment Lost fixed cost recovery (c) Deferred compensation Deferred property taxes AG-1 deferral Demand side management (c) Tax expense of Medicare subsidy Mead-Phoenix transmission line CIAC Deferred fuel and purchased power (c) (d) Coal reclamation Other Total regulatory assets (e) $ $ 2017 576,188 281,558 216,244 146,680 86,945 56,382 27,284 59,844 36,413 83,495 11,126 — 8,651 10,708 75,637 13,464 8,042 1,698,661 $ $ 2016 711,059 — 127,504 158,423 42,963 63,583 56,476 61,307 35,595 73,200 5,868 3,744 12,102 11,040 12,465 5,600 6,661 1,387,590 (a) This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. See Note 8 for further discussion. (b) Treatment of the deficient deferred income taxes, and the month in which recovery of the FERC FORM NO. 1 (ED. 12-88) Page 123.27 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (c) (d) (e) deficient tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. 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.” The detail of regulatory liabilities is as follows (dollars in thousands): December 31, Excess deferred income taxes - Tax Cuts and Jobs Act (a) Asset retirement obligations Removal costs Other post retirement benefits Income taxes - deferred investment tax credit $ 2017 1,801,832 332,171 11,651 189,627 54,661 2016 $ -279,976 13,983 156,575 113,195 Income taxes - change in rates 75,459 75,592 Spent nuclear fuel 69,056 71,726 Renewable energy standard (b) 23,155 26,809 Demand side management (b) 7,987 20,472 Sundance maintenance 16,897 15,287 Deferred gains on utility property 15,411 10,958 Four Corners coal reclamation 20,779 18,248 2,526 11,290 Other Total regulatory liabilities $ 2,621,212 $ 814,111 (a) While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism and FERC filings in 2018. (b) See “Cost Recovery Mechanisms” discussion above. FERC FORM NO. 1 (ED. 12-88) Page 123.28 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 5. Income Taxes Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement 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 (“ITC”) basis adjustment and tax expense of Medicare subsidy. The regulatory liabilities primarily relate to deferred taxes resulting from ITCs and the change in income tax rates. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate to 21% effective January 1, 2018. In accordance with generally accepted accounting principles, the effects of this corporate tax rate reduction were recognized for the year ending December 31, 2017. As a result of this rate reduction, the Company has recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction is substantially offset by a net regulatory liability. As of December 31, 2017, to reflect the $1.14 billion reduction in its net deferred income tax liabilities caused by the rate reduction, APS has recorded a net regulatory liability of $1.52 billion and a new $377 million net deferred tax asset. The company intends to amortize the net regulatory liability in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining regulatory life of the related property, and in a manner to be approved by its federal and state regulatory agencies. See Note 4 for more details. Additionally, as a result of the corporate tax rate reduction, the Company recorded income tax expense of $9.3 million, for the year ended December 31, 2017, to recognize the effect of certain reductions in deferred tax assets, for which the Company did not believe recovery was probable through its revenue requirement. Several sections of the Tax Cuts and Jobs Act contain technical ambiguities. These ambiguities include certain transition rules regarding the applicability of bonus depreciation to property acquired, or under construction, prior to September 28, 2017 and the continued deductibility of certain executive compensation arrangements in place prior to November 3, 2017. Management has recognized tax positions which it believes are more likely than not to be sustained upon examination based upon its interpretation of this legislation. Clarifying guidance may be issued through additional legislation, Treasury regulations, or other technical guidance, within the next 12 months which may impact the income tax effects of the Tax Act as recorded by the Company. As of December 31, 2017, the Company does not have a reasonable estimate of what the income tax effects of such clarifying guidance may be, if any. FERC FORM NO. 1 (ED. 12-88) Page 123.29 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. The components of APS’s income tax expense are as follows (dollars in thousands): Year Ended December 31, 2017 2016 Current: Federal State Total current Deferred: Federal State Total deferred Total income tax expense $ 20,187 2,778 22,965 221,908 23,801 245,709 268,674 $ $ 186 4,500 4,686 211,225 29,469 240,694 245,380 $ 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): Federal income tax expense at 35% statutory rate Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit Medicare Subsidy Part-D Stock compensation Excess deferred income taxes – Tax Cuts and Jobs Act Allowance for equity funds used during construction (see Note 2) Investment tax credit amortization Other Income tax expense FERC FORM NO. 1 (ED. 12-88) Page 123.30 $ $ Year Ended December 31, 2017 2016 270,717 $ 247,794 17,276 853 (3,489) 9,431 18,750 844 (1,937) — (12,937) (6,715) (6,462) 268,674 (11,724) (5,887) (2,460) 245,380 $ 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The components of the net deferred income tax liability were as follows (dollars in thousands): December 31, 2017 2016 DEFERRED TAX ASSETS Regulatory liabilities: Excess Deferred Income Taxes – Tax Cuts & Jobs Act 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: Deficient Deferred Income Taxes – Tax Cuts and Jobs Act 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 4) Other Other Total deferred tax liabilities Deferred income taxes — net 6. Lines of Credit and Short-Term Borrowings FERC FORM NO. 1 (ED. 12-88) Page 123.31 $ $ 446,702 82,352 54,661 47,021 38,063 27,023 77,280 33,546 1,920 108,223 916,791 $ — 107,958 113,195 60,375 64,438 40,149 194,981 56,379 1,645 187,454 826,574 (2,192,974) (2,411) (65,733) (3,230,570) (21,129) (62,819) (69,796) (36,365) (40,778) (142,848) (53,611) (75,007) (5,346) (2,684,869) (1,768,078) — (61,088) (21,396) (274,184) (49,166) (125,114) (5,165) (3,850,631) (3,024,057) $ 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) APS maintains committed revolving credit facilities in order to enhance liquidity and provide credit support for its commercial paper program, 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, 2017 and 2016 (dollars in thousands): December 31, Commitments under Credit Facilities Outstanding Commercial Paper Borrowings Amount of Credit Facilities Available Weighted-Average Commitment Fees $ $ 2017 1,000,000 — 1,000,000 0.100% $ $ 2016 1,000,000 (135,500) 864,500 0.100% On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022. At December 31, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in May 2021 and the above-mentioned $500 million facility. 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, 2017, APS had no 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 was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. See Note 7 for additional long-term debt provisions. 7. Long-Term Debt and Liquidity Matters FERC FORM NO. 1 (ED. 12-88) Page 123.32 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2017 and 2016 (dollars in thousands): December 31, Maturity Dates (a) APS Pollution control bonds: Variable Fixed Total pollution control bonds Other Long-Term Debt Unamortized discount Unamortized premium Total Long-Term Debt (a) (b) Interest Rates 2029 2024-2029 (b) 1.75%-4.70% 2018-2046 1.43%-8.75% 2017 $ $ 35,975 147,150 183,125 4,455,988 (11,288) 8,049 4,635,874 2016 $ $ 35,975 147,150 183,125 3,904,686 (11,816) 4,506 4,080,501 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 1.77% at December 31, 2017 and 0.81% at December 31, 2016. The following table shows principal payments due on APS’s total long-term debt (dollars in thousands): APS Year 2018 2019 2020 2021 2022 Thereafter Total $ $ 82,000 600,000 250,000 — — 3,707,113 4,639,113 Debt Fair Value FERC FORM NO. 1 (ED. 12-88) Page 123.33 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2017 Carrying Amount Fair Value $ 4,635,875 $ 5,037,336 Total As of December 31, 2016 Carrying Amount Fair Value $ 4,080,501 $ 4,330,475 Credit Facilities and Debt Issuances On March 21, 2017, APS issued an additional $250 million par amount of its outstanding 4.35% senior unsecured notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures. On September 11, 2017, APS issued $300 million of 2.95% senior unsecured notes that mature on September 15, 2027. The net proceeds from the sale were used to refinance commercial paper and other indebtedness and to replenish cash used to fund capital expenditures. On November 30, 2017, PNW contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes. See “Lines of Credit and Short-Term Borrowings” in Note 6 and “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit. Debt Provisions APS’s debt covenants related to its respective bank financing arrangements include maximum debt to capitalization ratios. APS complies with this covenant. For APS, this covenant requires that the ratio of debt to total capitalization not exceed 65%. At December 31, 2017, 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 FERC FORM NO. 1 (ED. 12-88) Page 123.34 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. Its total shareholder equity was approximately $5.3 billion, and total capitalization was approximately $10.0 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $4.0 billion, assuming APS’s total capitalization remains the same. APS was in compliance with this common equity ratio requirement as of December 31, 2017. 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 was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. See Note 6 for additional short-term debt provisions. 8. Retirement Plans and Other Postretirement Benefits Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Employees do not contribute to the plans. Pinnacle West calculates the benefits based on age, years of service and pay. FERC FORM NO. 1 (ED. 12-88) Page 123.35 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. Pinnacle West retains the right to change or eliminate these benefits. On September 30, 2014, Pinnacle West announced plan design changes to the 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"). Pinnacle West 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 2014 remeasurement also resulted in a decrease in Pinnacle West’s other postretirement benefit obligation of $316 million, which was offset by the related regulatory asset and accumulated other comprehensive income. Because of plan changes in September 2014, Pinnacle West is currently in the process of seeking IRS approval to move approximately $186 million of 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 transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account. Pinnacle West negotiated a draft Closing Agreement granting tentative approval from the IRS prior to the transfer. Subsequent to the transfer, Pinnacle West submitted proof of the transfer to the IRS and expects to execute a final Closing Agreement early in 2018. Per the terms of an order from FERC, Pinnacle West must also make an informational filing with FERC. Pinnacle West made this FERC filing during February 2018. It is Pinnacle West’s understanding that completion of these regulatory requirements will then permit access to the approximately $186 million for the sole purpose of paying active union employee medical benefits. Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of its plan assets is their fair value at the measurement date. See Note 13 for further discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods. A significant portion of the changes in the actuarial gains and losses of Pinnacle West 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. FERC FORM NO. 1 (ED. 12-88) Page 123.36 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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): Pension 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 2017 $ 54,858 129,756 2016 $ 53,792 131,647 (174,271) (173,906) 81 47,900 58,324 27,295 527 40,717 52,777 26,172 $ $ $ $ Other Benefits 2017 2016 $ 17,119 $ 14,993 29,959 29,721 (53,401) (36,495) (37,842) 5,118 $ (39,047) $ (18,274) (37,883) 4,589 $ (25,075) $ (12,435) See Note 3 for additional information regarding accounting changes relating to ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. FERC FORM NO. 1 (ED. 12-88) Page 123.37 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows the plans’ changes in the benefit obligations and funded status for the years 2017 and 2016 (dollars in thousands): Other Benefits 2017 2016 Pension 2017 2016 Change in Benefit Obligation Benefit obligation at January 1 Service cost Interest cost Benefit payments Actuarial loss Benefit obligation at December 31 $ 3,204,462 54,858 129,756 (166,342) 171,452 3,394,186 $ 3,033,803 53,792 131,647 (142,247) 127,467 3,204,462 $ 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 2,675,357 428,374 100,000 (146,704) 3,057,027 $ (337,159) 2,542,774 166,408 100,000 (133,825) 2,675,357 $ (529,105) 882,651 139,367 353 — 1,022,371 $ 268,978 716,445 17,119 29,959 (30,144) 20,014 753,393 $ $ 647,020 14,993 29,721 (26,231) 50,942 716,445 833,017 63,463 819 (14,648) 882,651 166,206 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, 2017 and 2016 (dollars in thousands): Projected benefit obligation Accumulated benefit obligation Fair value of plan assets $ 2017 3,394,186 3,227,233 3,057,027 $ 2016 3,204,462 3,049,406 2,675,357 The following table shows the amounts recognized on the Comparative Balance Sheets as of December 31, 2017 and 2016 (dollars in thousands): Pension 2017 Noncurrent asset Current liability Noncurrent liability Net amount recognized FERC FORM NO. 1 (ED. 12-88) $ $ 2016 — (9,859) (327,300) (337,159) $ $ — (19,795) (509,310) (529,105) Page 123.38 $ $ Other Benefits 2017 2016 268,978 $ 166,206 — — — — 268,978 $ 166,206 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The following table shows the details related to accumulated other comprehensive loss as of December 31, 2017 and 2016 (dollars in thousands): Pension Net actuarial loss Prior service cost (credit) APS’s portion recorded as a regulatory (asset) liability Income tax expense (benefit) Accumulated other comprehensive loss 2017 $ 643,199 — (576,188) (24,915) $ 42,096 2016 $ 773,750 81 (711,059) (24,202) $ 38,570 Other Benefits 2017 2016 $ 75,439 $ 146,509 (265,575) (303,417) 189,627 156,575 853 833 $ 344 $ 500 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 2018 (dollars in thousands): Net actuarial loss Prior service credit Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2018 Other Benefits Pension $ 28,334 — $ — (37,842) $ $ (37,842) 28,334 The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs: Benefit Obligations As of December 31, 2016 2017 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) Benefit Costs For the Years Ended December 31, 2017 2016 3.65% 4.08% 4.08% 4.37% 3.71% 4.17% 4.17% 4.52% 4.00% 4.00% 4.00% 4.00% N/A N/A 6.55% 6.90% N/A N/A 6.05% 4.45% 7.00% 7.00% 7.00% 7.00% 4.75% 5.00% 5.00% 5.00% 4.75% 5.00% 5.00% 5.00% 8 4 4 4 In selecting the pretax expected long-term rate of return on plan assets, Pinnacle West considers past performance and economic forecasts for the types of investments held by the plan. For 2018, Pinnacle West is FERC FORM NO. 1 (ED. 12-88) Page 123.39 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) assuming a 6.05% long-term rate of return for pension assets and 5.55% (before tax) for other benefit assets, which Pinnacle West believes is reasonable given its asset allocation in relation to historical and expected performance. In selecting its healthcare trend rates, Pinnacle West considers 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 on December 31, 2017 amounts (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 1% Increase 1% Decrease $ $ 8,424 9,145 128,203 (5,616) (7,037) (98,143) 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. FERC FORM NO. 1 (ED. 12-88) Page 123.40 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Based on the IPS, and given the pension plan's funded status at year-end 2017, the target and actual allocation for the pension plan at December 31, 2017 are as follows: Pension Target Allocation 62% 38% 100% Long-term fixed income assets Return-generating assets Total Actual Allocation 58% 42% 100% The permissible range is within +/- 3% of the target allocation shown in the above table, and also considers the Plan's funded status. The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets: Target Allocation 18% 6% 14% 38% Asset Class Equities in US and other developed markets Equities in emerging markets Alternative investments Total 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, 2017, 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. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2017: Other Benefits Actual Allocation 67% 33% 100% Long-term fixed income assets Return-generating assets Total 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 FERC FORM NO. 1 (ED. 12-88) Page 123.41 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, which includes exchange traded funds (ETFs), are classified as Level 1 and 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, and fixed income securities is derived from the 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, 2017, 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, 2017, approximately $58 million of these commitments have been funded. The plans’ trustee provides valuation of Pinnacle West plan assets by using pricing services that utilize methodologies described to determine fair market value. Pinnacle West has internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. FERC FORM NO. 1 (ED. 12-88) Page 123.42 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2017, by asset category, are as follows (dollars in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Pension Plan: Cash and cash equivalents Fixed income securities: Corporate U.S. Treasury Other (b) Common stock equities (c) Mutual funds (d) Common and collective trusts: Equities Real estate Fixed Income Partnerships Short-term investments & other (e) Total Other Benefits: Cash and cash equivalents Fixed income securities: Corporate U.S. Treasury Other (b) Common stock equities (c) Mutual funds (d) Common and collective trusts: Equities Real estate Short-term investments & other (e) Total (a) (b) (c) (d) (e) $ 3,830 Significant Other Observable Inputs (Level 2) $ Balance at December 31, 2017 Other (a) — $ — $ 3,830 — 221,291 — 228,088 233,732 1,365,194 — 100,599 — — — — — — — 1,365,194 221,291 100,599 228,088 233,732 $ — — — — — 686,941 $ — — — — 1,208 1,467,001 $ 408,763 171,569 90,869 133,379 98,505 903,085 $ 408,763 171,569 90,869 133,379 99,713 3,057,027 $ 143 $ — $ — $ 143 $ — 336,963 — 196,153 39,269 306,008 — 32,508 — — — — — — — 306,008 336,963 32,508 196,153 39,269 — — 11,268 583,796 — — 149 338,665 75,310 15,422 9,178 99,910 75,310 15,422 20,595 1,022,371 $ $ $ 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 U.S. common stock equities. These funds invest in U.S. and international common stock equities. This category includes plan receivables and payables. FERC FORM NO. 1 (ED. 12-88) Page 123.43 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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) Pension Plan: Cash and cash equivalents Fixed income securities: Corporate U.S. Treasury Other (b) Common stock equities (c) Mutual funds (d) Common and collective trusts: Equities Real estate Partnerships Short-term investments & other (e) Total Other Benefits: Cash and cash equivalents Fixed income securities: Corporate U.S. Treasury Other (b) Common stock equities (c) Mutual funds (d) Common and collective trusts: Equities Real estate Partnerships Short-term investments & other (e) Total (a) (b) (c) (d) (f) $ 13,995 Significant Other Observable Inputs (Level 2) $ Balance at December 31, 2017 Other (a) — $ — $ 13,995 — 112,583 — 235,109 251,506 1,210,453 — 102,170 — — — — — — — 1,210,453 112,583 102,170 235,109 251,506 $ — — — — 613,193 $ — — — — 1,312,623 $ 266,840 161,449 208,915 112,337 749,541 $ 266,840 161,449 208,915 112,337 2,675,357 $ 304 $ — $ — $ 304 $ — 145,255 — 243,741 67,418 268,193 — 34,506 — — — — — — — 268,193 145,255 34,506 243,741 67,418 — — — — 456,718 — — — — 302,699 95,814 14,509 3,060 9,851 123,234 95,814 14,509 3,060 9,851 882,651 $ $ $ 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 U.S. common stock equities. These funds invest in U.S. and international common stock equities. This category includes plan receivables and payables. FERC FORM NO. 1 (ED. 12-88) Page 123.44 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 2017 and $100 million in 2016. 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 $250 million during the 2018-2020 period. With regard to contributions to the other postretirement benefit plans, Pinnacle West made a contribution of approximately $1 million in each of 2017 and 2016. Pinnacle West does not expect to make any contributions over the next three years to the other postretirement benefit plans. APS funds its share of the contributions. APS’s share of the pension plan contribution was approximately $100 million in 2017 and $100 million in 2016. APS’s share of the contributions to the other postretirement benefit plan was approximately $1 million in 2017 and 2016. 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 2018 $ 175,383 Other Benefits $ 31,891 2019 181,902 34,000 2020 191,586 35,658 2021 196,583 37,090 2022 201,463 37,860 1,068,568 191,207 Years 2023-2027 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 2017, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, Pinnacle West’s matching contributions and earnings or losses on their investments. Under this plan, Pinnacle West 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 2017 and $10 million for 2016. 9. Leases FERC FORM NO. 1 (ED. 12-88) Page 123.45 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 $40 million in 2017 and $38 million in 2016. Estimated future minimum lease payments for APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands): Year APS 2018 $ 36,110 2019 33,802 2020 32,392 2021 29,858 2022 27,510 Thereafter 236,605 Total future lease commitments $ 396,277 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, 2017 (dollars in thousands): Construction FERC FORM NO. 1 (ED. 12-88) Page 123.46 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Percent Owned Plant in Service Accumulated Depreciation Work in Progress Generating facilities: Palo Verde Units 1 and 3 29.1% $ 1,872,104 $ 1,092,049 Palo Verde Unit 2 (a) 16.8% 619,263 364,516 14,672 Palo Verde Common 28.0% (b) 726,223 262,065 46,577 (a) 351,050 241,405 — Palo Verde Sale Leaseback $ 24,257 Four Corners Generating Station 63.0% 1,196,683 568,304 240,514 Cholla common facilities (c) 50.5% 180,907 69,633 1,091 Transmission facilities: ANPP 500kV System 34.0% (b) 130,767 46,400 684 Navajo Southern System 27.5% (b) 85,299 28,915 180 Palo Verde — Yuma 500kV System 18.1% (b) 14,765 6,614 486 Four Corners Switchyards 63.2% (b) 66,386 12,605 327 Phoenix — Mead System 17.1% (b) 39,383 17,600 41 Palo Verde — Rudd 500kV System 50.0% 97,600 23,884 245 Morgan — Pinnacle Peak System 64.6% 117,721 14,569 1 Round Valley System 50.0% 515 141 — Palo Verde — Morgan System 90.9% 137,887 3,948 94,350 Hassayampa - North Gila System 80.0% 142,541 6,953 — Cholla 500kV Switchyard 85.7% 5,243 1,312 190 Saguaro 500kV Switchyard 60.0% 20,473 12,574 — Kyrene – Knox System 50.0% 578 297 — (a) (b) (c) (b) (b) 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. APS also has a 14% ownership in the Navajo Plant. In the second quarter of 2017, APS’s remaining net book value of its interest was reclassified from property, plant and equipment to a regulatory asset. See “Navajo Plant” in Note 4 for more details. FERC FORM NO. 1 (ED. 12-88) Page 123.47 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 11. Commitments and Contingencies Palo Verde 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 United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019. APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 retail rate case settlement, this regulatory liability is being refunded to customers (see Note 6). APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE in the fourth quarter of 2017 in the amount of $9 million (APS's share is $2.6 million). In February 2018, the DOE approved this claim. 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 $450 million, which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately $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 per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $19 million per incident. Based on APS’s ownership interest in the three Palo Verde FERC FORM NO. 1 (ED. 12-88) Page 123.48 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 $24 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 $64.8 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 2018 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $715 million in 2018; $578 million in 2019; $548 million in 2020; $548 million in 2021; $554 million in 2022; and $6.5 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): Coal take-or-pay commitments (a) (a) 2018 $ 159,997 Years Ended December 31, 2019 2020 2021 2022 $ 185,365 $ 186,632 $ 190,607 $ 194,678 Thereafter $ 1,750,739 Total take-or-pay commitments are approximately $2.7 billion. The total net present value of these commitments is approximately $1.9 billion. APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last twoyears (dollars in thousands): Renewable Energy Credits FERC FORM NO. 1 (ED. 12-88) Page 123.49 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Years Ended December 31, 2017 2016 $ 165,220 $ 160,066 Total purchases 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 2018; $40 million in 2019; $40 million in 2020; $40 million in 2021; $40 million in 2022; and $370 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Coal Mine Reclamation Obligations APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $216 million at December 31, 2017 and $207 million at December 31, 2016. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $31 million in 2018; $32 million in 2019; $21 million in 2020; $20 million in 2021; $22 million in 2022; and $191 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, 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 RI/FS. Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS, APS anticipates finalizing the RI/FS in the summer or fall of 2018. 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, FERC FORM NO. 1 (ED. 12-88) Page 123.50 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. 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. 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 pollution control 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 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 Cholla BART approval. Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 is 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 had 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 purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.51 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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; however, given the future plans for the Navajo Plant, we do not expect to incur these costs. See "Navajo Plant" in Note 4 for information regarding future plans for the Navajo Plant. Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program. In September 2014, APS met with EPA to propose a compromise BART strategy. 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. 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 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. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017. Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. 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 FERC FORM NO. 1 (ED. 12-88) Page 123.52 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. ADEQ has initiated a process to evaluate how to develop a state CCR permitting program that would cover EGUs, including Cholla. While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR. Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. At this time, it is not clear whether EPA will initiate further notice-and-comment rulemaking to revise the federal CCR rules, nor is it clear what aspects of the federal CCR rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of these federal CCR regulations, on September 27, 2017 the United States Court of Appeals for the D.C. Circuit, the court overseeing these judicial challenges, ordered EPA to file by November 15, 2017 a list of federal regulatory provisions addressing CCR that are or likely will be revised through EPA’s reconsideration proceedings. While this filing identified certain provisions of the federal CCR regulations that EPA intends to revise, including allowances for risk-based groundwater protection standards for regulated CCR constituents for which no federal maximum contaminant level has been set, it is not clear at this time which specific provisions of the federal CCR rules will be modified, how they will be modified, or when such modification will occur. 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 2 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 APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings. 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 $22 FERC FORM NO. 1 (ED. 12-88) Page 123.53 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018. If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by January 2019. Depending upon the results of such groundwater monitoring and data evaluations 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. Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for EGUs. Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. 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. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit Court to hold the ongoing litigation over the Clean Power Plan in abeyance pending EPA action in accordance with the Executive Order. At this time, the D.C. Circuit Court proceedings evaluating the legality of the Clean Power Plan remain on hold. Based upon EPA's reevaluation of the August 2015 carbon pollution standards and the legal basis for these regulations, on October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. That proposal relies on EPA's current view as to the Agency's legal authority under Clean Air Act Section 111(d), which (in contrast to the Clean Power Plan) would limit the scope of any future Section 111(d) regulations to measures undertaken exclusively at a power plant's source of GHG emissions. On December 18, 2017, EPA issued an Advanced Notice of Proposed Rulemaking through which EPA is soliciting comments as to potential replacements for the Clean Power Plan that would be consistent with EPA's current legal interpretation of the Clean Air Act. We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to develop regulations replacing the Clean Power Plan. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal. FERC FORM NO. 1 (ED. 12-88) Page 123.54 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Other environmental rules that could involve material compliance costs include those related to effluent 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 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. 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. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings. Four Corners Coal Supply Agreement Arbitration On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the 2016 Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant. NTEC was originally seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC also alleged a shortfall in the Buyer’s purchases for the initial contract year of approximately $30 million. APS’s share of this amount is approximately $17 million. On September 20, 2017, NTEC amended its Demand for Arbitration removing its request for a declaratory judgment and at this time is only seeking relief for the alleged shortfall in the Buyer's purchases for the initial contract year. We cannot predict the timing or outcome of this arbitration; however we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. FERC FORM NO. 1 (ED. 12-88) Page 123.55 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2017, standby letters of credit totaled $5 million and will expire in 2018. As of December 31, 2017, surety bonds expiring through 2019 totaled $62 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. 12. Asset Retirement Obligations In 2017, APS received a new decommissioning study for the Navajo Generating Station. This resulted in an increase to the ARO in the amount of $22 million, an increase in the regulatory asset of $2 million, and a reduction of the regulatory liability of $20 million. 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. The following table shows the change in our asset retirement obligations for 2017 and 2016 (dollars in thousands): 2017 FERC FORM NO. 1 (ED. 12-88) Page 123.56 2016 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Asset retirement obligations at the beginning of year $ 615,936 $ 443,576 Changes attributable to: Accretion expense Settlements Estimated cash flow revisions Newly incurred or acquired obligations Asset retirement obligations at the end of year $ 32,815 26,518 — (15,577) 21,968 151,046 — 10,373 670,719 $ 615,936 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. Level 2 — Other significant observable inputs, including 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). Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote FERC FORM NO. 1 (ED. 12-88) Page 123.57 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 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, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels. Recurring Fair Value Measurements We apply recurring fair value measurements to certain cash equivalents, derivative instruments, and investments held in our coal reclamation escrow accounts and nuclear decommissioning trust. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 8 for fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets. Risk Management Activities — Derivative Instruments Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk. Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair FERC FORM NO. 1 (ED. 12-88) Page 123.58 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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. 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 Nuclear Decommissioning Trust and Coal Reclamation Escrow The nuclear decommissioning trust invests in fixed income securities, equity securities, and may hold cash and cash equivalents. The coal reclamation escrow account invests in fixed income instruments and may also hold cash and cash equivalents. See Note 17 for additional discussion about our investment accounts. The nuclear decommissioning trust's equity security investments 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. Fixed income securities issued by the U.S. Treasury 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 fixed income 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. Cash equivalents reported within Level 1 represent investments held in short-term investment exchange-traded mutual funds. These short-term investment accounts invest in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short term instruments. FERC FORM NO. 1 (ED. 12-88) Page 123.59 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) We price investment securities using information provided by our trustees for our nuclear decommissioning trust assets, and provided by our escrow agent for coal reclamation escrow assets. Our trustee and escrow agent use pricing services that utilize the valuation methodologies described above 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 and escrow agent's internal operating controls and valuation processes. Fair Value Tables The following table presents the fair value at December 31, 2017 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Quoted Prices in Active Markets for FERC FORM NO. 1 (ED. 12-88) Significant Other Page 123.60 Significant 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Identical Assets (Level 1) Observable Inputs (Level 2) Unobservable Inputs (a) (Level 3) Balance at December 31, 2017 Other Assets Cash equivalents $ 10,630 $ — $ — $ — $ 10,630 Risk management activities — derivative instruments: — 5,683 1,036 (1) 6,718 430 29,439 — 489 30,358 7,224 — — 109 (c) 7,333 — — — 417,390 (d) 417,390 127,662 — — — 127,662 Corporate debt — 114,007 — — 114,007 Mortgage-backed securities — 111,874 — — 111,874 Municipal bonds — 79,049 — — 79,049 Other — 13,685 — — 13,685 Commodity contracts Coal reclamation escrow account (b): Nuclear decommissioning trust: Cash and cash equivalents U.S. commingled equity funds Fixed income securities: U.S. Treasury Subtotal nuclear decommissioning trust Total Assets 134,886 — 417,499 $ 145,946 $ 318,615 353,737 $ 1,036 $ 417,987 $ 871,000 918,706 $ — $ (78,646) $ (19,292) $ $ (97,938) Liabilities Risk management activities — derivative instruments: Commodity contracts (a) (b) (c) (d) — Primarily consists of long-dated electricity contracts. 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 Comparative Balance Sheets. Primarily consists of fixed income municipal bonds. Represents nuclear decommissioning trust net pending securities sales and purchases. Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. 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) FERC FORM NO. 1 (ED. 12-88) Significant Other Observable Inputs (Level 2) Page 123.61 Significant Unobservable Inputs (a) (Level 3) Other Balance at December 31, 2016 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Assets Coal reclamation trust (b): $ 13,545 $ — $ — $ — $ 13,545 Risk management activities — derivative instruments: Commodity contracts — 43,722 11,076 1 54,799 — — — 353,261 (c) 353,261 — — — 795 (d) 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 $ 354,057 $ 847,930 $ $ (104,124) Subtotal nuclear decommissioning trust Total $ 108,986 $ 373,811 $ 11,076 $ — $ (45,641) $ (58,482) Liabilities Risk management activities — derivative instruments: Commodity contracts (a) (b) (c) (d) (1) Primarily consists of long-dated electricity contracts. 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 Comparative Balance Sheets. Primarily consists of cash equivalents. Presented as Coal reclamation escrow in 2017. Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. Represents nuclear decommissioning trust net pending securities sales and purchases. 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. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4). Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we FERC FORM NO. 1 (ED. 12-88) Page 123.62 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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. 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, 2017 and December 31, 2016: December 31, 2017 Fair Value (thousands) Commodity Contracts Electricity: Forward Contracts (a) Assets $ 21 Liabilities $ Valuation Technique Significant Unobservable Input Discounted Cash Flows Electricity forward price (per MWh) $18.51 - $38.75 $ 27.89 Natural gas forward price (per MMBtu) $2.33 - $3.11 $ 2.71 15,485 Range WeightedAverage Natural Gas: Forward Contracts (a) Discounted Cash Flows 1,015 Total $ (a) 1,036 3,807 $ 19,292 Includes swaps and physical and financial contracts. December 31, 2016 Fair Value (thousands) Commodity Contracts Electricity: Forward Contracts (a) Assets $ 10,648 Liabilities $ 32,042 Valuation Technique Significant Unobservable Input Discounted Cash Flows Electricity forward price (per MWh) $16.43 - $41.07 $ 29.86 Discounted Cash Flows Natural gas forward price (per MMBtu) $2.32 - $3.60 $ 2.81 Range WeightedAverage Natural Gas: Forward Contracts (a) 26,440 428 Total $ 11,076 FERC FORM NO. 1 (ED. 12-88) $ 58,482 Page 123.63 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) Includes swaps and physical and financial contracts. 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, 2017 and 2016 (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 Year Ended December 31, 2017 2016 $ (47,406) $ (32,979) $ $ — 3 (13,643) 5,834 (10,026) 46,982 (18,256) — $ $ — 88 (37,543) 15,146 1,900 5,982 (47,406) — 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, 2017, 2.2 million common shares were available for issuance FERC FORM NO. 1 (ED. 12-88) Page 123.64 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) under the 2012 Plan. During 2017 and 2016, 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. 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 $6 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 2016 resulted in a pre-tax $12 million adjustment to decrease operations and maintenance expense that was recognized during the fourth quarter of 2016. The following amounts related to years ended 2017 and 2016 expense and activity include the effects of adopting this new accounting standard. 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 $21 million in 2017 and $19 million in 2016. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $15 million in 2017and $10 million in 2016. As of December 31, 2017, there were approximately $12 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 2017and $22 million in 2016. The following table is a summary of awards granted and the weighted-average grant date fair value for the two years ended 2017 and 2016. Restricted Stock Units, Stock Grants, and Stock Units (a) Units granted Weighted-average grant date fair value FERC FORM NO. 1 (ED. 12-88) 2017 161,963 $ 72.60 2016 141,811 $ 67.34 Page 123.65 Performance Shares (b) $ 2017 147,706 78.99 2016 166,666 $ 66.60 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) (a) Units granted includes awards that will be cash settled of 67,599 in 2017 and 43,952 in 2016., (b) Reflects the target payout level. Nonvested at January 1, 2017 Granted Change in performance factor Vested Forfeited (c) Nonvested at December 31, 2017 Vested Awards Outstanding at December 31, 2017 Restricted Stock Units, Stock Grants, and Stock Units WeightedAverage Grant Date Shares Fair Value 335,259 $ 62.04 161,963 72.60 — — (202,327) 59.19 69.58 (3,607) 291,288 (a) 69.78 89,928 Performance Shares WeightedAverage Grant Date Shares (b) Fair Value $ 65.32 312,724 147,706 78.99 18,266 64.97 (164,396) 63.87 (4,798) 69.77 309,502 72.46 164,396 (a) Includes 133,373 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 $4 million, $3 million and $10 million in 2017 and 2016. This includes cash used to settle restricted stock units of $4 million, $3 million in 2017 and, 2016. Restricted stock units that are cash settled are classified as liability awards. In 2017 and 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, 100% cash, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award 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. FERC FORM NO. 1 (ED. 12-88) Page 123.66 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 did increase the number of awards that vested by 33,745 restricted stock units, payable in stock because certain performance requirements were met. In February 2017, 84,362 restricted stock units were released. 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 on non-financial 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 recipients would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares. Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the 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 FERC FORM NO. 1 (ED. 12-88) Page 123.67 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates. Risks associated with market volatility are managed 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. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may 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 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. 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, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Unit of Measure FERC FORM NO. 1 (ED. 12-88) Quantity December 31, 2017 December 31, 2016 Page 123.68 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Power Gas GWh 583 240 Billion cubic feet 1,314 194 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, 2017 and 2016 (dollars in thousands): Year Ended December 31, 2017 2016 Financial Statement Location Commodity Contracts Gain (Loss) Recognized in OCI on Derivative OCI — derivative instruments Instruments (Effective Portion) Loss Reclassified from Accumulated OCI Fuel and purchased power (b) into Income (Effective Portion Realized) (a) (a) (b) $ (59) $ 47 (3,926) (3,519) During the years ended December 31, 2017 and 2016 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 $2 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings. The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2017 and 2016 (dollars in thousands): Commodity Contracts Financial Statement Location Net Gain (Loss) Recognized in Income Operating revenues Net Gain (Loss) Recognized in Income Total Fuel and purchased power (a) $ Derivative Instruments in the Comparative Balance Sheets Page 123.69 (1,192) $ (87,991) $ (a) Amounts are before the effect of PSA deferrals. FERC FORM NO. 1 (ED. 12-88) Year Ended December 31, 2017 2016 (89,183) 771 25,711 $ 26,482 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 and 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. As of December 31, 2017, we no longer have derivative instruments that are designated as cash flow hedging instruments. As of December 31, 2016, the Comparative Balance Sheets included $2 million of gross liabilities related to derivative instruments designated as cash flow hedging instruments. The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the potential impacts of offsetting relating to transactions executed under master netting arrangements. While certain amounts may be eligible for offsetting, under master netting arrangements, for FERC reporting purposes we do not offset on the balance sheet. These amounts related to commodity contracts and are located in the assets and liabilities from derivative instrument lines of our Comparative Balance Sheets. Gross Recognized As of December 31, 2017: (dollars in thousands) Current Assets Investments and Other Assets Total Assets Current Liabilities Deferred Credits and Other Total Liabilities Total (a) (b) Derivatives (a) $ 5,427 $ Eligible for Offsetting Cash Collateral/ Other (b) Derivatives $ (3,796) $ -- Net Derivatives After Impacts of Offsetting $ 1,631 1,292 6,719 (1,241) (5,037) --- 51 1,682 (59,527) (38,411) (97,938) (91,219) 3,796 1,241 5,037 -- ----- (55,731) (37,170) (92,901) (91,219) $ $ $ All of our gross recognized derivative instruments were subject to master netting arrangements. No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. We had total cash collateral received from counterparties of $3,521, and cash margin provided to counterparties of $300; these amounts are reflected in miscellaneous current and accrued assets FERC FORM NO. 1 (ED. 12-88) Page 123.70 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) and liabilities. Certain cash collateral and margin is not eligible for offsetting as it does not relate to recognized derivatives. Gross Recognized 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) Derivatives (a) $ 48,094 $ Eligible for Offsetting Cash Collateral/ Derivatives Other (b) $ (28,400) $ -- Net Derivatives After Impacts of Offsetting $ 19,694 6,704 54,798 (6,703) (35,103) --- 1 19,695 (50,182) (53,941) (104,123) (49,325) 28,400 6,703 35,103 -- ----- (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. 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, 2017, APS has 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 counterparties 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. FERC FORM NO. 1 (ED. 12-88) Page 123.71 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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, 2017 (dollars in thousands): Aggregate fair value of derivative instruments in a net liability position December 31, 2017 $ 97,938 Cash collateral posted — Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) (a) 91,071 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 $110 million if our debt credit ratings were to fall below investment grade. 16. Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. 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 2018 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 three leases as operating leases for income statement and cash flow statement purposes, and for balance sheet purposes two of the leases are accounted for as capital leases. FERC FORM NO. 1 (ED. 12-88) Page 123.72 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) 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 $293 million beginning in 2018, and up to $456 million over the lease extension term. 17. Investments We have investments in debt and equity securities held in Nuclear Decommissioning Trusts and Coal Reclamation Escrow Accounts. These investments are classified as available for sale securities, and as a result we record the investments 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 investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning and coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The costs of securities sold are determined on the basis of specific identification. 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. 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, 2017 and December 31, 2016 (dollars in thousands): December 31, 2017 Equity securities Fair Value Total Unrealized Gains Total Unrealized Losses $ $ $ Fixed income securities Cash and cash equivalents Net receivables (a) Total $ (a) December 31, 2016 417,390 248,623 — Fair Value Total Unrealized Gains Total Unrealized Losses $ $ $ 353,261 188,091 — 446,277 11,537 (2,996) 425,530 9,820 (4,962) 7,224 — — — — — 109 — — 795 — — 871,000 $ 260,160 $ (2,996) $ 779,586 $ 197,911 $ (4,962) Net receivables/(payables) relate to pending purchases and sales of securities. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the FERC FORM NO. 1 (ED. 12-88) Page 123.73 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) nuclear decommissioning trust funds (dollars in thousands): Nuclear Decommissioning Year Ended December 31, 2017 $ 21,813 (13,146) 542,246 Realized gains Realized losses Proceeds from the sale of securities (a) (a) $ 2016 11,213 (10,106) 633,410 Proceeds are reinvested in the trust/account. Coal Reclamation Escrow Accounts APS has investments restricted for coal mine reclamation funding related to Four Corners. As of December 31, 2017, APS’s coal reclamation escrow accounts are invested in fixed income securities with a fair value of $30 million. The realized and unrealized gains and losses relating to these fixed income securities was immaterial for the twelve months ended December 31, 2017 and December 31, 2016. The proceeds from the sale of securities for the twelve months ended December 31, 2017 was $4 million. There were no proceeds from the sale of securities for the twelve months ended December 31, 2016. The proceeds are reinvested in the escrow accounts. Fixed Income Securities Contractual Maturities The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2017 is as follows (dollars in thousands): Nuclear Decommissioning Escrow Total Accounts Trusts Less than one year $ 24,668 $ 429 $ 25,097 1 year – 5 years 100,289 2,326 102,615 5 years – 10 years 129,239 8,036 137,275 Greater than 10 years 192,081 19,078 211,159 FERC FORM NO. 1 (ED. 12-88) Page 123.74 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) Total 18. $ 446,277 $ 29,869 $ 476,146 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, 2017 and 2016 (dollars in thousands): Pension and Other Postretirement Benefits Balance December 31, 2015 $ OCI (loss) before reclassifications 3,092 Balance December 31, 2016 OCI (loss) before reclassifications Amounts reclassified from accumulated other comprehensive loss (a) (b) (19,942) $ (3,821) Amounts reclassified from accumulated other comprehensive loss Balance December 31, 2017 Derivative Instruments (7,155) $ (538) (a) 2,941 (27,097) (4,359) (b) 6,033 (20,671) (4,752) (25,423) (6,884) (35) (6,919) 3,134 $ Total (24,421) (a) 2,225 $ (2,562) (b) 5,359 $ (26,983) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8. 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. FERC FORM NO. 1 (ED. 12-88) Page 123.75 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES 1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. 2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. 4. Report data on a year-to-date basis. Line No. Item (a) Unrealized Gains and Losses on Availablefor-Sale Securities (b) Minimum Pension Liability adjustment (net amount) (c) 1 Balance of Account 219 at Beginning of Preceding Year Foreign Currency Hedges Other Adjustments (d) (e) ( 19,941,821) 2 Preceding Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 3,092,366 3 Preceding Quarter/Year to Date Changes in Fair Value ( 3,821,973) 4 Total (lines 2 and 3) ( 729,607) 5 Balance of Account 219 at End of Preceding Quarter/Year ( 20,671,428) 6 Balance of Account 219 at Beginning of Current Year ( 20,671,428) 7 Current Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 3,134,190 8 Current Quarter/Year to Date Changes in Fair Value ( 6,883,606) 9 Total (lines 7 and 8) ( 3,749,416) ( 24,420,844) 10 Balance of Account 219 at End of Current Quarter/Year FERC FORM NO. 1 (NEW 06-02) Page 122a Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES Line No. Other Cash Flow Hedges Interest Rate Swaps Other Cash Flow Hedges [Specify] (f) (g) ( 1 7,155,262) 2 3 Totals for each category of items recorded in Account 219 (h) ( 27,097,083) ( 4,359,505) 2,940,641 537,532) 5 ( 4,752,153) ( 25,423,581) 6 ( 4,752,153) ( 25,423,581) ( 6,918,726) 2,403,109 7 ( 9 10 FERC FORM NO. 1 (NEW 06-02) 1,673,502 2,224,706 8 ( 35,120) (i) (j) 462,140,944 463,814,446 504,309,223 502,749,393 5,358,896 2,189,586 ( 1,559,830) 2,562,567) ( 26,983,411) Page 122b Total Comprehensive Income 6,033,007 ( 4 Net Income (Carried Forward from Page 117, Line 78) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) (2) 05/09/2018 X A Resubmission SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION 20180509-8003 FERC PDF (Unofficial) (1) 05/09/2018 An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function. Line No. Total Company for the Current Year/Quarter Ended (b) Classification (a) Electric (c) 1 Utility Plant 2 In Service 3 Plant in Service (Classified) 4 Property Under Capital Leases 17,405,901,043 17,405,901,043 178,775,422 178,775,422 827,697,505 827,697,505 18,412,373,970 18,412,373,970 3,116,822 3,116,822 1,154,425,945 1,154,425,945 255,525,921 255,525,921 19,825,442,658 19,825,442,658 5 Plant Purchased or Sold 6 Completed Construction not Classified 7 Experimental Plant Unclassified 8 Total (3 thru 7) 9 Leased to Others 10 Held for Future Use 11 Construction Work in Progress 12 Acquisition Adjustments 13 Total Utility Plant (8 thru 12) 14 Accum Prov for Depr, Amort, & Depl 15 Net Utility Plant (13 less 14) 6,838,877,327 6,838,877,327 12,986,565,331 12,986,565,331 6,019,888,870 6,019,888,870 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) 785,915,065 785,915,065 6,805,803,935 6,805,803,935 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 33,073,392 33,073,392 6,838,877,327 6,838,877,327 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION Year/Period of Report 2017/Q4 End of Gas Other (Specify) Other (Specify) Other (Specify) Common (d) (e) (f) (g) (h) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 FERC FORM NO. 1 (ED. 12-89) Page 201 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) 1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. 2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements. Line No. Description of item Balance Beginning of Year (b) (a) 1 Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) Changes during Year Additions (c) 2 Fabrication 20,606,297 37,110,194 3 Nuclear Materials 81,891,092 29,554,685 4 Allowance for Funds Used during Construction 5 (Other Overhead Construction Costs, provide details in footnote) 6 SUBTOTAL (Total 2 thru 5) 8,755,067 7,450,078 -138,270 1,898,096 111,114,186 7 Nuclear Fuel Materials and Assemblies 8 In Stock (120.2) 9 In Reactor (120.3) 10 SUBTOTAL (Total 8 & 9) 1,365 76,043,445 266,205,234 74,563,821 266,206,599 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) 147,202,304 14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 230,118,481 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Amortization (d) Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) Changes during Year Other Reductions (Explain in a footnote) (e) Year/Period of Report 2017/Q4 End of Balance End of Year (f) Line No. 1 34,901,748 22,814,743 2 31,402,878 80,042,899 3 6,714,571 9,490,574 4 1,898,096 -138,270 5 112,209,946 6 7 74,111,129 1,933,681 8 81,223,912 259,545,143 9 261,478,824 10 11 12 -75,748,182 78,880,074 144,070,412 13 229,618,358 14 15 16 17 18 19 20 21 22 FERC FORM NO. 1 (ED. 12-89) Page 203 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) Year/Period of Report 2017/Q4 End of 1. Report below the original cost of electric plant in service according to the prescribed accounts. 2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. 3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. 4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. 5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. 6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) Line Account Balance Additions Beginning of Year No. (a) (b) (c) 1 1. INTANGIBLE PLANT 2 (301) Organization 3 (302) Franchises and Consents 3,599,321 41,149 4 (303) Miscellaneous Intangible Plant 766,014,068 158,503,662 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 769,613,389 158,544,811 6 2. PRODUCTION PLANT 7 A. Steam Production Plant 8 (310) Land and Land Rights 5,793,509 9 (311) Structures and Improvements 172,665,333 1,920,630 10 (312) Boiler Plant Equipment 1,224,743,332 253,240,238 11 (313) Engines and Engine-Driven Generators 12 (314) Turbogenerator Units 214,592,728 15,848,214 13 (315) Accessory Electric Equipment 133,151,552 4,103,525 14 (316) Misc. Power Plant Equipment 104,760,598 2,436,720 15 (317) Asset Retirement Costs for Steam Production 53,059,883 21,728,717 16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 1,908,766,935 299,278,044 17 B. Nuclear Production Plant 18 (320) Land and Land Rights 4,417,789 19 (321) Structures and Improvements 847,932,331 10,797,147 20 (322) Reactor Plant Equipment 1,235,400,577 6,665,945 21 (323) Turbogenerator Units 407,922,913 20,440,686 22 (324) Accessory Electric Equipment 293,628,093 3,936,372 23 (325) Misc. Power Plant Equipment 206,208,589 26,888,183 24 (326) Asset Retirement Costs for Nuclear Production 77,858,133 19,717,502 25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 3,073,368,425 88,445,835 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 15,764,334 4,585 38 (341) Structures and Improvements 120,813,197 9,207,467 39 (342) Fuel Holders, Products, and Accessories 55,639,804 424,293 40 (343) Prime Movers 657,158,530 3,447,721 41 (344) Generators 1,429,583,770 -13,557,118 42 (345) Accessory Electric Equipment 214,237,650 29,677,665 43 (346) Misc. Power Plant Equipment 30,377,550 1,482,214 44 (347) Asset Retirement Costs for Other Production 8,856,067 45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 2,532,430,902 30,686,827 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 7,514,566,262 418,410,706 FERC FORM NO. 1 (REV. 12-05) Page 204 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Line No. 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 (2) X A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Account Balance Beginning of Year (a) (b) 3. TRANSMISSION PLANT (350) Land and Land Rights (352) Structures and Improvements (353) Station Equipment (354) Towers and Fixtures (355) Poles and Fixtures (356) Overhead Conductors and Devices (357) Underground Conduit (358) Underground Conductors and Devices (359) Roads and Trails (359.1) Asset Retirement Costs for Transmission Plant TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 4. DISTRIBUTION PLANT (360) Land and Land Rights (361) Structures and Improvements (362) Station Equipment (363) Storage Battery Equipment (364) Poles, Towers, and Fixtures (365) Overhead Conductors and Devices (366) Underground Conduit (367) Underground Conductors and Devices (368) Line Transformers (369) Services (370) Meters (371) Installations on Customer Premises (372) Leased Property on Customer Premises (373) Street Lighting and Signal Systems (374) Asset Retirement Costs for Distribution Plant TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT (380) Land and Land Rights (381) Structures and Improvements (382) Computer Hardware (383) Computer Software (384) Communication Equipment (385) Miscellaneous Regional Transmission and Market Operation Plant (386) Asset Retirement Costs for Regional Transmission and Market Oper TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 6. GENERAL PLANT (389) Land and Land Rights (390) Structures and Improvements (391) Office Furniture and Equipment (392) Transportation Equipment (393) Stores Equipment (394) Tools, Shop and Garage Equipment (395) Laboratory Equipment (396) Power Operated Equipment (397) Communication Equipment (398) Miscellaneous Equipment SUBTOTAL (Enter Total of lines 86 thru 95) (399) Other Tangible Property (399.1) Asset Retirement Costs for General Plant TOTAL General Plant (Enter Total of lines 96, 97 and 98) TOTAL (Accounts 101 and 106) (102) Electric Plant Purchased (See Instr. 8) (Less) (102) Electric Plant Sold (See Instr. 8) (103) Experimental Plant Unclassified TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) FERC FORM NO. 1 (REV. 12-05) Page 206 Year/Period of Report 2017/Q4 End of Additions (c) 207,213,264 140,830,608 1,134,576,413 151,481,295 539,431,138 493,717,502 37,567,322 34,619,490 7,677,788 36,340,787 41,155,372 29,159,084 13,112,227 -29,610,888 -1,317,069 1,506,086 2,739,437,032 98,023,387 62,584,829 85,517,484 546,409,743 19,412,166 2,155,249 37,668,140 616,332,398 376,749,366 697,738,638 1,674,627,714 859,274,164 395,855,931 299,177,623 45,037,568 39,636,950 44,946,412 14,121,331 82,202,155 34,521,417 31,198,211 11,945,747 1,119,652 76,569,431 1,248,009 5,735,874,889 320,175,439 14,600,073 258,075,198 250,678,126 39,202,919 685,274 38,758,419 806,336 10,184,222 263,285,752 21,305,377 897,581,696 6,645,619 29,127,425 33,311,927 2,950,635 137 1,876,107 897,581,696 17,657,073,268 95,014,039 1,090,168,382 17,657,073,268 1,090,168,382 342,441 19,507,178 1,252,570 95,014,039 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. 7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. 8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. 9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date Retirements Adjustments Transfers Balance at Line End of Year No. (d) (e) (f) (g) 44,259 92,875,818 92,920,077 205,901 205,901 25,111 33,766,040 186,379,854 27,523,405 24,124,057 20,774,929 1,865,912 294,459,308 5,768,398 140,819,923 1,291,603,716 -89,813 -21,728,717 -21,728,717 -89,813 -19,570,595 -19,570,595 1,402,885 130,211 7,449,762 4,452,475 52,429 124,493 13,612,255 318,301,687 FERC FORM NO. 1 (REV. 12-05) 13,226 13,226 -76,587 -41,299,312 Page 202,917,537 113,041,207 86,422,389 51,193,971 1,891,767,141 4,417,789 855,043,304 1,240,606,942 424,941,771 297,239,315 231,759,380 78,005,040 3,132,013,541 3,686,174 1,459,580 3,421,828 325,150 1,337,392 10,230,124 3,596,211 831,847,813 835,444,024 205 15,768,919 128,631,005 55,933,886 653,156,489 1,411,574,177 243,862,886 31,735,271 8,856,067 2,549,518,700 7,573,299,382 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Retirements (d) Year/Period of Report 2017/Q4 End of (2) X A Resubmission ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Adjustments Transfers Balance at End of Year (e) (f) (g) 444,676 6,651,016 1,929,113 19,941 62,861 828,658 346,449 168,584 7,010 1,906 216,820,165 176,746,660 1,169,143,630 180,640,379 551,883,291 463,767,175 36,250,253 36,123,670 8,272,705 2,187,509 2,831,375,223 15,612 2,102,931 653,556 260,953 -219,735 82,650,551 87,918,074 581,755,217 -168,584 273,467 531 -315,216 650,536,717 420,005,813 710,010,738 1,748,344,306 886,527,434 425,613,516 307,626,939 45,731,058 5,264,047 1,963,432 1,849,762 8,170,347 7,268,147 1,440,626 3,496,431 426,162 268,671 77,548,769 32,266,168 484,972 6,024,269,132 6,593 1,670,086 9,780,076 4,872,785 2,174,191 23,876 -205,901 1,955,064 23,413,290 285,556,413 274,004,076 37,280,769 685,411 39,856,324 806,336 10,372,570 274,727,334 22,508,264 969,210,787 778,202 154,093 8,028,494 49,683 25,340,012 -37,102 25,340,012 477,100,649 -41,299,312 1,955,064 4,756,859 969,210,787 18,233,598,548 477,100,649 -41,299,312 4,756,859 18,233,598,548 FERC FORM NO. 1 (REV. 12-05) Page 207 Line No. 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) (1) 05/09/2018 An Original Arizona Public Service Company Line No. Name of Lessee (Designate associated companies with a double asterisk) (a) (2) X A Resubmission ELECTRIC PLANT LEASED TO OTHERS (Account 104) Description of Property Leased (b) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 TOTAL FERC FORM NO. 1 (ED. 12-95) Date of Report (Mo, Da, Yr) 05/09/2018 Page 213 Commission Authorization (c) Year/Period of Report End of 2017/Q4 Expiration Date of Lease (d) Balance at End of Year (e) Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) Year/Period of Report 2017/Q4 End of 1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. 2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105. Description and Location 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 10/31/2006 12/31/2025 401,193 12/31/2014 12/31/2025 320,827 5/31/2008 12/31/2025 653,352 5/1/2009 12/31/2025 427,534 11/30/2016 1/1/2027 271,540 14 Other General Parcels (2) 12/31/1999 12/31/2025 111,576 15 Other Transmission Parcels (2) 12/31/1999 12/31/2025 92,023 16 Other Distribution Parcels (4) 12/31/1999 12/31/2025 556,005 3 35th Ave. & Roanoke Ave., Phoenix, AZ 4 Paradise Substation 5 15021 N. 33rd Place, Phoenix, AZ 6 Punkin Center Substation 7 146 E. Purtill Trail, Tonto Basin, AZ 8 Buckeye to Elianto (SV4) Transmission Line 9 Township 010N 030W Sec 7; Buckeye, AZ 10 Citrus (WS4) Substation 11 Parcel 502-40-267 /T01NR02W.S10/ 2.633 acres 12 Yavapai to Wellfield 13 Township 015N 001W; Yavapai, AZ 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) 3,116,822 Page 214 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Year/Period of Report 2017/Q4 End of 1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts) 3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped. Line No. Description of Project Construction work in progress Electric (Account 107) (b) (a) 1 Generation Plant 2 3 Ocotillo Modernization Project 423,747,774 4 Four Corners F4 Selective Catalytic Reduction System 190,138,020 5 Palo Verde NRC Cyber Security Manual 9,669,477 6 Four Corners Coal Silo Section Replacement 7,344,809 7 Palo Verde Polar Crane U2 7,150,217 8 Four Corners F4 LP Generator and Field Rewind 6,852,112 9 Palo Verde WRF Clarifiers Life Extenstion 5,677,094 10 Desert Star Solar Additions/Improvements 4,695,151 11 Four Corners F4 HP Generator Stator Rewind 4,604,895 12 Four Corners Environmental Projects 3,864,077 13 Four Corners Motors, Pumps and Valves Replacements 3,665,470 14 Four Corners Horizontal Reheat Bank Replacement 3,425,842 15 Palo Verde Security Access Control Fire Protec 3,143,754 16 Palo Verde SP666 Replacement of SP Filtration System U3 3,061,569 17 Four Corners Control System Upgrade 2,846,276 18 Palo Verde Probalistic Risk Assessment Software 2,788,394 19 Four Corners Unit 4 Major Turbine Overhaul 2,501,630 20 Four Corners F4 Burner Replacement 2,363,062 21 Palo Verde Plant 2 Way Radio Replacement 2,249,660 22 Palo Verde Spent Fuel Pool Borated Inserts U2 2,029,205 23 Four Corners Dust Collector Replacement 1,995,828 24 Palo Verde CD-1218 - LP FW Heater 2B Replacement U1 1,940,568 25 Fossil Electrical System Replacements 1,917,663 26 West Phoenix Gas Turbine 1 Major Overhaul 1,824,320 27 Palo Verde Substation Replacement Construction Loop 12 1,668,553 28 Palo Verde Loss of Phase Detection System 1,619,402 29 Palo Verde CD-1218 - LP FW Heater 2A Replacement U1 1,606,971 30 Palo Verde Security Access Control FP U3 1,490,766 31 Four Corners Common Facility Building Replacement 1,431,387 32 Palo Verde Control System Upgrade 1,321,650 33 Cotton Center Solar Additions/Improvements 1,302,443 34 West Phoenix Well No. 6 Replacement 1,272,972 35 Palo Verde License Renewal Operation Manual Replacement 1,253,066 36 West Phoenix CC5 Cooling Tower Rebuild 1,246,405 37 Palo Verde Best Estimate Loss of Coolant Accident Manual Replacement 1,236,058 38 Four Corners Unit 4 Econmizer Tube Replacement 1,219,598 39 Saguaro Unit 3 Hot Gas Path Overhaul 1,217,135 40 Palo Verde Control & Monitoring System Upgrade 1,149,411 41 Palo Verde Spray Pond Filtration System Replacement 1,105,178 42 Palo Verde Polar Crane U3 1,087,420 43 TOTAL FERC FORM NO. 1 (ED. 12-87) 1,154,425,945 Page 216 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Year/Period of Report 2017/Q4 End of 1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts) 3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped. Line No. Description of Project Construction work in progress Electric (Account 107) (b) 1,072,151 (a) 1 Four Corners Unit 4 Generator Hydrogen Cooler Replacment 2 Palo Verde Polar Crane U1 1,031,291 3 Palo Verde WRF Clarifiers Life Extenstion 201 1,029,786 4 Palo Verde Concrete & Paving Replacement 1,014,242 5 Other Generation Less Than $1 Million 50,095,537 6 7 Transmission 8 9 Palo Verde - Morgan 500Kv Transmission System 94,345,767 10 North Gila - Ts8 230 Substation And Line Additions/Improvements 17,428,737 11 Mazatzal 345/69 Substation And Line Additions/Improvements 12,783,652 12 Komatke 69 Switchyard Additions/Improvements 9,239,785 13 Via Dona 69 Line Upgrade 2,966,793 14 Pinal Central - Sundance 230 Line Additions/Improvements 1,427,796 15 Bald Mountain - Dewey 69 Rebuild 1,047,148 16 Other Transmission Less Than $1 Million 10,170,034 17 18 Distribution 19 20 Smart Grid Adms Rtus Dual-Port 12,638,882 21 Underground Service-Line Extension -Non Residential 10,816,757 22 Residential Underground Distribution Lines Additions/Improvements 9,616,508 23 Network Protectors 8,545,745 24 Sky Harbor T3 Modernization 7,382,061 25 Underground Cable Replacement 5,256,439 26 Festival Ranch Substation Additions/Improvements 4,402,896 27 At&T 4 Network Transformers 2,536,614 28 Solar Innovation Study 2,439,345 29 Eastern Office Substation Add Transformer 2,271,926 30 Tempe Substation Transformer Install 2,220,790 31 Skunk Creek New Feeder 1,515,700 32 Pima Substation Additions/Improvements 1,358,969 33 Build Midtown Substation 1,325,145 34 MT Elden Line Rebuild 1,274,460 35 Punkin Center Energy Storage 1,047,081 36 Other Distribution Less Than $1 Million 12,719,911 37 38 Unplanned Emergency - Transmission And Distribution 7,079,987 39 Highway Line Relocation - Transmission And Distribution 4,472,682 40 Planned Overhead Line Replacements - Transmission and Distribution 2,884,721 41 42 General and Intangible 43 TOTAL FERC FORM NO. 1 (ED. 12-87) 1,154,425,945 Page 216.1 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Year/Period of Report 2017/Q4 End of 1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts) 3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped. Line No. Description of Project Construction work in progress Electric (Account 107) (b) (a) 1 2 800 Mhz Radio 26,896,459 3 Ems Upgrade Project 26,082,805 4 2020 Vision-Adms 16,598,996 5 Hardware/Software License Maintenance Renewal Program 8,997,585 6 NERC Cip Compliance 7,171,316 7 Deer Valley DVN2 Building Remodel 4,872,480 8 New Western Service Center 4,428,180 9 Meter Data Management System Replacement 3,892,179 10 PeopleSoft FSCM Upgrade 3,281,766 11 Physical Security System Program 1,901,756 12 CC&B Sustainability 2.6 Upgrade 1,705,392 13 T&D Consolidated Communication Plan 1,605,300 14 Yucca Plant HMI Upgrade 1,586,735 15 Local Area Network Reliability 1,531,288 16 SharePoint 2016 Upgrade 1,399,164 17 Data Analytics 1,221,861 18 Server Migrations 1,046,390 19 Other General and Intangible Less Than $1 Million 14,021,673 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) 1,154,425,945 Page 216.2 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108) 1. Explain in a footnote any important adjustments during year. 2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property. 3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. 4. Show separately interest credits under a sinking fund or similar method of depreciation accounting. Line No. Section A. Balances and Changes During Year Electric Plant in Total (c+d+e) Service (b) (c) Item (a) 1 Balance Beginning of Year 5,913,579,625 5,913,579,625 410,405,975 410,405,975 10,332,839 10,332,839 1,224,717 1,224,717 522,178 522,178 422,485,709 422,485,709 383,197,362 383,197,362 13 Cost of Removal 11,174,960 11,174,960 14 Salvage (Credit) 16,071,322 16,071,322 15 TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14) 378,301,000 378,301,000 16 Other Debit or Cr. Items (Describe, details in footnote): 62,124,536 62,124,536 6,019,888,870 6,019,888,870 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 1,003,744,690 1,003,744,690 21 Nuclear Production 1,582,458,414 1,582,458,414 24 Other Production 703,077,882 703,077,882 25 Transmission 801,763,424 801,763,424 1,681,837,250 1,681,837,250 247,007,210 247,007,210 6,019,888,870 6,019,888,870 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) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 FOOTNOTE DATA Schedule Page: 219 Line No.: 12 Column: c FERC Page 219 Column (b), Line 12 Gain/(Loss) on Disposition of Assets 383,197,362 (784,308) FERC Page 204-207 Column (d), Line 5 15,389,204 FERC Page 204-207 Column (d), Line 48 - FERC Page 204-207 Column (d), Line 60 - General Plant Retirements 1,767,517 Other - FERC Page 204-207 Column (d), Line 95 Schedule Page: 219 Line No.: 16 399,569,776 Column: c Palo Verde Decommissioning Asset Retirement Obligation in Reg. Liability Accelerated CIAC to Regulatory Assets Childs Irving Decommissioning SCE Four Corners U4-5 - Accretion Cholla Unit 2 Regulatory Asset/Liability Saguaro Steam Regulatory Asset Amortization Navajo Regulatory Asset Amortization Reserve Transfers-- Accounts 1110,1112, & 1220 & Other Entities FERC FORM NO. 1 (ED. 12-87) Page 450.1 (2,149,049) (20,246,719) 98,944,377 0 (2,056,464) (4,693,320) (1,957,689) (5,848,600) 132,000 62,124,536 2017/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) Year/Period of Report End of X A Resubmission INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) 2017/Q4 1. Report below investments in Accounts 123.1, investments in Subsidiary Companies. 2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in columns (e),(f),(g) and (h) (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. 3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. Line No. Description of Investment Date Acquired (b) (a) Date Of Maturity (c) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 Total Cost of Account 123.1 $ FERC FORM NO. 1 (ED. 12-89) 0 Page 224 TOTAL Amount of Investment at Beginning of Year (d) Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) Date of Report (Mo, Da, Yr) 05/09/2018 X A Resubmission INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued) Year/Period of Report End of 2017/Q4 4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. 5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. 6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year. 7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible in column (f). 8. Report on Line 42, column (a) the TOTAL cost of Account 123.1 Equity in Subsidiary Earnings of Year (e) Revenues for Year Amount of Investment at End of Year (g) (f) Gain or Loss from Investment Disposed of (h) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 FERC FORM NO. 1 (ED. 12-89) Page 225 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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) 20,069,909 17,197,828 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 131,249,414 135,595,138 8 Transmission Plant (Estimated) 7 Production Plant (Estimated) 38,401,294 40,602,963 9 Distribution Plant (Estimated) 81,991,917 86,390,237 426,749 247,375 252,069,374 262,835,713 707,530 -205,223 272,846,813 279,828,318 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) (1) 05/09/2018 An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/Q4 Allowances (Accounts 158.1 and 158.2) 1. Report below the particulars (details) called for concerning allowances. 2. Report all acquisitions of allowances at cost. 3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. 4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). 5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Line No. SO2 Allowances Inventory (Account 158.1) (a) 1 Balance-Beginning of Year 2 3 Acquired During Year: 4 Issued (Less Withheld Allow) 5 Returned by EPA 6 7 8 Purchases/Transfers: 9 10 11 12 13 14 15 Total 16 17 Relinquished During Year: 18 Charges to Account 509 19 Other: 20 21 Cost of Sales/Transfers: 22 23 Surrender to EPA Consent 24 Surrender to EPA (RATA) 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) 2018 Current Year No. (b) Amt. (c) No. (d) 278,343.00 Amt. (e) 48,487.00 3,982.00 19,267.00 28,883.00 48,150.00 226,211.00 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Allowances (Accounts 158.1 and 158.2) Year/Period of Report End of 2017/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. 2019 No. (f) 48,487.00 2020 Amt. (g) No. (h) 48,487.00 Amt. (i) Future Years No. Amt. (j) (k) 1,260,662.00 Totals No. (l) 1,684,466.00 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 3,982.00 19,267.00 28,883.00 48,487.00 48,487.00 1,309,149.00 48,150.00 1,680,821.00 533.00 533.00 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 8 8 1,066.00 43 43 36 37 38 39 40 41 42 43 44 45 46 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 FOOTNOTE DATA Schedule Page: 228 Line No.: 29 Column: m Total ending balance of account 158.1 per this page does not agree to the corresponding line item on page 110. The difference is due to ending balance of $8,060,182 in CO2 allowances issued by the California Air Resources Board (CARB). FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) (1) 05/09/2018 An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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) 2018 Current Year No. (b) Amt. (c) Page 228b No. (d) Amt. (e) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Allowances (Accounts 158.1 and 158.2) Year/Period of Report End of 2017/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. 2019 No. (f) Future Years 2020 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Line No. Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a) (2) X A Resubmission EXTRAORDINARY PROPERTY LOSSES (Account 182.1) Total Amount of Loss Losses Recognised During Year (b) (c) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 TOTAL FERC FORM NO. 1 (ED. 12-88) Year/Period of Report 2017/Q4 End of 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Line No. (2) X A Resubmission UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2) Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of Commission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a) Total Amount of Charges Costs Recognised During Year (b) (c) 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 TOTAL FERC FORM NO. 1 (ED. 12-88) Page 230b Year/Period of Report 2017/Q4 End of WRITTEN OFF DURING YEAR Balance at Account Charged Amount End of Year (d) (e) (f) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) (1)05/09/2018 An Original Arizona Public Service Company (2) X A Resubmission Transmission Service and Generation Interconnection Study Costs Year/Period of Report End of 2017/Q4 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,WA334372 ( 842) 143 143 23 FACIL STDY,WA334374 ( 627) 143 196,278 143 24 FACIL STDY,WA334485 ( 292) 143 100,844 143 3) 143 131,346 143 25 FACIL STDY,WA342410 ( 26 FACIL STDY,WA358556 ( 1,035) 143 179,304 143 27 FACIL STDY,WA359997 ( 266) 143 92,190 143 28 SMG FESSTD,WA403301 121 143 143 29 SMG FESSTD,WA403302 121 143 143 30 SYSIMPTSTD,WA173723 1 143 143 31 SYSIMPTSTD,WA334709 ( 6) 143 143 32 SYSIMPTSTD,WA334712 ( 6) 143 220,841 143 33 SYSIMPTSTD,WA334713 ( 6) 143 227,911 143 34 SYSIMPTSTD,WA351491 8,285 143 228,647 143 35 SYSIMPTSTD,WA352111 5,214 143 143 36 SYSIMPTSTD,WA353816 7,469 143 143 37 SYSIMPTSTD,WA377418 22,503 143 143 38 SYSIMPTSTD,WA377611 7,504 143 143 39 SYSIMPTSTD,WA377697 24,862 143 143 40 SYSIMPTSTD,WA377818 20,776 143 250,000 143 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) (1)05/09/2018 An Original Arizona Public Service Company Line No. 1 Description (a) Year/Period of Report End of 2017/Q4 (2) X A Resubmission Transmission Service and Generation Interconnection Study Costs (continued) Costs Incurred During Period (b) Account Charged (c) Reimbursements Received During the Period (d) Account Credited With Reimbursement (e) Transmission Studies 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Generation Studies 22 SYSIMPTSTD,WA383670 ( 4,412) 143 143 23 SYSIMPTSTD,WA384886 ( 2,206) 143 143 34 143 143 25 SYSIMPTSTD,WA389046 ( 2,256) 143 143 26 SYSIMPTSTD,WA399547 ( 436) 143 143 27 SYSIMPTSTD,WA402545 ( 4,239) 143 143 28 SYSIMPTSTD,WA402547 ( 3,250) 143 143 250,000 143 24 SYSIMPTSTD,WA386679 29 SYSIMPTSTD,WA402793 ( 2,032) 143 30 SYSIMPTSTD,WA402794 ( 1,239) 143 31 SYSIMPTSTD,WA402826 ( 1,830) 143 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission OTHER REGULATORY ASSETS (Account 182.3) Year/Period of Report 2017/Q4 End of 1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Assets being amortized, show period of amortization. Line No. Description and Purpose of Other Regulatory Assets (a) 1 Deferred Compensation Balance at Beginning of Current Quarter/Year (b) Debits (c) 35,595,335 CREDITS Written off During Written off During the Quarter/Year the Period Account Charged Amount (d) (e) Balance at end of Current Quarter/Year (f) 36,413,464 818,129 2 Amortize through 2036 3 4 Capital Contribution on Phoenix-Mead Transmission 108 11,040,359 332,040 10,708,319 6,188,902 146,680,338 5 U-1345-90-269 Amortize through 2050 6 7 Income Taxes - AFUDC Equity ( 5,554,041) 283,410.1 158,423,281 8 E-01345A-03-0437 Amortize through 2047 9 10 AG-1 Deferral 5,867,920 6,235,548 407 977,314 11,126,154 1,718,358 190 1,016,177 702,181 ( 14,766,725) 75,637,179 1,745,094 86,944,517 11 E-01345A-11-0224 Amortize through 2022 12 13 Prior Flow Through of Tax Benefits 14 Amortize through 2019 15 16 Deferred Fuel and Purchased Power 48,405,417 411.8,555 12,465,037 17 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 547,411.9 18 Amortize through 2018 502 19 20 Deferred Fuel and Purchased Power Mark-to-Market 45,727,094 547, 555 42,962,517 21 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 22 Amortize through 2020 23 24 Deferred Fuel and Purchased Power - Interest 60,245 1,898,477 1,838,232 25 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 26 Amortize through 2018 27 28 Navajo Coal Reclamation 5,599,774 8,498,587 501 634,593 372,189 518 372,189 13,463,768 29 E-01345A-08-0172 Amortize through 2026 30 31 Spent Nuclear Fuel 32 ER11-3468-000 Amortize through 2017 33 34 Pension and Other Postretirement Benefits ( 92,177,345) 228.3,926 711,058,563 42,693,647 576,187,571 35 E-01345A-08-0172 36 37 Demand Side Management 254 3,744,147 3,744,147 38 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 39 Amortize through 2017 40 41 Income Taxes - Change in Rates 2,922,876 ( 526,645) 283,410.1 47,584 2,348,647 135,277,914 1,698,661,211 42 Amortize through 2041 43 44 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 1,387,590,018 Page 446,349,107 232 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission OTHER REGULATORY ASSETS (Account 182.3) Year/Period of Report 2017/Q4 End of 1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Assets being amortized, show period of amortization. Line No. Description and Purpose of Other Regulatory Assets (a) 1 Income Taxes - Medicare Subsidy Balance at Beginning of Current Quarter/Year (b) Debits (c) CREDITS Written off During Written off During the Quarter/Year the Period Account Charged Amount (d) (e) Balance at end of Current Quarter/Year (f) 12,102,013 ( 1,949,286) 283,410.1 1,501,994 8,650,733 56,476,151 ( 27,033,428) 283,410.1 2,159,054 27,283,669 2 Amortize through 2024 3 4 Income Taxes - Investment Tax Credit Basis Adjustmt 5 Amortize through 2046 6 7 Property Tax Deferral 73,199,778 13,451,308 408 3,155,924 83,495,162 61,306,977 60,629,844 400 62,092,972 59,843,849 1,588,011 400 67,350 1,520,661 127,504,281 106,754,824 403 18,014,797 216,244,308 63,582,206 ( 1,899,912) 407 5,300,861 56,381,433 8 E-01345A-11-0224 Amortize thorugh 2027 9 10 Lost Fixed Cost Recovery 11 E-01345A-11-0224 12 Amortize through 2018 13 14 FERC Transmission Cost Adjustor 15 Amortize through 2018 16 17 Retired Power Plant Costs 18 Amortize through 2033 19 20 Four Corners Cost Deferral 21 Amortize through 2024 22 23 SCR Deferral 353,585 353,585 1,219,512 1,219,512 271,525,127 271,525,127 10,032,557 10,032,557 24 E-01345A-16-0036 25 26 TCA Balancing account 27 E-01345A-16-0036 Amortize through 2018 28 29 Deficient Deferred Income Taxes 30 Tax Cuts & Jobs Act-ACC 31 32 Deficient Deferred Income Taxes 33 Tax Cuts & Jobs Act-FERC 34 35 36 37 38 39 40 41 42 43 44 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 1,387,590,018 Page 446,349,107 232.1 135,277,914 1,698,661,211 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 232.1 Line No.: 29 Column: c Deficient Deferred Income Taxes Regulatory Gross Up Schedule Page: 232.1 Line No.: 32 Column: c Deficient Deferred Income Taxes Regulatory Gross Up FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission MISCELLANEOUS DEFFERED DEBITS (Account 186) 1. Report below the particulars (details) called for concerning miscellaneous deferred debits. 2. For any deferred debit being amortized, show period of amortization in column (a) 3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes. Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 Description of Miscellaneous Deferred Debits (a) Rouse Deferred Lease Payments (Through 2045) Redhawk Effluent Water Balance at Beginning of Year Debits (b) 90,767,702 CREDITS Account Charged (d) 257,617 931 (c) Amount (e) 3,387,538 Balance at End of Year (f) 87,637,781 200,000 143,750 232 143,750 200,000 Information Sys Leases & Maint. 9,887,243 2,543,369 165 2,439,592 9,991,020 Unamortized Arrangement Fees (Through 2021) 3,559,728 2,386,199 431,525 2,355,292 3,590,635 Transmission Debits (Through 2025) 6,514,710 28,184 565 1,322,713 5,220,181 Prepaid Payroll Agreements Prepaid Water Supply Agreements (Through 2050) 294,601 294,601 7,048,655 165 Debt Shelf Registration 149,396 various 219,652 6,829,003 147,797 1,599 Freight in Transit 340,368 2,351,256 232 2,589,509 102,115 Prepaid Monitoring Services (Through 2023) 669,210 576,275 165 679,133 566,352 14,187,656 165 14,187,656 790,494 400,760 232 400,760 790,494 4,547,758 871,142 506 153,388 5,265,512 Long Term Prepaid Insurance Rapid Response Center Equipment Four Corners NEPA (Through 2041) Scottsdale Improvement District (Through 2032) Minor Items 1,937,721 107 -23,620 208,065 various 1,937,721 158,750 25,695 47 Misc. Work in Progress Deferred Regulatory Comm. 48 Expenses (See pages 350 - 351) 49 TOTAL FERC FORM NO. 1 (ED. 12-94) 124,596,849 122,452,709 Page 233 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X 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) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES (Account 190) 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes. 2. At Other (Specify), include deferrals relating to other income and deductions. Line No. Description and Location Balance of Begining of Year (b) (a) Balance at End of Year (c) 1 Electric 2 Risk Management Activities 3 Pension and Other Post Retirement Liabilities 40,149,112 25,767,214 194,981,280 78,536,109 4 TCJA Excess Deferred Taxes 446,702,533 5 Regulated Liabilities - Asset Retirement Obligation 107,958,597 82,351,821 6 Regulated Liabilities - Other 238,008,304 139,745,256 7 Other 245,477,196 143,687,676 8 TOTAL Electric (Enter Total of lines 2 thru 7) 826,574,489 916,790,609 826,574,489 916,790,609 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 234 Line No.: 4 Column: c TCJA Excess Deferred Taxes - FERC Jurisdiction TCJA Excess Deferred Taxes - ACC Jurisdiction Total 65,501,171 381,201,362 446,702,533 Excess Deferred Income Taxes Regulatory Gross Up FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission CAPITAL STOCKS (Account 201 and 204) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. 2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Line No. Class and Series of Stock and Name of Stock Series Number of shares Authorized by Charter Par or Stated Value per share Call Price at End of Year (a) (b) (c) (d) 1 Common Stock 100,000,000 2 3 Total Common Stock 100,000,000 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 FERC FORM NO. 1 (ED. 12-91) Page 250 2.50 Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission CAPITAL STOCKS (Account 201 and 204) (Continued) Year/Period of Report 2017/Q4 End of 3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. 4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or non-cumulative. 5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purposes of pledge. OUTSTANDING PER BALANCE SHEET (Total amount outstanding without reduction for amounts held by respondent) Shares Amount (e) (f) 71,264,947 178,162,368 HELD BY RESPONDENT AS REACQUIRED STOCK (Account 217) Shares (g) Cost (h) IN SINKING AND OTHER FUNDS Shares (i) Line No. Amount (j) 1 2 71,264,947 178,162,368 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 FERC FORM NO. 1 (ED. 12-88) Page 251 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission OTHER PAID-IN CAPITAL (Accounts 208-211, inc.) Year/Period of Report 2017/Q4 End of Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such change. (a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation. (b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to amounts reported under this caption including identification with the class and series of stock to which related. (c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. (d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations, disclose the general nature of the transactions which gave rise to the reported amounts. Line No. Item (a) 1 Gain on Resale or Cancellation of Capital Stock - Account 210 Amount (b) 1,505,626 2 Balance at Beginning of Year: $1,505,626 3 Credits 4 Debits 5 Balance at End of Year: $1,505,626 6 7 Misc Paid in Capital - Account 211 8 Transfer of Contract from Pinnacle West Marketing & Trading LLC 12,323,739 9 Balance at Beginning of Year: $12,323,739 10 Credit 11 Debit 12 Balance at End of Year: $12,323,739 13 14 El Dorado transfer of Aegis software to APS 4,571,000 15 Balance at Beginning of Year: $4,571,000 16 Credit 17 Debit 18 Balance at End of Year: $4,571,000 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 TOTAL FERC FORM NO. 1 (ED. 12-87) 18,400,365 Page 253 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission CAPITAL STOCK EXPENSE (Account 214) Year/Period of Report 2017/Q4 End of 1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock. 2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged. Line No. 1 Common Stock Expense Class and Series of Stock (a) Balance at End of Year (b) 37,461,284 2 Shelf Registration 50,368 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 TOTAL FERC FORM NO. 1 (ED. 12-87) 37,511,652 Page 254b Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission LONG-TERM DEBT (Account 221, 222, 223 and 224) 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received. 5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were issued. 6. In column (b) show the principal amount of bonds or other long-term debt originally issued. 7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued. 8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount. Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted. 9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as specified by the Uniform System of Accounts. Line No. Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a) Principal Amount Of Debt issued (b) Total expense, Premium or Discount (c) 1 Pollution Control Bonds Account 221 2 City of Farmington, NM Pollution Control Revenue Refunding Bonds1994 Series A 49,400,000 1,062,971 3 City of Farmington, NM Pollution Control Revenue Refunding Bonds 1994 Series B 65,750,000 1,314,677 4 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds 2009 Series A 35,975,000 576,013 5 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds 2009 Series C 32,000,000 445,268 183,125,000 3,398,929 200,000,000 2,049,339 6 Subtotal 7 8 Other Long Term Debt Account 224 9 10 11 5.625% Unsecured Senior Note 12 2,288,000 D 13 5.500% Unsecured Senior Note 250,000,000 14 2,147,500 D 15 6.875% Unsecured Senior Note 150,000,000 1,333,769 500,000,000 4,301,413 16 226,500 D 17 8.750% Unsecured Senior Note 18 275,000 D 19 5.05% Unsecured Senior Note 300,000,000 20 3,096,550 2,022,000 D 21 4.50% Unsecured Senior Note 325,000,000 22 3,321,373 3,074,500 D 23 4.50% Unsecured Senior Note 100,000,000 24 1,148,640 -5,182,000 P 25 4.70% Unsecured Senior Note 250,000,000 26 2,501,050 1,000,000 D 27 3.35% Unsecured Senior Note 250,000,000 2,080,950 250,000,000 2,103,800 300,000,000 2,384,360 28 230,000 D 29 2.20% Unsecured Senior Note 30 35,000 D 31 3.15% Unsecured Senior Note 32 1,578,000 D 33 TOTAL FERC FORM NO. 1 (ED. 12-96) 2,362,692 4,639,113,231 Page 256 50,322,454 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission LONG-TERM DEBT (Account 221, 222, 223 and 224) 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received. 5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were issued. 6. In column (b) show the principal amount of bonds or other long-term debt originally issued. 7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued. 8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount. Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted. 9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as specified by the Uniform System of Accounts. Line No. Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a) 1 4.35% Unsecured Senior Note Principal Amount Of Debt issued (b) 250,000,000 2 Total expense, Premium or Discount (c) 2,518,924 460,000 D 3 3.75% Unsecured Senior Note 350,000,000 4 3,691,995 1,004,500 D 5 2.55% Unsecured Senior Note 250,000,000 6 2,118,925 1,157,500 D 7 4.35% Unsecured Senior Note 250,000,000 8 2,628,975 -3,822,500 P 9 2.95% Unsecured Senior Note 300,000,000 10 2,559,770 207,000 D 11 12 13 14 15 APS Term Loan 2015 50,000,000 10,000 16 APS Term Loan 2016 100,000,000 10,000 17 18 COLI LOANS ( Option II Benefits) 30,988,231 19 20 Subtotal 4,455,988,231 46,923,525 21 22 23 24 25 26 27 28 29 30 31 32 33 TOTAL FERC FORM NO. 1 (ED. 12-96) 4,639,113,231 Page 256.1 50,322,454 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) Year/Period of Report 2017/Q4 End of 10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years. 11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium on Debt - Credit. 12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid during year. Give Commission authorization numbers and dates. 13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee and purpose of the pledge. 14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. 15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. 16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued. Nominal Date of Issue (d) Date of Maturity (e) AMORTIZATION PERIOD Date From (f) Date To (g) Outstanding (Total amount outstanding without reduction for amounts held by respondent) (h) Interest for Year Amount (i) Line No. 1 5/25/94 5/01/24 5/25/94 5/01/24 49,400,000 2,321,800 2 9/14/94 9/01/24 9/14/94 9/01/24 65,750,000 3,090,250 3 6/26/09 5/01/29 6/26/09 5/01/29 35,975,000 376,451 4 6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 560,000 5 183,125,000 6,348,501 6 7 8 9 10 5/07/03 5/15/33 5/07/03 5/15/33 200,000,000 11,250,000 11 8/22/05 09/01/35 8/22/05 9/1/2035 250,000,000 13,750,000 13 8/03/06 8/01/36 8/03/06 8/01/36 150,000,000 10,312,500 15 2/26/09 3/01/19 2/26/09 3/01/19 500,000,000 43,750,000 17 12 14 16 18 8/25/11 9/01/41 8/25/11 9/01/41 300,000,000 15,150,000 19 1/13/12 4/01/42 1/13/12 4/01/42 325,000,000 14,625,000 21 1/13/12 4/01/42 1/13/12 4/01/42 100,000,000 4,500,000 23 20 22 24 1/10/14 1/15/44 1/10/14 1/15/44 250,000,000 11,750,000 25 6/18/14 6/15/24 6/18/14 6/15/24 250,000,000 8,375,000 27 1/12/15 1/15/20 1/12/15 1/15/20 250,000,000 5,500,000 29 5/19/15 5/15/25 5/19/15 5/15/25 300,000,000 9,450,000 31 26 28 30 32 4,639,113,231 FERC FORM NO. 1 (ED. 12-96) Page 257 198,918,367 33 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) Year/Period of Report 2017/Q4 End of 10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years. 11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium on Debt - Credit. 12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid during year. Give Commission authorization numbers and dates. 13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee and purpose of the pledge. 14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. 15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. 16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued. Nominal Date of Issue (d) 11/06/15 Date of Maturity (e) 11/15/45 AMORTIZATION PERIOD Date From (f) 11/06/15 Date To (g) 11/15/45 Outstanding (Total amount outstanding without reduction for amounts held by respondent) (h) 250,000,000 Line Interest for Year No. Amount (i) 9,666,667 1 2 5/06/16 5/15/46 5/06/16 5/15/46 350,000,000 13,125,000 3 9/20/16 9/15/26 9/20/16 9/15/26 250,000,000 6,375,000 5 3/21/17 11/15/45 3/21/17 11/15/45 250,000,000 9,666,667 7 9/11/17 9/15/27 9/11/17 9/15/27 300,000,000 2,679,583 9 4 6 8 10 11 12 13 14 6/26/15 6/26/18 6/26/15 6/26/18 50,000,000 845,494 15 4/22/16 4/22/19 4/22/16 4/22/19 100,000,000 1,798,955 16 17 30,988,231 18 19 4,455,988,231 192,569,866 20 21 22 23 24 25 26 27 28 29 30 31 32 4,639,113,231 FERC FORM NO. 1 (ED. 12-96) Page 257.1 198,918,367 33 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 was set to expire on December 31, 2017; however, on December 15, 2016, APS filed a financing application with the ACC requesting continuation of its authorization of (i) Continuing Long-Term Debt of $5.1 billion and (ii) Continuing Short-Term Debt. The financing application is currently pending with the ACC. The authorizations approved in the 2013 order continue until further order of the ACC with respect to the pending application. Schedule Page: 256.1 Line No.: 18 Column: h The change in the loan balance for the Coli Loan is as follows: Total outstanding balance @ 12/31/16 $ 29,686,078 2017 death repayments (406,658) 2017 net premiums 503,842 2017 net 1,204,969 interest Balance outstanding @ 12/31/17 $ 30,988,231 Schedule Page: 256.1 Line No.: 20 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) $ 200,211,147 $ (1,062,674) (210,105) (20,000) 198,918,368 Page 450.1 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES 1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. 2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. 3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote. Line Particulars (Details) No. (a) 1 Net Income for the Year (Page 117) Amount (b) 504,309,223 2 3 4 Taxable Income Not Reported on Books 5 Contributions in Aid of Construction 13,402,832 6 Tax Gain/Loss on Sale of Business Property -12,136,438 7 Other Taxable Income Not Reported on Books 10,082,658 8 9 Deductions Recorded on Books Not Deducted for Return 10 Book Depreciation and Amortization 606,191,827 11 Income Tax Per Books 268,673,398 12 Pension and Other Post-Retirement Benefits 3,895,463 13 Other Deductions Recorded on Books Not Deducted for Return (see footn) 224,111,694 14 Income Recorded on Books Not Included in Return 15 Book Gain/Loss on Sale of Business Property 3,375,788 16 Mark-to-Market Adjustments -3,586,454 17 Cash Surrender Value -1,204,969 18 Other Income Recorded on Books Not Included in Return -1,636,950 19 Deductions on Return Not Charged Against Book Income 20 Tax Depreciation and Amortization -835,819,246 21 Expenditures Capitalized for Book Not Tax -199,145,453 22 Other Deductions on Return Not Charged Against Book Income (see footn) -382,362,102 23 24 25 26 27 Federal Tax Net Income 198,151,271 28 Show Computation of Tax: 29 ($198,511,954) * 35% 69,352,945 30 31 Tax Attributes Utilized -18,821,105 32 33 Net Current Year Federal Tax Expense 50,531,840 34 35 Other (includes 2016 Return-to-Provision) -30,344,570 36 37 Net Federal Tax Expense per Income Statement 20,187,270 38 39 40 41 42 43 44 FERC FORM NO. 1 (ED. 12-96) Page 261 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 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 207,653,859 9,588,563 6,869,272 Total Schedule Page: 261 $ Line No.: 22 224,111,694 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 (207,430,654) (77,341,655) (94,670,591) (2,281,000) (296,933) (341,270) Total FERC FORM NO. 1 (ED. 12-87) $ Page 450.1 (382,362,102) 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR Year/Period of Report 2017/Q4 End of 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts. 2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes. 3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. 4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. Line No. Kind of Tax (See instruction 5) (a) 1 Federal Income BALANCE AT BEGINNING OF YEAR Taxes Accrued Prepaid Taxes (Account 236) (Include in Account 165) (b) (c) 11,312,626 13,381,881 2 FICA 3 Unemployment 4 Heavy Vehicle Use -49,591 5 Fuel Tax -13,648 6 Subtotal 11,249,387 Taxes Charged During Year (d) 20,187,271 Taxes Paid During Year (e) 13,156,100 52,440,178 52,440,178 285,642 285,642 84,857 89,701 72,997,948 65,985,606 14,898,100 14,368,917 -250,151 -485,316 29,817 29,817 Adjustments (f) 13,985 13,381,881 7 8 New Mexico: State and Local 9 Real and Personal Property 7,013,948 10 Income -55,570 11 Unemployment 12 Sales 13 Use 14 Subtotal -14,453 14,431 -2,221 5,791 3,570 14,697,988 13,916,988 183,953,956 180,741,688 3,158,490 -4,252,478 17,477,116 272,973,924 271,398,394 371,896 21,585,848 20,819,657 6,223,507 551,609 559,649 6,997,274 -55,570 15 16 Arizona: State and Local 17 Real and Personal Property 89,297,689 18 Income -2,100,157 19 Diesel Fuel 20 State and City Sales 21 State and City Use 22 State and City Tax Reserve 23 Unemployment 24 Subtotal 113,370,208 816,534 816,534 483,040,361 470,083,444 110,162 110,162 110,162 110,162 26,768 26,768 -52,298 -131,106 -168,592 -52,298 -104,338 -141,824 11,173,856 570,742,626 549,954,881 -2,100,157 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) 141,954,872 Page 262 -45,888 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR Year/Period of Report 2017/Q4 End of 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts. 2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes. 3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. 4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. Line No. Kind of Tax (See instruction 5) (a) 1 Texas: State BALANCE AT BEGINNING OF YEAR Taxes Accrued Prepaid Taxes (Account 236) (Include in Account 165) (b) (c) Taxes Charged During Year (d) Taxes Paid During Year (e) Adjustments (f) 2 Income 3 Unemployment 4 Subtotal 5 6 Sales Tax - Palo Verde Lease 505 505 505 505 -45,888 570,742,626 549,954,881 -45,888 7 Payroll - other 8 Sales Tax - Unbilled Revenue 10,338,003 9 Subtotal 10,338,003 -45,888 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) 11,173,856 141,954,872 Page 262.1 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) Year/Period of Report 2017/Q4 End of 5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying the year in column (a). 6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. 7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. 8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts. 9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax. BALANCE AT END OF YEAR Prepaid Taxes (Taxes accrued (Incl. in Account 165) Account 236) (g) (h) 31,725,678 DISTRIBUTION OF TAXES CHARGED Extraordinary Items Electric (Account 408.1, 409.1) (Account 409.3) (i) (j) 24,846,915 26,874,155 -54,435 Adjustments to Ret. Earnings (Account 439) (k) Other (l) -4,659,644 1 25,566,023 2 285,642 3 84,857 -27,633 31,643,610 Line No. 4 5 51,721,070 21,276,878 6 7 8 7,543,131 13,898,100 179,595 -254,320 -22 7,722,704 13,643,780 1,000,000 9 4,169 10 29,817 11 14,431 12 5,791 13 1,054,208 14 15 16 92,509,957 168,905,029 15,048,927 17 5,310,811 3,038,305 120,185 18 272,973,924 20 19 19,052,646 21,585,848 21 6,215,467 1,138,096 38,663 512,946 22 816,534 23 124,226,977 171,981,997 311,058,364 24 25 110,162 26 110,162 28 27 29 30 26,768 31 -14,812 -132,671 1,565 32 -14,812 -105,903 1,565 34 33 35 36 37 38 39 40 173,870,594 FERC FORM NO. 1 (ED. 12-96) 237,351,106 Page 333,345,632 263 41 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) Year/Period of Report 2017/Q4 End of 5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying the year in column (a). 6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. 7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. 8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts. 9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax. BALANCE AT END OF YEAR Prepaid Taxes (Taxes accrued (Incl. in Account 165) Account 236) (g) (h) DISTRIBUTION OF TAXES CHARGED Extraordinary Items Electric (Account 408.1, 409.1) (Account 409.3) (i) (j) Adjustments to Ret. Earnings (Account 439) (k) Line No. Other (l) 1 2 3 4 5 6 505 7 10,292,115 -45,888 8 10,292,115 -45,383 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 40 173,870,594 FERC FORM NO. 1 (ED. 12-96) 237,351,106 Page 333,345,632 263.1 41 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) A Resubmission X ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the average period over which the tax credits are amortized. Line No. Account Subdivisions (a) Balance at Beginning of Year (b) Deferred for Year Account No. Amount (d) (c) Allocations to Current Year's Income Account No. Amount (e) (f) Adjustments (g) 1 Electric Utility 2 3% 3 4% 4 7% 5 10% 6 101,763 255 210,060,528 255 3,524,462 420 81,816 420 8,029,922 7 8 TOTAL 210,162,291 3,524,462 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 8,111,738 Name of Respondent This Report Is: Date of Report Year/Period of Report (Mo, Da, Yr) 2017/Q4 End of Arizona Public Service Company 05/09/2018 (2) X A Resubmission ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Balance at End of Year (h) 19,947 205,555,068 Average Period of Allocation to Income (i) ADJUSTMENT EXPLANATION Line No. 1 2 3 4 5 6 7 8 9 0.24 years 25.60 years 205,575,015 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 266 Line No.: 8 Column: b $12,611 is associated with transmission investments. Schedule Page: 266 Line No.: 8 Column: h $2,123 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) 05/09/2018 2017/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission OTHER DEFFERED CREDITS (Account 253) 1. Report below the particulars (details) called for concerning other deferred credits. 2. For any deferred credit being amortized, show the period of amortization. 3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes. Description and Other Deferred Credits Line No. (a) 1 Deferred Compensation Balance at Beginning of Year (b) 3,984,177 DEBITS Contra Account (c) 182.3 Credits Balance at End of Year (d) 1,030,373 (e) (f) 116,389 3,070,193 12,721,534 18,028,774 201,304,060 628,009 4,505,891 14,526,395 1,210,774 114,649 4,256,043 Amount 2 3 Coal Reclamation 195,996,820 232 10,648,513 182.3, 501 5,352,168 131 300,000 143 841,306 165, 555 4 5 Navajo Retiree Health Care Costs 6 7 Legal Reserves 8 9 Imperial Irrigation Prepaid O&M 300,000 10 11 Land Lease Obligations 12 904,011 998,519 935,814 Through 2048 13 14 Interconnection Studies 4,382,046 143 20,689,745 21,094,880 4,787,181 288,809 143 3,216,141 5,073,799 2,146,467 930.2 1,198,703 15 16 Retention 17 18 License Fees 2,923,346 1,724,643 19 20 Leasehold Improvements 21 13,170 131 70,174 57,004 57,998 131 69,971 9,634 19,358,489 232, 567 332,753 15,527,200 232 13,168,800 6,558,800 8,917,200 7,224,233 509, 242 7,908,666 690,818 6,385 1,426,513 107 4,070,092 5,496,605 550,000 456 550,000 107 2,700,000 2,700,000 855,830 855,830 67,255,484 64,875,079 Through 2017 22 23 Escheated Funds -2,339 24 25 SCE Right of Way 19,025,736 26 27 Tolling Agreements 28 29 Carbon Allowance 30 31 OCC Modernization Overland Retentn 32 Through 2019 33 34 House Warranty Program 35 Through 2018 36 37 Solar Plant Insurance Proceeds 38 39 Minor Items Various 40 41 42 43 44 45 46 47 TOTAL FERC FORM NO. 1 (ED. 12-94) 268,874,788 Page 269 266,494,383 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281) 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property. 2. For other (Specify),include deferrals relating to other income and deductions. CHANGES DURING YEAR Line No. Account Balance at Beginning of Year (a) (b) 1 Accelerated Amortization (Account 281) 2 Electric 3 Defense Facilities 4 Pollution Control Facilities 5 Other (provide details in footnote): 6 7 8 TOTAL Electric (Enter Total of lines 3 thru 7) 9 Gas 10 Defense Facilities 11 Pollution Control Facilities 12 Other (provide details in footnote): 13 14 15 TOTAL Gas (Enter Total of lines 10 thru 14) 16 17 TOTAL (Acct 281) (Total of 8, 15 and 16) 18 Classification of TOTAL 19 Federal Income Tax 20 State Income Tax 21 Local Income Tax NOTES FERC FORM NO. 1 (ED. 12-96) Page 272 Amounts Debited to Account 410.1 (c) Amounts Credited to Account 411.1 (d) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued) 3. Use footnotes as required. CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.2 to Account 411.2 (e) (f) ADJUSTMENTS Debits Account Credited (g) Credits Account Debited (i) Amount (h) Amount (j) Balance at End of Year Line No. (k) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 NOTES (Continued) FERC FORM NO. 1 (ED. 12-96) Page 273 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282) Year/Period of Report 2017/Q4 End of 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization 2. For other (Specify),include deferrals relating to other income and deductions. CHANGES DURING YEAR Line No. Account Balance at Beginning of Year (a) (b) Amounts Debited to Account 410.1 (c) Amounts Credited to Account 411.1 (d) 1 Account 282 2 Electric 3,205,807,752 733,294,125 597,054,062 3,205,807,752 733,294,125 597,054,062 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 24,762,188 831,017 3,230,569,940 734,125,142 597,054,062 2,881,701,987 653,787,773 502,725,155 348,867,953 80,337,369 94,328,907 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued) Year/Period of Report 2017/Q4 End of 3. Use footnotes as required. CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.2 to Account 411.2 (e) (f) ADJUSTMENTS Debits Account Credited (g) Amount (h) Credits Account Debited (i) Amount (j) Balance at End of Year Line No. (k) 1 254 1,174,666,390 2,167,381,425 2 3 4 1,174,666,390 2,167,381,425 5 6 7 1,174,666,390 25,593,205 8 2,192,974,630 9 10 1,174,666,390 1,858,098,215 11 334,876,415 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283) Year/Period of Report 2017/Q4 End of 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts recorded in Account 283. 2. For other (Specify),include deferrals relating to other income and deductions. Line No. Balance at Beginning of Year (b) Account (a) CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 (c) (d) 1 Account 283 2 Electric 3 Reg. Assets - AFUDC 61,088,018 97,045,333 90,175,673 4 Reg Assets - Mark to Market 21,396,095 44,247,367 2,943,620 5 Reg Assets - Pension and Other 274,184,183 4,562,324 59,103,804 6 Reg Assets - Other 183,060,949 57,851,558 31,642,926 7 Mark to Market 21,129,392 2,535,429 18,799,962 8 Other 59,202,822 81,600,364 31,219,346 620,061,459 287,842,375 233,885,331 620,061,459 287,842,375 233,885,331 540,493,965 252,341,647 197,218,672 79,567,494 35,500,728 36,666,659 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued) Year/Period of Report 2017/Q4 End of 3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other. 4. Use footnotes as required. CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.2 to Account 411.2 (e) (f) ADJUSTMENTS Debits Account Credited (g) Credits Account Debited (i) Amount (h) Amount (j) Balance at End of Year (k) Line No. 1 2 254 31,592,688 36,364,990 3 254 21,921,917 40,777,925 4 254 76,794,279 142,848,424 5 254 80,605,601 182.3 198,460,088 6 2,411,204 7 219, 254 69,796,108 2,453,655 254 38,552,053 251,920,193 69,796,108 71,031,787 8 491,894,418 9 10 11 12 13 14 15 16 17 18 251,920,193 69,796,108 491,894,418 19 20 251,585,290 334,903 69,796,108 413,827,758 78,066,660 21 22 23 NOTES (Continued) FERC FORM NO. 1 (ED. 12-96) Page 277 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 FOOTNOTE DATA Schedule Page: 276 Line No.: 6 Column: j Deficient Deferred Income Taxes Regulatory Gross Up Schedule Page: 276 Line No.: 6 Column: k Included in the total are the following amounts: Reg Asset - TCJA Deficient Deferred Taxes - ACC Jurisdiction Reg Asset - TCJA Deficient Deferred Taxes - FERC Jurisdiction Schedule Page: 276 Line No.: 21 Column: j Deficient Deferred Income Taxes Regulatory Gross Up FERC FORM NO. 1 (ED. 12-87) Page 450.1 67,308,836 2,487,272 2017/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission OTHER REGULATORY LIABILITIES (Account 254) 1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Liabilities being amortized, show period of amortization. Line No. Description and Purpose of Other Regulatory Liabilities (a) 1 PacifiCorp CT Deferred Gain Balance at Begining of Current Quarter/Year (b) 6,000,000 DEBITS Account Credited (c) 456 Amount Credits (d) (e) Balance at End of Current Quarter/Year (f) 2,000,000 4,000,000 2 U-1345-90-269 Amortize through 2019 3 4 Asset Retirement Obligations 279,975,611 52,195,334 332,170,945 167,851) 69,055,819 ( 54,157,032) 54,661,212 1,609,200 16,896,600 2,478,935 75,458,796 ( 3,654,129) 23,155,071 5 FERC Order# 552 Amortize through 2057 6 7 Spent Nuclear Fuel Storage 71,725,574 518 2,501,904 113,194,633 190 4,376,389 ( 8 E-01345A-03-0437, E-01345A-05-0816, -0826, 9 -0827 Amortize through 2027 10 11 Income Taxes - Unamortized Investment Tax Credit 12 E-01345A-05-0816, -0826, -0827 13 Amortize through 2046 14 15 Sundance Maintenance 15,287,400 16 E-01345A-05-0816, -0826, -0827 17 Amortize through 2030 18 19 Income Tax - Change in Rates 75,592,485 283 2,612,624 20 Amortize through 2046 21 22 Renewable Energy Standard 26,809,200 23 E-01345A-03-0437, E-01345A-05-0816, -0826, 24 -0827 Amortize through 2018 25 26 Excess Deferred Taxes 1,718,359 190 1,016,178 20,472,245 908 54,471,891 41,986,776 7,987,130 156,575,243 182 32,551,164 65,602,918 189,626,997 539,364 400 1,410,545 2,438,664 1,567,483 13,982,876 407 2,330,957 702,181 27 Amortize through 2019 28 29 Demand Side Management 30 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 31 Amortize through 2019 32 33 Other Postretirement Benefits 34 E-01345A-08-0172 35 36 FERC transmission true up 37 Amortize through 2019 38 39 Removal costs Cholla 11,651,919 40 Amortize through 2033 41 TOTAL FERC FORM NO. 1/3-Q (REV 02-04) 814,110,646 Page 278 106,544,412 1,913,645,612 2,621,211,846 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission OTHER REGULATORY LIABILITIES (Account 254) 1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Liabilities being amortized, show period of amortization. Line No. Description and Purpose of Other Regulatory Liabilities (a) Balance at Begining of Current Quarter/Year (b) DEBITS Account Credited (c) Amount Credits (d) (e) Balance at End of Current Quarter/Year (f) 1 2 Power Supply Adjuster Marked to Market 1,745,094 501,547 18,247,507 501 12,245,055 421 1,745,094 3 Amortize through 2017 4 5 Four Corners Coal Reclamation ( 245,189) 2,286,003 20,778,699 1,772,855 938,321 11,410,521 1,537,629,221 1,537,629,221 264,202,848 264,202,848 256,404 256,404 1,913,645,612 2,621,211,846 6 E-013454A-05-0816, -0826, -0827 7 Amortize through 2038 8 9 Deferred Gain on Sale of Property 10 E-01345A-09-0357 amortize through 2022 11 12 Excess Deferred Income Taxes 13 Tax Cuts & Jobs Act-ACC 14 15 Excess Deferred Income Taxes 16 Tax Cuts & Jobs Act-FERC 17 18 Red Rock 19 E-0145A-16-0036 Amortize through 2023 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 TOTAL FERC FORM NO. 1/3-Q (REV 02-04) 814,110,646 Page 278.1 106,544,412 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 278.1 Line No.: 12 Column: e Excess Deferred Income Taxes Regulatory Gross Up Schedule Page: 278.1 Line No.: 15 Column: e Excess Deferred Income Taxes Regulatory Gross Up FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission ELECTRIC OPERATING REVENUES (Account 400) 1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. 2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. 3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of each month. 4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. 5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Line No. Operating Revenues Year to Date Quarterly/Annual (b) Title of Account (a) Operating Revenues Previous year (no Quarterly) (c) 1 Sales of Electricity 2 (440) Residential Sales 1,792,452,827 1,736,195,175 1,400,817,101 1,395,289,253 190,953,711 190,926,089 22,649,859 22,578,875 143,156 181,677 3,407,016,654 3,345,171,069 117,095,734 119,366,602 3,524,112,388 3,464,537,671 3,524,112,388 3,464,537,671 16 (450) Forfeited Discounts 6,278,580 8,154,228 17 (451) Miscellaneous Service Revenues 7,860,353 9,339,995 701,517 6,898,303 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 4,474,196 7,800,261 47,140,324 31,605,546 66,454,970 63,798,333 3,590,567,358 3,528,336,004 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission ELECTRIC OPERATING REVENUES (Account 400) Year/Period of Report 2017/Q4 End of 6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) 7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases. 8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. 9. Include unmetered sales. Provide details of such Sales in a footnote. 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 13,207,135 13,195,346 1,080,665 1,061,814 2 3 12,380,386 12,411,366 128,696 126,662 4 2,284,201 2,267,688 4,058 3,845 5 144,124 144,857 1,054 1,037 6 2,165 2,745 154 153 7 8 9 28,018,011 28,022,002 1,214,627 1,193,511 10 2,892,159 3,906,044 40 46 11 30,910,170 31,928,046 1,214,667 1,193,557 12 13 30,910,170 Line 12, column (b) includes $ Line 12, column (d) includes FERC FORM NO. 1/3-Q (REV. 12-05) 31,928,046 3,057,171 8,206 of unbilled revenues. MWH relating to unbilled revenues Page 301 1,214,667 1,193,557 14 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 FOOTNOTE DATA Schedule Page: 300 Line No.: 2 Column: c FERC Accounting Order on SCE Expiration Payment AC18-13-000 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. FERC Accounting Order on SCE Expiration Payment AC18-13-000 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. FERC Accounting Order on SCE Expiration Payment AC18-13-000 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 6,584,099 1,276,254 7,860,353 $ $ Line No.: 21 Column: b PCS Project PacifiCorp CT Deferred Gain Amortization Fuel Loading Bid Fee Proceeds Effluent Water Rights Fee Management/Administration Fees Home Warranty Program Other Facility Charges Participant Station Power Revenue Call Center Referrals Risk Management Surepay and Autopay Discount Total FERC FORM NO. 1 (ED. 12-87) 9,291,197 48,798 9,339,995 $ $ 2,584,259 2,000,000 1,074,292 590,000 (11,363) 630,206 220,665 208,415 237,922 119,628 48,988 (1,497,141) (1,731,675) 4,474,196 Page 450.1 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 300 Line No.: 21 Column: c 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 Line No.: 22 $ $ 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 FERC Accounting Order on SCE Expiration Payment AC18-13-000 FERC FORM NO. 1 (ED. 12-87) Page 450.2 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES OF ELECTRICITY BY RATE SCHEDULES Year/Period of Report 2017/Q4 End of 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading. 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 3,756,469 555,225,560 466,839 8,047 0.1478 3 ET-1 1,707,057 227,733,093 109,374 15,608 0.1334 4 ET-2 4,441,975 599,470,490 305,604 14,535 0.1350 548,913 66,188,728 22,053 24,891 0.1206 0.1204 5 ECT-1R 6 ECT-2 2,200,517 264,938,794 96,823 22,727 7 ET-SP 38,428 5,245,042 2,289 16,788 0.1365 8 ET-EV 6,820 807,096 256 26,641 0.1183 9 R-XS 0.1495 24,949 3,729,925 4,490 5,557 10 R-BASIC 20,121 3,135,790 2,881 6,984 0.1558 11 R-BASICL 8,006 1,266,658 734 10,907 0.1582 12 TOU-E 40,962 5,874,650 4,073 10,057 0.1434 13 R-2 21,691 3,061,246 1,787 12,138 0.1411 14 R-3 19,872 2,533,398 1,441 13,790 0.1275 9 1,089 16 E-12 EPR-2,6 65,181 10,873,637 22,498 2,897 0.1668 17 ET-1 EPR-2,6 53,724 6,556,620 8,201 6,551 0.1220 18 ET-2 EPR-2,6 218,917 26,567,535 28,472 7,689 0.1214 26,171 4,360,622 2,348 11,146 0.1666 6,626 1,054,126 499 13,279 0.1591 3 5,333 0.1546 15 R-TECH 19 ECT-2 EPR-2,6 20 ECT-1R EPR-2,6 21 RCP 16 2,473 22 E-47 1,652 538,255 13,208,076 1,789,261,879 23 Green Power 24 Total Residential 0.1210 0.3258 97,052 1,080,665 12,222 0.1355 25 26 442 Commercial 27 E-20 38,048 5,046,706 413 92,126 0.1326 28 E-30 4,853 1,332,998 4,423 1,097 0.2747 1,437,059 240,339,915 99,667 14,419 0.1672 59 10,022 3 19,667 0.1699 31 E-32-S 2,595,288 355,338,177 16,949 153,123 0.1369 32 E-32-M 2,784,651 312,084,362 3,698 753,015 0.1121 33 E-32-L 1,979,562 202,199,305 540 3,665,856 0.1021 29 E-32-XS 30 E-32 XS D 34 E-32-TOU XS 3,608 573,078 165 21,867 0.1588 35 E-32-TOU S 27,899 3,774,133 132 211,356 0.1353 36 E-32-TOU M 61,813 6,542,990 60 1,030,217 0.1059 37 E-32-TOU L 202,989 18,339,533 36 5,638,583 0.0903 38 GS-Schools M 41,406 5,605,185 65 637,015 0.1354 39 GS-Schools L 34,043 4,124,444 31 1,098,161 0.1212 511,351 38,828,076 14 36,525,071 0.0759 28,009,805 8,206 28,018,011 3,403,959,483 3,057,171 3,407,016,654 1,214,627 0 1,214,627 23,060 0 23,067 0.1215 0.3726 0.1216 40 E-34 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: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES OF ELECTRICITY BY RATE SCHEDULES Year/Period of Report 2017/Q4 End of 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading. 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 E-35 1,085,096 66,837,654 22 49,322,545 0.0616 2 E-36 - M 4,940 597,916 7 705,714 0.1210 3 E-56 1,011 592,622 1 1,011,000 0.5862 4 E-221 330,109 35,077,216 1,241 266,002 0.1063 5 EPR-2 7,746 758,142 23 336,783 0.0979 6 EPR-6 466,391 53,384,883 1,041 448,022 0.1145 7 E-56R 163,457 14,216,983 24 6,810,708 0.0870 8 AG-1 M & L 409,678 19,187,197 134 3,057,299 0.0468 9,837 349,231 2 4,918,500 0.0355 10 AG-1 - XL 90,391 3,822,726 3 30,130,333 0.0423 11 AG-1- XL TOU 57,903 2,589,576 2 28,951,500 0.0447 12 E-47 20,216 8,908,999 9 AG-1 M & L TOU 13 Green Power 14 Total Commercial 0.4407 139,433 12,369,404 1,400,601,502 128,696 96,113 0.1132 58 17,802 73 795 0.3069 36,462 6,851,206 2,551 14,293 0.1879 15 16 442 Industrial and Irrigation 17 E-30 18 E-32-XS 19 E-32 XS D 20 E-32-S 99,571 13,255,170 795 125,247 0.1331 21 E-32-M 200,626 23,526,612 332 604,295 0.1173 22 E-32-L 469,520 42,119,421 127 3,697,008 0.0897 23 E-32-TOU XS 133 5,157 5 26,600 0.0388 24 E-32-TOU S 851 49,065 4 212,750 0.0577 25 E-32-TOU M 4,501 485,011 5 900,200 0.1078 26 E-32-TOU L 53,011 4,482,884 8 6,626,375 0.0846 27 E-34 125,249 9,413,559 6 20,874,833 0.0752 28 E-35 564,419 40,121,093 12 47,034,917 0.0711 6 13,451,833 0.0677 29 E-36 M 1,102 105,031 30 E-36 L 80,711 5,462,665 31 E-47 0.0953 574 158,897 32 E-221 10,924 1,127,744 106 103,057 0.1032 33 EPR-6 23,083 2,610,280 22 1,049,227 0.1131 151 13,586 540,301 27,542,325 1 540,301,000 74,769 13,952,766 5 14,953,800 0.1866 2,286,016 191,300,274 4,058 563,336 0.0837 28,009,805 8,206 28,018,011 3,403,959,483 3,057,171 3,407,016,654 1,214,627 0 1,214,627 23,060 0 23,067 0.1215 0.3726 0.1216 34 AG-1 M & L 0.2768 0.0900 35 AG-1 M & L TOU 36 AG-X XL 37 AG-X XL TOU 38 Special Contracts 39 Total Industrials & Irrigation 0.0510 40 41 42 43 TOTAL Billed Total Unbilled Rev.(See Instr. 6) TOTAL FERC FORM NO. 1 (ED. 12-95) Page 304.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES OF ELECTRICITY BY RATE SCHEDULES Year/Period of Report 2017/Q4 End of 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading. 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) 1 444 Public Street Lighting 144,144 22,652,672 1,054 136,759 0.1572 2 TotalPublic Street Lighting 144,144 22,652,672 1,054 136,759 0.1572 4 445 Other Public Authorities 2,165 143,156 154 14,058 0.0661 5 Total Other Public Authorities 2,165 143,156 154 14,058 0.0661 3 6 7 Unbilled MWh & Revenue 8 Residential Unbilled 9 Commercial Unbilled 10 Ind & Irrig. Unbilled 11 Public Str Lighting Unbilled -941 3,190,948 -3.3910 10,982 215,599 0.0196 -1,815 -346,563 0.1909 -20 -2,813 0.1407 8,206 3,057,171 0.3726 28,009,805 8,206 28,018,011 3,403,959,483 3,057,171 3,407,016,654 12 Other Public Auth Unbilled 13 Total Unbilled MWh & Revenue 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) Page 304.2 1,214,627 0 1,214,627 23,060 0 23,067 0.1215 0.3726 0.1216 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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) 0.044 0.044 0.044 (a) 1 Aguila Irrigation District Statistical Classification (b) RQ 2 Buckeye Irrigation District RQ 86306 0.053 0.053 0.053 3 City of Williams RQ MRT Vol 1 5.758 6.090 4.762 4 Electrical District No. 6 RQ 86307 0.000 5 Electrical District No. 7 RQ 86304 0.040 0.040 0.040 6 Electrical District No. 8 RQ 86310 1.397 1.397 1.397 7 Harquahala Valley Irrigation District RQ 86309 0.237 0.237 0.237 8 Maricopa County Municipal Water Conserv RQ 86058 0.046 0.046 0.045 9 McMullen Valley Irrigation District Line No. Name of Company or Public Authority (Footnote Affiliations) RQ 86311 0.223 0.223 0.223 10 Roosevelt Irrigation District RQ 86305 0.144 0.144 0.144 11 Tonopah Irrigation District RQ 86312 0.048 0.048 0.048 12 Town of Wickenburg RQ 85726 0.086 0.086 0.086 13 Citigroup Energy Inc. IF MRT Vol 3 14 Constellation New Energy Inc. IF 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 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 Direct Energy Business LLC Statistical Classification (b) IF 2 Freeport-McMoRan Copper & Gold Energy C IF FERC Rate Schedule or Tariff Number (c) WSPP Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) WSPP 3 Morgan Stanley Capital Group Inc. IF MRT Vol 3 4 NextEra Energy Power Marketing LLC IF WSPP 5 Noble Americas Energy Solutions, LLC IF WSPP 6 Arizona Electric Power Cooperative Inc SF WSPP 7 Bonneville Power Administration SF WSPP 8 BP Energy Company SF WSPP 9 Brookfield Energy Marketing LP SF WSPP 10 California Independent System Operator SF MRT Vol 3 11 Cargill Power Markets LLC SF WSPP 12 Central Arizona Water Conservation Dist SF WSPP 13 Citigroup Energy Inc. SF MRT Vol 3 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 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, LLC. 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 Department 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 Company of Colorado SF WSPP 5 Public Service Company 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 MRT Vol 5 14 TransAlta Energy Marketing, U.S., 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 TransCanada Energy Sales, LTD Statistical Classification (b) SF FERC Rate Schedule or Tariff Number (c) WSPP 2 Tucson Electric Power SF WSPP 3 Twin Eagle Resource Management, LLC SF WSPP 4 UNS Electric SF WSPP 5 Various counterparties-prior yr adjusts SF WSPP 6 Westar Energy, Inc. SF WSPP 7 Arizona Electric Power Cooperative OS WSPP 8 BP Energy Company OS WSPP 9 California Independent System Operator OS MRT Vol 3 10 Cargill Power Markets, LLC OS WSPP 11 EDF Trading North America LLC OS WSPP 12 Imperial Irrigation District OS WSPP 13 Macquarie Energy LLC OS WSPP 14 Nevada Power Company OS 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 310.4 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SALES FOR RESALE (Account 447) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. FERC Rate Schedule or Tariff Number (c) MRT Vol 3 1 PacifiCorp Statistical Classification (b) OS 2 PacifiCorp Supplemental Coal OS RS # 183 3 PacifiCorp Supplemental Other OS RS # 183 4 Tenaska Power Services Company OS WSPP 5 Tucson Electric Power Co. OS WSPP 6 Southwest Reserve Sharing Group OS SRSG1 Line No. Name of Company or Public Authority (Footnote Affiliations) (a) 7 Transmission Losses AD 8 Change in estimate/other AD Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) Average Monthly Billing Demand (MW) (d) 9 10 11 12 13 14 Subtotal RQ 0 0 0 Subtotal non-RQ 0 0 0 Total 0 0 0 FERC FORM NO. 1 (ED. 12-90) Page 310.5 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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) 379 Demand Charges ($) (h) 5,515 REVENUE Energy Charges ($) (i) 14,211 Other Charges ($) (j) 354,743 Line No. Total ($) (h+i+j) (k) 374,469 1 2 456 6,554 16,202 244,884 267,640 37,796 1,006,451 793,728 39,600 1,839,779 3 29,596 29,596 4 360 4,912 11,652 380,345 396,909 5 12,335 170,911 411,354 1,873,875 2,456,140 6 2,088 29,203 71,834 779,135 880,172 7 394 5,693 14,549 382,715 402,957 8 1,531 27,487 53,677 889,368 970,532 9 1,245 18,103 46,702 406,531 471,336 10 414 6,027 15,531 176,101 197,659 11 165,205 166,906 1,701 12 13 2,066 126,919 126,919 56,998 1,282,557 1,449,440 5,722,098 8,454,095 2,835,161 0 105,018,133 3,623,506 108,641,639 2,892,159 1,282,557 106,467,573 9,345,604 117,095,734 FERC FORM NO. 1 (ED. 12-90) Page 311 14 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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) 1 Other Charges ($) (j) 25 Line No. Total ($) (h+i+j) (k) 25 1 2 170 177,945 177,945 339,845 21,206,328 21,206,328 3 2,024 108,962 108,962 4 98 46,664 46,664 5 200,626 3,721,495 3,721,495 6 33,600 1,001,000 1,001,000 7 41,255 979,209 979,209 8 400 12,800 12,800 9 100,900 3,488,938 3,488,938 10 26,656 661,999 661,999 11 29,620 388,300 388,300 12 29,647 834,490 834,490 13 1,200 38,600 38,600 14 56,998 1,282,557 1,449,440 5,722,098 8,454,095 2,835,161 0 105,018,133 3,623,506 108,641,639 2,892,159 1,282,557 106,467,573 9,345,604 117,095,734 FERC FORM NO. 1 (ED. 12-90) Page 311.1 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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) 52,617 Other Charges ($) (j) 1,610,948 Line No. Total ($) (h+i+j) (k) 1,610,948 1 12,825 291,945 291,945 2 92,766 2,299,579 2,299,579 3 64 492 492 4 21 1,344 1,344 5 104,725 2,782,697 2,782,697 6 28,400 879,600 879,600 7 11,530 347,113 347,113 8 181,664 9 6,400 181,664 42 2,436 2,436 10 3,400 68,250 68,250 11 16,614 511,568 511,568 12 141,766 3,696,616 3,696,616 13 275 2,600 2,600 14 56,998 1,282,557 1,449,440 5,722,098 8,454,095 2,835,161 0 105,018,133 3,623,506 108,641,639 2,892,159 1,282,557 106,467,573 9,345,604 117,095,734 FERC FORM NO. 1 (ED. 12-90) Page 311.2 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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) 1 12,000 279,600 279,600 91,658 2,179,199 2,179,199 2 5,176 134,884 134,884 3 94,595 2,115,967 2,115,967 4 3,325 92,864 92,864 5 3,600 100,100 100,100 6 164,417 4,457,963 4,457,963 7 4,350 116,680 116,680 8 14,110 368,277 368,277 9 18,200 473,700 473,700 10 800 24,800 24,800 11 9,131 245,822 39,649 1,676,954 57,962 1,649,522 540,335 245,822 12 2,217,289 13 1,649,522 14 56,998 1,282,557 1,449,440 5,722,098 8,454,095 2,835,161 0 105,018,133 3,623,506 108,641,639 2,892,159 1,282,557 106,467,573 9,345,604 117,095,734 FERC FORM NO. 1 (ED. 12-90) Page 311.3 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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) 4,400 130,300 130,300 1 83,920 2,221,676 2,221,676 2 34,000 793,230 793,230 3 4 119,125 2,841,552 2,841,552 175 7,700 7,700 6 260 11,550 11,550 7 60 2,100 2,100 8 674,778 37,002,489 37,002,489 9 5 70 1,960 1,960 10 400 15,400 15,400 11 400 14,660 14,660 12 300 21,000 21,000 13 200 8,600 8,600 14 56,998 1,282,557 1,449,440 5,722,098 8,454,095 2,835,161 0 105,018,133 3,623,506 108,641,639 2,892,159 1,282,557 106,467,573 9,345,604 117,095,734 FERC FORM NO. 1 (ED. 12-90) Page 311.4 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission SALES FOR RESALE (Account 447) (Continued) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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) 340 Other Charges ($) (j) 13,700 Line No. Total ($) (h+i+j) (k) 13,700 1 13,865 359,902 359,902 2 98,968 2,167,526 2,167,526 3 245 8,330 8,330 4 200 9,600 4,929 120,744 9,600 5 120,744 6 7,773,586 7,773,586 7 -4,811,159 -4,811,159 8 9 10 11 12 13 14 56,998 1,282,557 1,449,440 5,722,098 8,454,095 2,835,161 0 105,018,133 3,623,506 108,641,639 2,892,159 1,282,557 106,467,573 9,345,604 117,095,734 FERC FORM NO. 1 (ED. 12-90) Page 311.5 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission ELECTRIC OPERATION AND MAINTENANCE EXPENSES If the amount for previous year is not derived from previously reported figures, explain in footnote. Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 Account (a) 1. POWER PRODUCTION EXPENSES A. Steam Power Generation Operation (500) Operation Supervision and Engineering (501) Fuel (502) Steam Expenses (503) Steam from Other Sources (Less) (504) Steam Transferred-Cr. (505) Electric Expenses (506) Miscellaneous Steam Power Expenses (507) Rents (509) Allowances TOTAL Operation (Enter Total of Lines 4 thru 12) Maintenance (510) Maintenance Supervision and Engineering (511) Maintenance of Structures (512) Maintenance of Boiler Plant (513) Maintenance of Electric Plant (514) Maintenance of Miscellaneous Steam Plant TOTAL Maintenance (Enter Total of Lines 15 thru 19) TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) B. Nuclear Power Generation Operation (517) Operation Supervision and Engineering (518) Fuel (519) Coolants and Water (520) Steam Expenses (521) Steam from Other Sources (Less) (522) Steam Transferred-Cr. (523) Electric Expenses (524) Miscellaneous Nuclear Power Expenses (525) Rents TOTAL Operation (Enter Total of lines 24 thru 32) Maintenance (528) Maintenance Supervision and Engineering (529) Maintenance of Structures (530) Maintenance of Reactor Plant Equipment (531) Maintenance of Electric Plant (532) Maintenance of Miscellaneous Nuclear Plant TOTAL Maintenance (Enter Total of lines 35 thru 39) TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) C. Hydraulic Power Generation Operation (535) Operation Supervision and Engineering (536) Water for Power (537) Hydraulic Expenses (538) Electric Expenses (539) Miscellaneous Hydraulic Power Generation Expenses (540) Rents TOTAL Operation (Enter Total of Lines 44 thru 49) C. Hydraulic Power Generation (Continued) Maintenance (541) Mainentance Supervision and Engineering (542) Maintenance of Structures (543) Maintenance of Reservoirs, Dams, and Waterways (544) Maintenance of Electric Plant (545) Maintenance of Miscellaneous Hydraulic Plant TOTAL Maintenance (Enter Total of lines 53 thru 57) TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) FERC FORM NO. 1 (ED. 12-93) Page 320 Amount for Current Year (b) Amount for Previous Year (c) 14,709,137 241,173,791 23,077,523 14,465,641 243,789,424 18,221,926 5,029,036 20,211,697 1,381,616 627,318 306,210,118 4,862,010 14,696,564 1,316,174 2,834,992 300,186,731 5,309,655 10,640,342 44,135,811 14,932,067 6,232,820 81,250,695 387,460,813 7,341,999 9,242,420 55,065,542 15,837,331 10,982,099 98,469,391 398,656,122 24,587,889 74,603,556 13,628,445 11,125,054 26,232,569 79,688,967 12,934,179 11,694,791 9,083,767 42,637,624 22,759,215 198,425,550 8,349,317 40,221,101 22,757,675 201,878,599 4,919,890 2,082,947 15,532,898 12,172,995 3,720,009 38,428,739 236,854,289 6,230,976 2,508,512 14,303,492 14,623,970 3,455,428 41,122,378 243,000,977 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) If the amount for previous year is not derived from previously reported figures, explain in footnote. Line No. 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 Account 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 4,405,629 350,721,503 10,680,955 53,722,269 927,354 420,457,710 3,450,084 390,682,689 8,678,397 38,968,223 1,020,933 442,800,326 242,274 6,464,420 27,233,891 1,851,593 35,792,178 456,249,888 256,146 5,129,533 28,709,421 1,716,719 35,811,819 478,612,145 333,276,238 -3,929,340 3,663,101 333,009,999 1,413,574,989 364,921,525 -3,400,047 4,999,576 366,521,054 1,486,790,298 1,500,397 2,349,519 3,347,335 2,935,219 866,120 2,352,913 1,299,877 81,453 76,516 2,972,533 1,316,391 3,698,715 85,777 28,519,716 12,638,751 7,719,039 69,410,752 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 64,243,877 414,591 1,335,014 586,534 1,235,089 158,535 174,891 6,008,560 5,046,802 295,511 34,474 13,293,487 82,704,239 5,320,761 9,602,074 394,796 84,098 17,398,243 81,642,120 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Year/Period of Report 2017/Q4 End of If the amount for previous year is not derived from previously reported figures, explain in footnote. Line No. 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 Account Amount for Current Year (b) (a) 3. REGIONAL MARKET EXPENSES Operation (575.1) Operation Supervision (575.2) Day-Ahead and Real-Time Market Facilitation (575.3) Transmission Rights Market Facilitation (575.4) Capacity Market Facilitation (575.5) Ancillary Services Market Facilitation (575.6) Market Monitoring and Compliance (575.7) Market Facilitation, Monitoring and Compliance Services (575.8) Rents Total Operation (Lines 115 thru 122) Maintenance (576.1) Maintenance of Structures and Improvements (576.2) Maintenance of Computer Hardware (576.3) Maintenance of Computer Software (576.4) Maintenance of Communication Equipment (576.5) Maintenance of Miscellaneous Market Operation Plant Total Maintenance (Lines 125 thru 129) TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 4. DISTRIBUTION EXPENSES Operation (580) Operation Supervision and Engineering (581) Load Dispatching (582) Station Expenses (583) Overhead Line Expenses (584) Underground Line Expenses (585) Street Lighting and Signal System Expenses (586) Meter Expenses (587) Customer Installations Expenses (588) Miscellaneous Expenses (589) Rents TOTAL Operation (Enter Total of lines 134 thru 143) Maintenance (590) Maintenance Supervision and Engineering (591) Maintenance of Structures (592) Maintenance of Station Equipment (593) Maintenance of Overhead Lines (594) Maintenance of Underground Lines (595) Maintenance of Line Transformers (596) Maintenance of Street Lighting and Signal Systems (597) Maintenance of Meters (598) Maintenance of Miscellaneous Distribution Plant TOTAL Maintenance (Total of lines 146 thru 154) TOTAL Distribution Expenses (Total of lines 144 and 155) 5. CUSTOMER ACCOUNTS EXPENSES Operation (901) Supervision (902) Meter Reading Expenses (903) Customer Records and Collection Expenses (904) Uncollectible Accounts (905) Miscellaneous Customer Accounts Expenses TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) FERC FORM NO. 1 (ED. 12-93) Page 322 Amount for Previous Year (c) 5,435,604 2,006,991 1,374,015 1,826,146 1,491,489 3,528 9,003,314 7,947 52,553,863 891,493 74,594,390 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 1,752,609 253,069 3,147,484 16,965,068 5,517,624 3,050,746 867,483 1,887,558 285,225 3,733,248 18,832,297 7,164,127 2,918,319 440,137 3,135,451 34,689,534 109,283,924 3,909,178 39,170,089 104,811,542 2,345,495 2,332,998 47,181,206 6,836,014 345,196 59,040,909 1,933,983 2,497,722 45,567,772 4,025,012 232,563 54,257,052 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Year/Period of Report 2017/Q4 End of If the amount for previous year is not derived from previously reported figures, explain in footnote. Line No. 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180 181 182 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 Account (a) 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES Operation (907) Supervision (908) Customer Assistance Expenses (909) Informational and Instructional Expenses (910) Miscellaneous Customer Service and Informational Expenses TOTAL Customer Service and Information Expenses (Total 167 thru 170) 7. SALES EXPENSES Operation (911) Supervision (912) Demonstrating and Selling Expenses (913) Advertising Expenses (916) Miscellaneous Sales Expenses TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 8. ADMINISTRATIVE AND GENERAL EXPENSES Operation (920) Administrative and General Salaries (921) Office Supplies and Expenses (Less) (922) Administrative Expenses Transferred-Credit (923) Outside Services Employed (924) Property Insurance (925) Injuries and Damages (926) Employee Pensions and Benefits (927) Franchise Requirements (928) Regulatory Commission Expenses (929) (Less) Duplicate Charges-Cr. (930.1) General Advertising Expenses (930.2) Miscellaneous General Expenses (931) Rents TOTAL Operation (Enter Total of lines 181 thru 193) Maintenance (935) Maintenance of General Plant TOTAL Administrative & General Expenses (Total of lines 194 and 196) TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) FERC FORM NO. 1 (ED. 12-93) Page 323 Amount for Previous Year (c) Amount for Current Year (b) 273,407 52,967,104 605,972 563,783 54,410,266 252,608 57,603,630 324,521 842,735 59,023,494 16 8,407,927 7,336,790 5,463,863 13,871,806 5,052,579 12,389,369 99,241,248 10,161,144 21,226,138 40,968,557 2,474,048 9,338,729 59,524,852 91,137,415 8,978,950 21,102,430 38,976,113 5,276,432 8,736,209 64,872,042 20,683,666 20,365,123 3,910,088 -59,565,557 5,705,530 171,216,167 3,641,978 -51,847,022 5,858,387 174,893,197 12,101,097 183,317,264 1,916,203,397 11,879,833 186,773,030 1,985,686,905 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 2 Dynegy Arlington - Tolling Agreement RQ 321,164 3 Gila River Power - Tolling Agreement RQ 136,408 4 Salt River Project Eastern Area RQ 10,795 5 Citigroup Energy Inc. IF MRT Vol 3 N/A N/A N/A 6 Constellation New Energy Inc. IF WSPP N/A N/A N/A 7 Direct Energy Business LLC IF WSPP N/A N/A N/A 8 Freeport-McMoRan Copper & Gold EnergyC IF WSPP N/A N/A N/A 9 NextEra Energy Power Marketing LLC IF WSPP N/A N/A N/A 10 Noble Americas Energy Solutions, LLC IF WSPP N/A N/A N/A 11 AG-1 Contracts SF N/A N/A N/A 12 Arizona Electric Power Cooperative Inc SF N/A N/A N/A 13 Arlington Valley, LLC SF N/A N/A N/A 14 Bonneville Power Administration SF N/A N/A N/A WSPP WSPP Total FERC FORM NO. 1 (ED. 12-90) Page 326 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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) 1 BP Energy Company SF 2 Brookfield Energy Marketing LP 3 California Independent System Operator 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) WSPP N/A N/A N/A SF WSPP N/A N/A N/A SF MRT Vol 3 N/A N/A N/A 4 California Independent System Operator SF MRT Vol 3 N/A N/A N/A 5 Cargill Power Markets LLC SF WSPP N/A N/A N/A 6 Central Arizona Water Conservation Dit SF WSPP N/A N/A N/A 7 EDF Trading North America LLC SF WSPP N/A N/A N/A 8 El Paso Electric SF WSPP N/A N/A N/A 9 Energy Keepers, Inc. SF WSPP N/A N/A N/A 10 Exelon Generation Company, LLC SF WSPP N/A N/A N/A 11 Gila River Power LLC SF N/A N/A N/A 12 Iberdrola Renewables, LLC. SF WSPP N/A N/A N/A 13 Idaho Power Company SF WSPP N/A N/A N/A 14 Imperial Irrigation District SF WSPP N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.1 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 Department of Water & Powr SF WSPP N/A N/A N/A 2 Macquarie Energy LLC SF WSPP N/A N/A N/A 3 Morgan Stanley Capital Group Inc. SF MRT Vol 3 N/A N/A N/A 4 Nevada Power Company SF WSPP N/A N/A N/A 5 PacifiCorp SF MRT Vol 3 N/A N/A N/A 6 Powerex Corp. SF WSPP N/A N/A N/A 7 Public Service Company of Colorado SF WSPP N/A N/A N/A 8 Public Service Company of New Mexico SF WSPP N/A N/A N/A 9 Rainbow Energy Marketing Corporation SF WSPP N/A N/A N/A 10 Salt River Project SF WSPP N/A N/A N/A 11 Seattle City Light SF WSPP N/A N/A N/A 12 Sempra Gas & Power Marketing, LLC SF WSPP N/A N/A N/A 13 Shell Energy North America (US), L.P. SF WSPP 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 WSPP N/A N/A N/A 2 Tenaska Power Services Company SF WSPP N/A N/A N/A 3 TransAlta Energy Marketing, U.S., Inc. SF WSPP N/A N/A N/A 4 Tucson Electric Power SF WSPP N/A N/A N/A 5 Twin Eagle Resource Management, LLC SF WSPP N/A N/A N/A 6 UNS Electric SF WSPP N/A N/A N/A 7 Various counterparties - prior yrs adt SF N/A N/A N/A 8 Westar Energy, Inc. SF WSPP N/A N/A N/A 9 WAPA Co River Storage Project SF WSPP N/A N/A N/A 10 WAPA Desert Southwest Region SF WSPP N/A N/A N/A 11 Aragonne Wind, LLC LU N/A N/A N/A 12 Arizona Solar One, LLC LU N/A N/A N/A 13 CE Turbo LLC LU N/A N/A N/A 14 Desert Sky Solar 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 Glendale Energy LLC LU N/A N/A N/A 2 High Lonesome Mesa, LLC LU N/A N/A N/A 3 Novo BioPower LLC LU N/A N/A N/A 4 Perrin Ranch Wind LLC LU N/A N/A N/A 5 RE Ajo 1 LLC LU N/A N/A N/A 6 RE Bagdad Solar 1 LLC LU N/A N/A N/A 7 RE Gillespie 1, LLC LU N/A N/A N/A 8 SunE AZ 1 LLC LU N/A N/A N/A 9 SunE AZ 2 LLC LU N/A N/A N/A N/A N/A N/A 10 Waste Management Renewable Energy, LLC LU 11 Aguila Irrigation District EX 141 12 Buckeye Water Conservation & Drainage EX 155 13 Electric District #6 EX 126 14 Electric District #7 EX 128 Total FERC FORM NO. 1 (ED. 12-90) Page 326.4 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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) 1 Electric District #8 EX 140 2 Harquahala Valley Power District EX 153 3 Maricopa City Municipal Water Conserv EX 168 4 McMullen Valley Water Conservation EX 142 5 PacifiCorp Exchange EX 182 6 Roosevelt Irrigation District EX 158 7 Tonopah Irrigation District EX 143 8 Banked Energy 9 Co Generation Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) N/A N/A N/A OS N/A N/A N/A 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 MRT Vol 3 N/A N/A N/A 12 San Diego Gas & Electric Co OS WSPP N/A N/A N/A 13 TransCanada Energy Sales, LTD OS WSPP N/A N/A N/A 14 Tri-State Generation and Transmission. OS WSPP N/A N/A N/A Total FERC FORM NO. 1 (ED. 12-90) Page 326.5 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission PURCHASED POWER (Account 555) (Including power exchanges) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 Westar Energy, Inc. Statistical Classification (b) OS FERC Rate Schedule or Tariff Number (c) WSPP Average Monthly Billing Demand (MW) (d) Actual Demand (MW) Average Average Monthly NCP Demand Monthly CP Demand (e) (f) N/A N/A N/A 2 Net Inadvertent OS N/A N/A N/A 3 Options and Hedges OS N/A N/A N/A 4 Power Supply Adjustor OS N/A N/A N/A 5 SFAS 133 OS N/A N/A N/A 6 Purchase Power- Variable Energy OS N/A N/A N/A 7 Prior Year Adjustment AD N/A N/A N/A 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) 05/09/2018 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) 19 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) 2,049 Total (j+k+l) of Settlement ($) (m) Line No. 2,049 1 2 1,926,982 59,089,200 2,616,997 61,706,197 682,041 15,757,945 1,949,501 17,707,446 3 5,654,012 7,454,012 4 339,845 20,730,545 20,730,545 5 206,564 7,610,144 7,610,144 6 7 174,635 1,800,000 73,937 2,506,532 2,506,532 387,027 13,320,485 13,320,485 8 226,208 6,977,416 6,977,416 9 93,036 3,109,220 3,109,220 10 11 1,979 83,308 83,308 12 477,330 14 13 13,614 7,825,768 477,330 633,695 FERC FORM NO. 1 (ED. 12-90) 639,817 76,647,145 Page 327 297,861,527 -41,232,434 333,276,238 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) 22,125 942,999 1,200 48,200 Total (j+k+l) of Settlement ($) (m) 942,999 13,446,136 Line No. 1 48,200 2 13,446,136 3 4 80,552 3,274,769 3,274,769 30,842 630,969 630,969 5 240 9,600 9,600 6 62,038 4,932,510 4,932,510 7 2,427 80,897 80,897 8 1,600 61,600 61,600 9 16,900 470,740 470,740 10 11 800 51,000 51,000 12 11,783 93,269 93,269 13 20 2,293 2,293 14 7,825,768 633,695 FERC FORM NO. 1 (ED. 12-90) 639,817 76,647,145 Page 327.1 297,861,527 -41,232,434 333,276,238 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) 9,645 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) 743,570 Total (j+k+l) of Settlement ($) (m) 743,570 Line No. 1 3,600 193,976 193,976 2 26,198 1,997,897 1,997,897 3 17,420 713,897 713,897 4 158,479 5,552,648 5,552,648 5 30,092 2,526,004 2,526,004 6 7 1,650 49,050 49,050 4,150 157,343 157,343 8 9 400 17,000 17,000 28,824 1,819,225 1,819,225 10 735 54,950 54,950 11 1,350 112,600 112,600 12 3,680 176,962 176,962 13 97,170 14 1,570 7,825,768 97,170 633,695 FERC FORM NO. 1 (ED. 12-90) 639,817 76,647,145 Page 327.2 297,861,527 -41,232,434 333,276,238 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) Total (j+k+l) of Settlement ($) (m) Line No. 237,655 7,293,893 7,293,893 1 7,850 163,208 163,208 2 10,710 529,855 529,855 3 5,938 163,161 163,161 4 219 5,211 5,211 5 2,902 194,408 194,408 6 7,171 438,100 438,100 8 9 7 100 4,000 4,000 75 1,118,747 1,118,747 10 272,990 16,380,630 16,380,630 11 723,966 96,492,843 96,492,843 12 73,081 5,288,161 5,288,161 13 40,069 3,448,739 3,448,739 14 7,825,768 633,695 FERC FORM NO. 1 (ED. 12-90) 639,817 76,647,145 Page 327.3 297,861,527 -41,232,434 333,276,238 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) Total (j+k+l) of Settlement ($) (m) Line No. 1 19,447 1,715,932 1,715,932 294,045 17,479,191 17,479,191 2 77,261 7,596,731 7,596,731 3 234,710 19,774,318 19,774,318 4 8,489 1,209,852 1,209,852 5 34,132 5,472,725 5,472,725 6 42,481 4,052,730 4,052,730 7 25,352 3,063,991 3,063,991 8 31,729 3,679,295 3,679,295 9 1,638,628 1,638,628 19,163 7,825,768 10 8,372 8,134 11 4,817 4,784 12 723 534 13 4,375 4,756 14 633,695 639,817 FERC FORM NO. 1 (ED. 12-90) 76,647,145 Page 327.4 297,861,527 -41,232,434 333,276,238 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) 13,455 12,261 Demand Charges ($) (j) COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) Total (j+k+l) of Settlement ($) (m) Line No. 1 9,479 11,388 2 5,021 6,051 3 4,503 9,373 4 571,397 571,685 5,620 4,952 5,933 5,899 -1,052,783 -1,052,783 5 6 7 280,532 32 927 1,012,376 16,283,851 280,532 8 927 9 29,021,771 11 10 12,737,920 444 40,404 40,404 12 800 56,400 56,400 13 280 23,800 23,800 14 7,825,768 633,695 FERC FORM NO. 1 (ED. 12-90) 639,817 76,647,145 Page 327.5 297,861,527 -41,232,434 333,276,238 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission PURCHASED POWER(Account 555) (Continued) (Including power exchanges) Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data. MegaWatt Hours Purchased (g) POWER EXCHANGES MegaWatt Hours MegaWatt Hours Received Delivered (h) (i) Demand Charges ($) (j) 340 COST/SETTLEMENT OF POWER Energy Charges Other Charges ($) ($) (l) (k) 22,400 Total (j+k+l) of Settlement ($) (m) 22,400 Line No. 1 2 -2,246 9,969,509 3 -61,082,939 -61,082,939 4 -4,486,506 -4,486,506 5 1,221 1,221 6 -16,664,805 -16,664,805 9,969,509 7 8 9 10 11 12 13 14 7,825,768 633,695 FERC FORM NO. 1 (ED. 12-90) 639,817 76,647,145 Page 327.6 297,861,527 -41,232,434 333,276,238 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 326.5 Line No.: 11 Column: a Energy Imbalance Market Schedule Page: 326.6 Line No.: 7 Column: a Change in Estimate / Various counterparties FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of 1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) 1 Arizona Public Service Company Arizona Public Service Company Arizona Public Service Company FNS 2 Arizona Public Service Company Arizona Public Service Company Arizona Public Service Company FNS 3 Arizona Public Service Company Arizona Public Service Company Arizona Public Service Company FNS 4 Arizona Public Service Company Various Arizona Public Service Company FNS 5 Ajo Improvement Company Not Available Not Available FNO 6 Central Arizona Water Conservation District Not Available Not Available FNO 7 Navajo Tribal Utility Authority Tucson Electric Power Navajo Tribal Utility Authority FNO 8 Navopache Electric Cooperative, Inc. Not Available Not Available FNO 9 Southwest Transmission Cooperative Not Available Not Available FNO 10 Avangrid Renewables, LLC Not Available Not Available LFP 11 Broadview Energy JN LLC Not Available Not Available LFP 12 Broadview Energy KW- LLC Not Available Not Available LFP 13 CSE Operating 1, LLC Not Available Not Available LFP 14 Electrical District 3 Not Available Not Available LFP 15 NOVO BioPower LLC Not Available Not Available LFP 16 PacifiCorp Not Available Not Available LFP 17 Public Service Company of New Mexico Not Available Not Available LFP 18 Salt River Project (OATT General Service) Not Available Not Available LFP 19 Trico Electric Cooperative Inc. Not Available Not Available LFP 20 Tucson Electric Power Company Not Available Not Available LFP 21 Arizona Public Service Company Not Available Not Available SFP 22 Avangrid Renewables, LLC Not Available Not Available SFP 23 Broadview Energy KW- LLC Not Available Not Available SFP 24 City of Anaheim Not Available Not Available SFP 25 Public Service Company of New Mexico Not Available Not Available SFP 26 Broadview JN, LLC Not Available Not Available SFP 27 CSE Operating 1, LLC Not Available Not Available SFP 28 Salt River Project (OATT General Service) Not Available Not Available SFP 29 4C Acquisition, LLC Not Available Not Available SFP 30 Arizona Electric Power Cooperative, Inc Not Available Not Available SFP 31 Arizona Public Service Company Not Available Not Available SFP 32 Avangrid Renewables, LLC Not Available Not Available SFP 33 Cargill Power Markets, LLC Not Available Not Available SFP 34 City of Anaheim Not Available Not Available SFP TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of 1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. 1 Rainbow Energy Marketing Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Not Available Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) Not Available SFP 2 Salt River Project (OATT General Service) Not Available Not Available SFP 3 Shell Energy North America LP Not Available Not Available SFP 4 Tenaska Power Services Co. Not Available Not Available SFP 5 Tucson Electric Power Company Not Available Not Available SFP 6 4C Acquisition, LLC Not Available Not Available SFP 7 Arizona Electric Power Cooperative, Inc Not Available Not Available SFP 8 Arizona Public Service Company Not Available Not Available SFP 9 Avangrid Renewables, LLC Not Available Not Available SFP 10 BP Energy Company Not Available Not Available SFP 11 Broadview Energy KW- LLC Not Available Not Available SFP 12 Brookfield Energy Marketing LP Not Available Not Available SFP 13 Cargill Power Markets, LLC Not Available Not Available SFP 14 City of Anaheim Not Available Not Available SFP 15 CXA Sundevil Power I, Inc. Not Available Not Available SFP 16 EDF Trading North America, LLC Not Available Not Available SFP 17 Guzman Power Markets LLC Not Available Not Available SFP 18 Guzman Renewable Energy Partners Not Available Not Available SFP 19 Macquarie Energy LLC Not Available Not Available SFP 20 Mag Energy Solutions, Inc Not Available Not Available SFP 21 Nevada Power Company Not Available Not Available SFP 22 PacifiCorp Not Available Not Available SFP 23 Public Service Company of New Mexico Not Available Not Available SFP 24 Rainbow Energy Marketing Not Available Not Available SFP 25 Salt River Project (OATT General Service) Not Available Not Available SFP 26 Sempra Gas & Power Marketing, LLC Not Available Not Available SFP 27 Sempra Generation Not Available Not Available SFP 28 Shell Energy North America LP Not Available Not Available SFP 29 Southern California Edison Company Not Available Not Available SFP 30 Talen Energy Marketing LLC Not Available Not Available SFP 31 Tenaska Power Services Co. Not Available Not Available SFP 32 TransAlta Energy Marketing U.S. Inc. Not Available Not Available SFP 33 Tucson Electric Power Company Not Available Not Available SFP 34 4C Acquisition, LLC Not Available Not Available NF TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of 1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) 1 Arizona Public Service Company Not Available Not Available NF 2 Avangrid Renewables, LLC Not Available Not Available NF 3 Broadview Energy JN LLC Not Available Not Available NF 4 Broadview Energy KW- LLC Not Available Not Available NF 5 Cargill Power Markets, LLC Not Available Not Available NF 6 City of Anaheim Not Available Not Available NF 7 Shell Energy North America LP Not Available Not Available NF 8 4C Acquisition, LLC Not Available Not Available NF 9 Arizona Electric Power Cooperative, Inc Not Available Not Available NF 10 Arizona Public Service Company Not Available Not Available NF 11 Avangrid Renewables, LLC Not Available Not Available NF 12 Broadview Energy JN LLC Not Available Not Available NF 13 Broadview Energy KW- LLC Not Available Not Available NF 14 Brookfield Energy Marketing LP Not Available Not Available NF 15 Cargill Power Markets, LLC Not Available Not Available NF 16 City of Anaheim Not Available Not Available NF 17 EDF Trading North America, LLC Not Available Not Available NF 18 El Paso Electric Company Not Available Not Available NF 19 Guzman Power Markets LLC Not Available Not Available NF 20 Guzman Renewable Energy Partners Not Available Not Available NF 21 Imperial Irrigation District Not Available Not Available NF 22 Imperial Irrigation District Marketing Not Available Not Available NF 23 Macquarie Energy LLC Not Available Not Available NF 24 Mag Energy Solutions, Inc Not Available Not Available NF 25 Morgan Stanley Not Available Not Available NF 26 Nevada Power Company Not Available Not Available NF 27 PacifiCorp Not Available Not Available NF 28 Powerex Not Available Not Available NF 29 Public Service Company of New Mexico Not Available Not Available NF 30 Salt River Project (OATT General Service) Not Available Not Available NF 31 Sempra Gas & Power Marketing, LLC Not Available Not Available NF 32 Sempra Generation Not Available Not Available NF 33 Shell Energy North America LP Not Available Not Available NF 34 Southern California Edison Company Not Available Not Available NF TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328.2 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of 1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. Payment By (Company of Public Authority) (Footnote Affiliation) (a) Line No. 1 Tenaska Power Services Co. Energy Received From (Company of Public Authority) (Footnote Affiliation) (b) Not Available Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c) Statistical Classification (d) Not Available NF 2 TransAlta Energy Marketing U.S. Inc. Not Available Not Available NF 3 Tri-State Generation and Transmission Not Available Not Available NF 4 Tucson Electric Power Company Not Available Not Available NF 5 Westar Energy Inc. Not Available Not Available NF 6 WestConnect Not Available Not Available NF 7 Yuma Cogeneration Associates Not Available Not Available NF 8 Arizona Public Service Company Not Available Not Available OLF 9 PacifiCorp Not Available Not Available OLF 10 Public Service Company of NM Not Available Not Available OLF 11 Yuma Cogeneration Associates Yuma Cogeneration Assoc. San Diego Gas and Elect. OLF 12 Imperial Irrigation District Not Available Not Available OS 13 Luke AFB Main Field DOE WAPA Lower Luke Air Force Base OS 14 Marine Corps. Air Station DOE WAPA Lower Marine Corps Air Station OS 15 NOVO BioPower LLC Not Available Not Available OS 16 Salt River Project (Schedule F) Not Available Not Available OS 17 Salt River Project (Schedule Q) Pinnacle Peak Ocotillo 230 OS 18 Unit B Irrigation and Drainage District Not Available Not Available OS 19 Yuma Mesa Irrigation and Drainage District DOE WAPA Lower Yuma-Mesa Irrigation Dist OS 20 Other Not Available Not Available AD 21 22 23 24 25 26 27 28 29 30 31 32 33 34 TOTAL FERC FORM NO. 1 (ED. 12-90) Page 328.3 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company 5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered. FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other Designation) (g) Billing Demand (MW) (h) TRANSFER OF ENERGY MegaWatt Hours Received (i) 964,268 964,268 30,254,129 30,254,129 Line No. OATT Various Various OATT Various Various OATT Various Various OATT Various Various OATT Various Various 3 16,468 16,468 5 OATT Various Various 42 298,861 298,861 6 OATT Various Various 8 53,377 53,377 7 OATT Various Various 54 693,426 693,426 8 OATT Various Various 3 7,504 7,504 9 OATT Various Various 225 146,490 146,490 10 OATT Various Various 167 185,700 185,700 11 OATT Not Available Not Available 58 16,472 16,472 12 OATT Various Various 1 6,907 6,907 13 OATT Various Various 90 357,425 357,425 14 OATT Various Various 14 82,781 82,781 15 OATT Various Various 37 141,249 141,249 16 OATT Various Various 10 54,668 54,668 17 OATT Various Various 127 246,526 246,526 18 OATT Various Various 2 4,718 4,718 19 OATT Various Various 110 260,699 260,699 20 OATT Various Various 1 4,146 4,146 21 OATT Various Various 191 163,676 163,676 22 OATT Various Various 72 103,165 103,165 23 OATT Various Various 50 119,400 119,400 24 OATT Various Various 25 OATT Various Various 26 OATT Various Various 3 354 354 27 OATT Various Various 23 1,929 1,929 28 OATT Various Various 333 44,093 44,093 29 OATT Various Various 91 3,532 3,532 30 OATT Various Various 24 297 297 31 OATT Various Various 5,896 269,075 269,075 32 OATT Various Various 25 400 400 33 OATT Various Various 1,676 83,546 83,546 34 123,411 47,821,543 47,821,543 FERC FORM NO. 1 (ED. 12-90) 166 MegaWatt Hours Delivered (j) 1 2 3 4 Page 329 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company 5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered. FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other Designation) (g) Billing Demand (MW) (h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Line No. MegaWatt Hours Delivered (j) OATT Various Various OATT Various Various 115 1,723 1,723 2 OATT Various Various 50 1,016 1,016 3 OATT Various Various 135 3,176 3,176 4 OATT Various Various 104 790 790 5 OATT Various Various 5,450 18,286 18,286 6 OATT Various Various 1,733 4,091 4,091 7 OATT Various Various 2,275 3,068 3,068 8 OATT Various Various 5,406 66,410 66,410 9 OATT Various Various 5 5 5 10 OATT Various Various 550 363 363 11 OATT Various Various 352 210 210 12 OATT Various Various 2,400 2,737 2,737 13 OATT Various Various 78 155 155 14 OATT Various Various 1,519 2,628 2,628 15 OATT Various Various 270 295 295 16 OATT Various Various 400 23 23 17 OATT Various Various 169 169 169 18 OATT Various Various 403 749 749 19 OATT Various Various OATT Various Various 200 200 200 21 OATT Various Various 7,381 26,611 26,611 22 OATT Various Various 3,750 3,693 3,693 23 OATT Various Various 800 760 760 24 OATT Various Various 400 646 646 25 OATT Various Various 1,250 1,453 1,453 26 OATT Various Various OATT Various Various 2,273 3,556 3,556 28 OATT Various Various OATT Various Various OATT Various Various 1,845 6,231 6,231 31 OATT Various Various 1,200 1,701 1,701 32 OATT Various Various 6,555 12,804 12,804 33 OATT Various Various 1,247 60,582 60,582 34 123,411 47,821,543 47,821,543 FERC FORM NO. 1 (ED. 12-90) 1 20 27 29 30 Page 329.1 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company 5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered. FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other Designation) (g) Billing Demand (MW) (h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Line No. MegaWatt Hours Delivered (j) OATT Various Various 4 OATT Various Various 42 26 26 2 OATT Various Various 15 162 162 3 OATT Various Various 56 997 997 4 OATT Various Various 150 1,200 1,200 5 OATT Various Various OATT Various Various 225 4,073 4,073 7 OATT Various Various 7,997 19,231 19,231 8 OATT Various Various 75 75 75 9 OATT Various Various 3,005 6,985 6,985 10 OATT Various Various 1,645 2,425 2,425 11 OATT Various Various 114 31 31 12 OATT Various Various 1,518 917 917 13 OATT Various Various 404 429 429 14 OATT Various Various 5,009 8,861 8,861 15 OATT Various Various 650 650 650 16 OATT Various Various 1,000 953 953 17 OATT Various Various 45 45 45 18 OATT Various Various 275 608 608 19 OATT Various Various 552 820 820 20 OATT Various Various 52 52 52 21 OATT Various Various 178 128 128 22 OATT Various Various 725 1,327 1,327 23 OATT Various Various 2,481 4,548 4,548 24 OATT Various Various 2,297 4,172 4,172 25 OATT Various Various 408 4 4 26 OATT Various Various 4,224 11,310 11,310 27 OATT Various Various 1,085 1,079 1,079 28 OATT Various Various 360 473 473 29 OATT Various Various 2,538 2,847 2,847 30 OATT Various Various 4,403 6,027 6,027 31 OATT Various Various OATT Various Various 13,941 21,706 21,706 33 OATT Various Various 600 600 600 34 123,411 47,821,543 47,821,543 FERC FORM NO. 1 (ED. 12-90) 42 42 1 6 32 Page 329.2 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') Year/Period of Report 2017/Q4 End of 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company 5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered. FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other Designation) (g) Billing Demand (MW) (h) TRANSFER OF ENERGY MegaWatt Hours Received (i) MegaWatt Hours Delivered (j) Line No. OATT Various Various 837 2,724 2,724 1 OATT Various Various 2,206 8,696 8,696 2 OATT Various Various 140 151 151 3 OATT Various Various 5,966 19,276 19,276 4 OATT Various Various 100 180 180 5 OATT Various Various 36,559 36,559 6 OATT Various Various 168 168 7 RS 183 Not Available Not Available 5,167,641 5,167,641 8 RS 183 Not Available Not Available 6,880,485 6,880,485 9 RS 73 Palo Verde Four Corners 130 780,631 780,631 10 RS 198 Riverside Substation North Gila Sub 50 12,817 12,817 11 OATT Not Available Not Available 12 RS 162 Pinnacle Peak Sub Luke Substation 13 RS 166 Gila Substation Marine Corps Air Stn 14 OATT Not Available Not Available 15 RS 3 Not Available Not Available 16 RS 3 Pinnacle Peak Ocotillo 230 17 RS 181 Gila Substation District Customer 18 RS 31 Gila Substation Yuma Mesa Load 19 Not Available Not Available Not Available 92 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 123,411 FERC FORM NO. 1 (ED. 12-90) Page 329.3 47,821,543 47,821,543 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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 ($) (k) 9,394,207 99,154 4,442 1,510,496 306,188 16,406 Line No. Total Revenues ($) (k+l+m) (n) 9,394,207 1 -9,394,207 -9,394,207 2 -302,227,232 -302,227,232 3 302,227,232 302,227,232 4 -169 103,427 5 -3,509 1,506,987 6 7 53,545 376,139 2,150,295 -3,901 2,146,394 8 56,005 -92 55,913 9 10 4,210,074 1,465,602 4,210,074 11 1,465,602 12 42,239 891 101,271 144,401 13 3,801,943 31,990 -4,703 3,829,230 14 591,413 -1,273 590,140 15 1,562,837 -1,863 1,560,974 16 422,388 -741 421,647 17 5,364,650 3,082 5,367,732 18 29,295 -11 29,284 19 4,646,819 -2,317 4,644,502 20 455,545 21 455,545 3,253,781 -822 3,252,959 22 3,252,636 191,255 3,443,891 23 1,077,979 -962 1,077,017 24 445,163 445,163 25 550,683 550,683 26 2,298 27 17,617 22,750 40,367 28 360,119 -93 360,026 29 37,382 37,382 30 3,862 3,862 31 3,883 1,907,426 32 5,983 33 -146 660,775 34 3,535,639 47,140,324 2,298 1,903,543 5,983 660,921 43,549,458 FERC FORM NO. 1 (ED. 12-90) 55,227 Page 330 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively. 11. Footnote entries and provide explanations following all required data. REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS Energy Charges (Other Charges) ($) ($) (l) (m) Demand Charges ($) (k) Line No. Total Revenues ($) (k+l+m) (n) 1 14,986 14,986 2 -1 6,515 3 22,394 -1 22,393 4 26,677 -113 26,564 5 126,006 6 6,516 126,006 49,687 -39 49,648 7 38,782 -1,234 37,548 8 55,293 259 55,552 9 23 23 10 3,550 3,550 11 2,637 2,637 12 12,746 12,746 13 790 790 14 16,908 16,908 15 4,488 4,488 16 3,646 3,646 17 1,516 18 6,678 6,678 19 2,992 2,992 21 1,517 -1 20 228,910 -662 228,248 22 58,785 -14 58,771 23 3,642 24 3,642 7,502 7,502 25 12,192 12,192 26 40,103 28 27 40,143 -40 29 30 51,324 51,324 31 17,097 17,097 32 164,903 -254 362,783 43,549,458 FERC FORM NO. 1 (ED. 12-90) 55,227 Page 330.1 3,535,639 164,649 33 362,783 34 47,140,324 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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) 529 529 1 5,508 5,508 2 1,809 1,809 3 7,373 7,373 4 19,823 19,823 5 -2,276 6 -2,276 31,751 31,751 7 153,686 153,686 8 673 673 9 62,969 52,410 115,379 10 26,574 -16 26,558 11 571 571 12 10,456 10,456 13 4,300 4,300 14 73,520 -18 73,502 15 5,439 -5 5,434 16 8,581 -170 8,411 17 366 18 5,365 19 366 5,369 -4 5,907 5,907 20 380 380 21 1,598 22 12,484 1,598 -34 12,450 23 40,081 -16 40,065 24 51,034 -9 51,025 25 3,663 26 3,663 88,016 -4 88,012 27 6,620 -1 6,619 28 3,984 29 3,984 32,275 -28 32,247 30 51,112 -2 51,110 31 -165 -165 32 -34 164,989 33 4,883 34 165,023 4,883 43,549,458 FERC FORM NO. 1 (ED. 12-90) 55,227 Page 330.2 3,535,639 47,140,324 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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) 23,857 -108 23,749 1 61,646 -48 61,598 2 1,321 -3 1,318 3 176,065 621 176,686 4 865 -2 863 5 6 2,084 258 2,342 7 8 9 1,415,030 1,415,030 10 2,071,390 2,071,390 11 52,997 173,448 1,498 77,652 2,716 20,042 935,984 52,997 12 174,946 13 77,652 14 2,716 15 20,042 16 935,984 17 540 540 18 4,500 4,500 19 1,144,666 1,144,666 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 43,549,458 FERC FORM NO. 1 (ED. 12-90) 55,227 Page 330.3 3,535,639 47,140,324 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 328 Line No.: 1 Column: a Service to Arizona Public Service Company pursuant to Part III of the OATT Schedule Page: 328 Line No.: 1 Column: c Monthly Demand Service Period Schedule Page: 328 Line No.: 1 Column: m Direct Assignment Charges and Unreserved Use Credit Intercompany Transmission Correction 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: c Service to Arizona Public Service Company pursuant to Part IV of the OATT Schedule Page: 328 Line No.: 2 Column: m AzISA Fees and Unreserved Use Credit Intercompany Transmission Correction Schedule Page: 328 Line No.: 3 Column: a Intercompany Transmission Schedule Page: 328 Line No.: 3 Column: c Intercompany Transmission Schedule Page: 328 Line No.: 4 Column: a Intercompany Transmission Schedule Page: 328 Line No.: 4 Column: c Intercompany Transmission Schedule Page: 328 Line No.: 5 Column: m Line No.: 6 Column: m Line No.: 7 Column: m Unreserved Use Credit Schedule Page: 328 Unreserved Use Credit Schedule Page: 328 Direct Assignment Charges and Unreserved Use Credit Schedule Page: 328 Line No.: 8 Column: m Line No.: 9 Column: m Unreserved Use Credit Schedule Page: 328 Unreserved Use Credit Schedule Page: 328 Line No.: 13 Column: m Direct Assignment Charge and Unreserved Use Credit Schedule Page: 328 Line No.: 14 Column: m Line No.: 15 Column: m Line No.: 16 Column: m Line No.: 17 Column: m Line No.: 18 Column: m Unreserved Use Credit Schedule Page: 328 Unreserved Use Credit Schedule Page: 328 Unreserved Use Credit Schedule Page: 328 Unreserved Use Credit Schedule Page: 328 Unreserved Use Credit and Unreserved Use Penalty Charge Schedule Page: 328 Line No.: 19 FERC FORM NO. 1 (ED. 12-87) Column: m Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 FOOTNOTE DATA Unreserved Use Credit Schedule Page: 328 Line No.: 20 Column: m Line No.: 21 Column: h Unreserved Use Credit Schedule Page: 328 Monthly Demand Service Period Schedule Page: 328 Line No.: 21 Column: m Line No.: 22 Column: h Unreserved Use Credit Schedule Page: 328 Monthly Demand Service Period Schedule Page: 328 Line No.: 22 Column: m Line No.: 23 Column: h Unreserved Use Credit Schedule Page: 328 Monthly Demand Service Period Schedule Page: 328 Line No.: 23 Column: m Charge equivalent to SFP monthly charge for long-term transmission contract deferral, recognized over deferral period Schedule Page: 328 Line No.: 24 Column: h Monthly Demand Service Period Schedule Page: 328 Line No.: 24 Column: m Line No.: 25 Column: h Unreserved Use Credit Schedule Page: 328 Monthly Demand Service Period Schedule Page: 328 Line No.: 25 Column: m Charge equivalent to SFP monthly charge for long-term transmission contract deferral, recognized over deferral period Schedule Page: 328 Line No.: 26 Column: h Monthly Demand Service Period Schedule Page: 328 Line No.: 26 Column: m Charge equivalent to SFP monthly charge for long-term transmission contract deferral, recognized over deferral period Schedule Page: 328 Line No.: 28 Column: m Unreserved Use Credit and Unreserved Use Penalty Charge Schedule Page: 328 Line No.: 29 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 29 Column: k Intercompany Transmission Correction Schedule Page: 328 Line No.: 29 Column: m Line No.: 30 Column: h Unreserved Use Credit Schedule Page: 328 Daily Demand Service Period Schedule Page: 328 Line No.: 31 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 32 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 32 Column: m Unreserved Use Credit and Unreserved Use Penalty Charge Schedule Page: 328 Line No.: 33 Column: h Daily Demand Service Period FERC FORM NO. 1 (ED. 12-87) Page 450.2 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 328 Line No.: 34 Column: h Daily Demand Service Period Schedule Page: 328 Line No.: 34 Column: m Line No.: 1 Column: h Unreserved Use Credit Schedule Page: 328.1 Daily Demand Service Period Schedule Page: 328.1 Line No.: 2 Column: h Daily Demand Service Period Schedule Page: 328.1 Line No.: 3 Column: h Daily Demand Service Period Schedule Page: 328.1 Line No.: 3 Column: m Line No.: 4 Column: h Unreserved Use Credit Schedule Page: 328.1 Daily Demand Service Period Schedule Page: 328.1 Line No.: 4 Column: m Line No.: 5 Column: h Unreserved Use Credit Schedule Page: 328.1 Daily 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.: 7 Column: h 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 Line No.: 9 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 9 Column: m Unreserved Use Credit and Unreserved Use Penalty Charge Schedule Page: 328.1 Line No.: 10 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 11 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 12 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 12 Column: m Line No.: 13 Column: h Unreserved Use Credit Schedule Page: 328.1 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 FERC FORM NO. 1 (ED. 12-87) Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 328.1 Line No.: 16 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 17 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 17 Column: m Line No.: 18 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 18 Column: m Line No.: 19 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 19 Column: m Line No.: 20 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 21 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 22 Column: h 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 Line No.: 24 Column: h Unreserved Use Credit Schedule Page: 328.1 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 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 28 Column: m Line No.: 29 Column: h Unreserved Use Credit Schedule Page: 328.1 Hourly Demand Service Period Schedule Page: 328.1 Line No.: 30 Column: h Hourly Demand Service Period Schedule Page: 328.1 Line No.: 30 Column: m Unreserved Use Credit FERC FORM NO. 1 (ED. 12-87) Page 450.4 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 328.1 Line No.: 31 Column: h 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 Daily Demand Service Period Schedule Page: 328.2 Line No.: 1 Column: h Daily Demand Service Period Schedule Page: 328.2 Line No.: 2 Column: h Daily Demand Service Period Schedule Page: 328.2 Line No.: 3 Column: h Daily Demand Service Period Schedule Page: 328.2 Line No.: 4 Column: h Daily Demand Service Period Schedule Page: 328.2 Line No.: 5 Column: h Daily Demand Service Period Schedule Page: 328.2 Line No.: 6 Column: h Daily Demand Service Period Schedule Page: 328.2 Line No.: 6 Column: m Line No.: 7 Column: h Unreserved Use Credit Schedule Page: 328.2 Daily Demand Service Period Schedule Page: 328.2 Line No.: 8 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 9 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 10 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 10 Column: m Unreserved Use Credit and Unreserved Use Penalty Charge Schedule Page: 328.2 Line No.: 11 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 11 Column: m Line No.: 12 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 13 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 14 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 15 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 15 Column: m Unreserved Use Credit FERC FORM NO. 1 (ED. 12-87) Page 450.5 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 328.2 Line No.: 16 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 16 Column: m Line No.: 17 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 17 Column: m Line No.: 18 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 18 Column: m Line No.: 19 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 19 Column: m Line No.: 20 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 21 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 22 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 23 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 23 Column: m Line No.: 24 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 24 Column: m Line No.: 25 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 25 Column: m Line No.: 26 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 27 Column: h Hourly Demand Service Period Schedule Page: 328.2 Line No.: 27 Column: m Line No.: 28 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 28 Column: m Line No.: 29 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 30 Column: h Hourly Demand Service Period FERC FORM NO. 1 (ED. 12-87) Page 450.6 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 328.2 Line No.: 30 Column: m Line No.: 31 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 31 Column: m Line No.: 32 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 32 Column: m Line No.: 33 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.2 Line No.: 33 Column: m Line No.: 34 Column: h Unreserved Use Credit Schedule Page: 328.2 Hourly Demand Service Period Schedule Page: 328.3 Line No.: 1 Column: h Hourly Demand Service Period Schedule Page: 328.3 Line No.: 1 Column: m Line No.: 2 Column: h Unreserved Use Credit Schedule Page: 328.3 Hourly Demand Service Period Schedule Page: 328.3 Line No.: 2 Column: m Line No.: 3 Column: h Unreserved Use Credit Schedule Page: 328.3 Hourly Demand Service Period Schedule Page: 328.3 Line No.: 3 Column: m Line No.: 4 Column: h Unreserved Use Credit Schedule Page: 328.3 Hourly Demand Service Period Schedule Page: 328.3 Line No.: 4 Column: m Unreserved Use Credit and Unreserved Use Penalty Charge Schedule Page: 328.3 Line No.: 5 Column: h Hourly Demand Service Period Schedule Page: 328.3 Line No.: 5 Column: m Line No.: 6 Column: h Unreserved Use Credit Schedule Page: 328.3 Hourly Demand Service Period Schedule Page: 328.3 Line No.: 6 Column: m Service taken under the WestConnect agreement Schedule Page: 328.3 Line No.: 7 Column: h Hourly Demand Service Period Schedule Page: 328.3 Line No.: 7 Column: m Unreserved Use Credit and Unreserved Use Penalty Charge Schedule Page: 328.3 Line No.: 8 Column: e Exchange agreement pursuant to Pre888 contract Schedule Page: 328.3 Line No.: 9 Column: e Exchange agreement pursuant to Pre888 contract FERC FORM NO. 1 (ED. 12-87) Page 450.7 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 328.3 Line No.: 12 Column: m Direct Assignment Charges Schedule Page: 328.3 Line No.: 13 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.3 Line No.: 14 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.3 Line No.: 15 Column: m Direct Assignment Charges Schedule Page: 328.3 Line No.: 16 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.3 Line No.: 17 Column: m Direct Assignment Charges Schedule Page: 328.3 Line No.: 18 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.3 Line No.: 19 Column: e Part of APS NITS load - recovery of transmission cost contract Schedule Page: 328.3 Line No.: 20 Column: m FERC transmission rate true up, change in estimate, and timing difference Intercompany Transmission Correction FERC FORM NO. 1 (ED. 12-87) Page 450.8 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/Q4 (2) X A Resubmission TRANSMISSION OF ELECTRICITY BY ISO/RTOs 1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). 3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. 4. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. 5. In column (d) report the revenue amounts as shown on bills or vouchers. 6. Report in column (e) the total revenues distributed to the entity listed in column (a). Line 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling") Year/Period of Report 2017/Q4 End of 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data. Line No. 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 LFP 612,862 612,862 2 Bu. of Indian Affairs OLF 3 Department of Energy OS 490,688 490,688 4 Department of Energy NF 16,086 16,086 58,250 5 Department of Energy FNS 368,561 368,561 1,339,804 6 Department of Energy FNS 1,169,752 1,169,752 3,922,112 7 Department of Energy LFP 305,192 305,192 48,952 270,591 -4,021 315,522 8 Department of Energy LFP 1,750 1,750 2,680,940 444,168 -435,121 2,689,987 387,817 387,817 7,365,240 360,069 74,246 7,799,555 -129 92,096 -10,458 30,385 153,600 153,600 324,943 22,699 347,642 22,044 -34,476 45,818 547,216 8,650 1,895,670 1,033,538 -52,972 4,902,678 9 Department of Energy LFP 10 Department of Energy OS 11 Department of Energy SFP 15,714 15,714 39,829 12 Electric District # 4 OLF 2,246 2,246 67,601 13,562 81,163 13 Electric District # 3 LFP 2,658 2,658 81,940 -13,701 68,239 14 Salt River Project OLF 36,901 36,901 263,969 35,580 -37,217 262,332 15 Salt River Project OLF 343,086 343,086 1,413,028 319,792 -319,793 1,413,027 16 Salt River Project LFP 186,883 186,883 1,327,505 188,997 -19,337 1,497,165 5,838,042 5,838,042 24,014,956 5,184,285 -679,525 28,519,716 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 92,225 Page 332 1,014 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling") Year/Period of Report 2017/Q4 End of 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data. Line No. Name of Company or Public Authority (Footnote Affiliations) (a) Statistical Classification (b) TRANSFER OF ENERGY MagawattMagawatthours hours Received Delivered (c) (d) 467,713 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 467,713 1,710,521 468,257 2,483 2,181,261 2 Salt River Project OLF 3 Salt River Project OS 100,196 100,196 223,759 100,419 -100,421 223,757 1,752,518 1,752,518 539,275 285,153 824,428 4 Salt River Project FNS 391 391 1,786,529 386,423 -32,938 2,140,014 4,389 199,880 5 Salt River Project OS 6 Southern Cal Edison LFP 104 104 195,491 7 Southwest Transmission SFP 24,081 24,081 103,957 15,758 119,715 8 Tucson Electric Power NF 6,807 6,807 41,616 4,781 -5,996 40,401 1,572 1,572 -41,457 374,251 9 Public Srvce Co of NM NF 10 SRP Misc AR OS 156,530 156,530 279,941 135,767 11 Pacificorp NF 1,203 1,203 9,762 1,411 12 Idaho Power Company NF 1,165 1,165 13 Navopache Electric OS 11,173 7,251 7,251 188,272 188,272 14 15 16 TOTAL FERC FORM NO. 1/3-Q (REV. 02-04) 5,838,042 5,838,042 Page 332.1 24,014,956 5,184,285 -679,525 28,519,716 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 332 Line No.: 1 Column: a Intercompany Transmission Schedule Page: 332 Line No.: 1 Column: b Terminates December 31, 2020 Schedule Page: 332 Line No.: 2 Column: b Terminates with 30 days notice Schedule Page: 332 Line No.: 3 Column: b Loss compensation on jointly owned facilities 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: b Effective until terminated by counterparty Schedule Page: 332 Line No.: 12 Column: g Prior period adjustment /Timing 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 FERC FORM NO. 1 (ED. 12-87) Column: g Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Prior period adjustment /Timing Schedule Page: 332 Line No.: 16 Column: b 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: b Loss compensation on jointly owned facilities 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: a Ancilliary/Timing Schedule Page: 332.1 Southwest Transmission Cooperative Inc. Schedule Page: 332.1 Line No.: 7 Column: g 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 Schedule Page: 332.1 Line No.: 11 Column: g Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 12 Column: g Prior period adjustment /Timing Schedule Page: 332.1 Line No.: 13 Column: b Navopache Vernon Tie Facilities use charges Schedule Page: 332.1 Line No.: 13 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) 05/09/2018 2017/Q4 Name of Respondent 20180509-8003 FERC Arizona Public Service Company This Report Is: PDF (Unofficial) (1) 05/09/2018 An Original Line No. Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC) Description (a) 1 Industry Association Dues Year/Period of Report 2017/Q4 End of Amount (b) 1,083,041 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 6 Allocation of Parent Company Costs -570,396 8,531,840 7 Bank Fees 1,401,785 8 Billed to Others-Services Performed -72,518,422 9 Communication Service 450,459 10 Materials & Supplies 41,457 11 Payroll 1,509,837 12 Outside Services 424,665 13 Rents/Leases -255,840 14 Transportation Expense 14,574 15 Travel 321,443 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) -59,565,557 Page 335 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405) (Except amortization of aquisition adjustments) Year/Period of Report 2017/Q4 End of 1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). 2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. 3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. 4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related. Line No. Functional Classification (a) 1 Intangible Plant A. Summary of Depreciation and Amortization Charges Depreciation Amortization of Expense for Asset Limited Term Depreciation Retirement Costs Expense Electric Plant (Account 404) (Account 403.1) (Account 403) (c) (b) (d) 71,527,912 Amortization of Other Electric Plant (Acc 405) (e) Total (f) 71,527,912 2 Steam Production Plant 64,828,751 2,982,944 5,461 67,817,156 3 Nuclear Production Plant 37,233,809 1,491,816 4,439,558 43,165,183 6 Other Production Plant 76,756,247 5,858,079 7 Transmission Plant 50,848,700 9,646,824 60,495,524 133,803,926 866,384 134,670,310 46,934,542 6,473,079 53,407,621 92,959,218 513,698,032 4 Hydraulic Production Plant-Conventional 5 Hydraulic Production Plant-Pumped Storage 8 Distribution Plant 82,614,326 9 Regional Transmission and Market Operation 10 General Plant 11 Common Plant-Electric 12 TOTAL 410,405,975 10,332,839 B. Basis for Amortization Charges RATES Franchises 302 4.00% Software 303 10.00% to 33.33% Misc. Intangibles 303.0 2.00% to 20.00% Limited Term Land Rights 310,350,360,389 1.67% to 50.00% Office Equipment & Furniture, Small Tools, Garage Equipment, Misc. Equipment 391,391.2,393,394,395,3984.17% to 5.00% Leasehold Improvements 321,322,323,324,325,326,371,390,397 amortized over the life of the lease FERC FORM NO. 1 (REV. 12-03) Page 336 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Line No. Account No. (a) 12 STEAM PRODUCTION (2) X A Resubmission DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) C. Factors Used in Estimating Depreciation Charges Depreciable Estimated Net Plant Base Avg. Service Salvage (In Thousands) Life (Percent) (d) (b) (c) Applied Depr. rates (Percent) (e) Year/Period of Report 2017/Q4 End of Mortality Curve Type (f) Average Remaining Life (g) 13 311 25.00 -10.60 5.43 O1 12.00 14 312 29.00 -14.00 4.17 O1 14.00 15 314 28.00 -13.40 4.95 O1 12.00 16 315 28.00 -11.50 4.97 O1 13.00 17 316 24.00 -13.20 5.36 O1 13.00 19 321 47.00 -0.70 0.98 O1 30.00 20 322 47.00 -0.70 0.83 O1 29.00 21 323 46.00 -0.70 0.92 O1 29.00 22 324 52.00 -0.70 0.40 O1 29.00 23 325 43.00 -0.70 1.35 O1 30.00 25 341 28.00 -5.80 3.86 O1 21.00 26 342 28.00 -5.80 3.81 O1 17.00 27 343 30.00 -5.80 3.43 O1 20.00 28 344 27.00 -5.80 3.98 O1 22.00 29 345 27.00 -5.80 3.95 O1 22.00 30 346 25.00 -5.80 4.29 O1 19.00 2.51 R4 12.00 2.00 R1.5 41.00 1.78 R3 33.00 18 NUCLEAR PRODUCTION 24 OTHER PRODUCTION 31 TRANSMISSION 32 352 52.00 33 353 54.00 34 354 60.00 35 355 55.00 -20.00 2.22 R1.5 44.00 36 356 60.00 -20.00 2.07 R3 43.00 37 357 60.00 1.55 R4 48.00 38 358 60.00 15.00 1.33 L1.5 45.00 40 361 60.00 -5.00 1.66 R3 48.00 41 362 43.00 -5.00 2.28 L0.5 35.00 42 363 10.00 8.79 S3 7.00 43 364.1 45.00 -10.00 2.29 L0 35.00 44 364.2 50.00 -10.00 2.14 R0.5 45.00 45 365 50.00 -10.00 2.12 SC 42.00 46 366 60.00 -10.00 1.74 L1 48.00 47 367 40.00 -10.00 2.54 L1 31.00 48 368 55.00 -5.00 1.76 L1 43.00 49 369 55.00 -20.00 2.01 L1 42.00 50 370.1 18.00 5.49 SC 15.00 -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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Line No. Account No. (a) 12 370.3 (2) X A Resubmission DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) C. Factors Used in Estimating Depreciation Charges Depreciable Estimated Net Plant Base Avg. Service Salvage (In Thousands) Life (Percent) (d) (b) (c) 20.00 Applied Depr. rates (Percent) (e) 4.84 SC Year/Period of Report 2017/Q4 End of Mortality Curve Type (f) Average Remaining Life (g) 18.00 13 371 45.00 -15.00 2.42 L0 37.00 14 373 54.00 -12.00 1.90 L0.5 43.00 40.00 -5.00 2.69 L1 33.00 15 GENERAL 16 390 17 391-1 18 397 8.00 12.88 L3 5.00 21.00 4.83 L2 15.00 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 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission REGULATORY COMMISSION EXPENSES Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. 2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Line No. Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a) 1 ACC/RUCO Expenses Assessed by Regulatory Commission (b) Expenses of Utility (c) Total Expense for Current Year (b) + (c) (d) 2 Annual Assessment by Arizona Corporation 3 Commission (ACC) and Annual Assessment by 4 Residential Utility Consumer Office (RUCO) 8,719,377 5 Legal and Filing Fees 6 Consulting Fees 7 Payroll and Employee Expense 8 Est. ACC and RUCO Assessments on Unbilled Rev 8,719,377 10,000 10,000 550,990 550,990 4,085,286 4,085,286 8,442 8,442 2,757,545 2,757,545 9 Other 10 11 FERC Expenses 12 Regulatory Assessment by FERC 13 Legal and Filing Fees 14 Consulting Fees 11,723 11,723 15 Payroll and Employee Expenses 52,508 52,508 16 Other 17 18 NRC Expenses 19 NRC License Fees 4,487,795 4,487,795 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 TOTAL FERC FORM NO. 1 (ED. 12-96) 15,973,159 Page 350 4,710,507 20,683,666 Deferred in Account 182.3 at Beginning of Year (e) Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission REGULATORY COMMISSION EXPENSES (Continued) Year/Period of Report 2017/Q4 End of 3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. 4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts. 5. Minor items (less than $25,000) may be grouped. EXPENSES INCURRED DURING YEAR CURRENTLY CHARGED TO Account Amount Department No. (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 8,719,377 4 Electric 928 10,000 5 Electric 928 550,990 6 Electric 928 4,085,286 7 Electric 928 8,442 8 9 10 11 Electric 928 2,757,545 12 Electric 928 11,723 14 Electric 928 52,508 15 13 16 17 18 Electric 928 4,487,795 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 20,683,666 FERC FORM NO. 1 (ED. 12-96) 46 Page 351 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES Year/Period of Report 2017/Q4 End of 1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). 2. Indicate in column (a) the applicable classification, as shown below: Classifications: A. Electric R, D & D Performed Internally: (1) Generation a. hydroelectric i. Recreation fish and wildlife ii Other hydroelectric b. Fossil-fuel steam c. Internal combustion or gas turbine d. Nuclear e. Unconventional generation f. Siting and heat rejection (2) Transmission Line 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 B(1) EPRI 2 B(1) EPRI 3 B(1) EPRI 4 B(1) EPRI 5 B(1) EPRI 6 Total 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 FERC FORM NO. 1 (ED. 12-87) Page 352 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued) Year/Period of Report 2017/Q4 End of (2) Research Support to Edison Electric Institute (3) Research Support to Nuclear Power Groups (4) Research Support to Others (Classify) (5) Total Cost Incurred 3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D & D activity. 4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e) 5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. 6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by "Est." 7. Report separately research and related testing facilities operated by the respondent. Costs Incurred Internally Costs Incurred Externally Current Year Current Year (c) (d) 1,697,025 AMOUNTS CHARGED IN CURRENT YEAR Account (e) 580 Amount (f) 1,697,025 Unamortized Accumulation (g) Line No. 1 263,393 500 263,393 2 216,367 506 216,367 3 384,890 549 384,890 4 698,736 524 698,736 5 3,260,411 6 3,260,411 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 FERC FORM NO. 1 (ED. 12-87) Page 353 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission DISTRIBUTION OF SALARIES AND WAGES Year/Period of Report 2017/Q4 End of Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used. Line No. 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) 125,505,581 19,647,235 49,204,704 26,254,832 2,342,386 7,557,521 95,551,067 326,063,326 38,108,490 3,105,531 19,624,848 3,872,581 64,711,450 163,614,071 22,752,766 68,829,552 26,254,832 2,342,386 7,557,521 99,423,648 390,774,776 354 390,774,776 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company 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 (2) X A Resubmission DISTRIBUTION OF SALARIES AND WAGES (Continued) 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 Saguaro Studies / Streetlights Miscellaneous Billings TOTAL Other Accounts TOTAL SALARIES AND WAGES FERC FORM NO. 1 (ED. 12-88) Page 355 Year/Period of Report 2017/Q4 End of Allocation of Payroll charged for Clearing Accounts (c) Total (d) 390,774,776 390,774,776 182,795,398 182,795,398 182,795,398 182,795,398 414,935 200,674 106,101 439 3,256,308 -97,243 215,308,270 15,300,356 9,758,586 1,772,481 11,444 317,282 362,522 1,421,182 369,359 330,686 1,163,565 249,996,947 823,567,121 414,935 200,674 106,101 439 3,256,308 -97,243 215,308,270 15,300,356 9,758,586 1,772,481 11,444 317,282 362,522 1,421,182 369,359 330,686 1,163,565 249,996,947 823,567,121 20180509-8003 05/09/2018 Name of RespondentFERC PDF (Unofficial) This Report Is: (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2017/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) 4,772,146 12,399,106 24,444,241 33,004,756 ( 6,726,310) ( 14,931,632) ( 29,719,982) ( 40,491,426) ( 1,954,164) ( 2,532,526) ( 5,275,741) ( 7,486,670) 4 Transmission Rights 5 Ancillary Services 6 Other Items (list separately) 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 TOTAL FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission PURCHASES AND SALES OF ANCILLARY SERVICES Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. (1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year. (2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold during the year. (3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold during the year. (4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year. (5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services purchased and sold during the period. (6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided. Amount Purchased for the Year Line No. Type of Ancillary Service (a) Amount Sold for the Year Usage - Related Billing Determinant Unit of Number of Units Dollars Measure (b) (c) (d) 1 Scheduling, System Control and Dispatch 62,532 MW 2 Reactive Supply and Voltage 62,532 MW 3 Regulation and Frequency Response 62,532 MW 4 Energy Imbalance 1,804,767 Usage - Related Billing Determinant Unit of Number of Units Dollars Measure (e) (f) (g) 70,026 MW 2,019,908 70,026 MW 6,927,436 63,714 MW 6,950,919 36,684 MWh -362,358 MWh 5 Operating Reserve - Spinning 62,532 MW 15,885,554 63,722 MW 15,911,762 6 Operating Reserve - Supplement 62,532 MW 2,013,369 63,722 MW 2,017,407 7 Other 8 Total (Lines 1 thru 7) FERC FORM NO. 1 (New 2-04) MWh MWh 312,660 26,631,126 Page 398 367,894 26,537,638 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 $54,676 of sold revenue in column (g) for 2017. Schedule Page: 398 Line No.: 2 Column: g Service currently provided at $0 per MW. FERC FORM NO. 1 (ED. 12-87) Page 450.1 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission MONTHLY TRANSMISSION SYSTEM PEAK LOAD (1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. (2) Report on Column (b) by month the transmission system's peak load. (3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). (4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification. NAME OF SYSTEM: Line No. Month Monthly Peak MW - Total Day of Monthly Peak (a) (b) (c) 1 January 5,008 2 February 4,395 3 March 4,781 Hour of Firm Network Monthly Service for Self Peak (d) Firm Network Service for Others Long-Term Firm Point-to-point Reservations Other LongTerm Firm Service Short-Term Firm Point-to-point Reservation Other Service (f) (g) (h) (i) (j) (e) 800 4,323 115 389 181 1 800 3,758 67 389 181 20 1900 4,125 86 389 181 12,206 268 1,167 543 26 4 Total for Quarter 1 5 April 4,957 23 1800 4,303 84 389 181 6 May 6,412 23 1800 5,529 88 614 181 7 June 8,435 20 1800 8 Total for Quarter 2 9 July 8,198 10 August 11 September 7,541 99 614 181 17,373 271 1,617 543 7 1700 7,296 107 614 181 7,594 9 1800 6,704 95 614 181 7,397 12 1700 6,518 82 616 181 20,518 284 1,844 543 12 Total for Quarter 3 13 October 5,623 4 1700 4,755 71 616 181 14 November 4,508 1 1900 3,664 47 616 181 15 December 4,890 22 800 16 Total for Quarter 4 4,016 77 616 181 12,435 195 1,848 543 62,532 1,018 6,476 2,172 17 Total Year to Date/Year FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD Year/Period of Report 2017/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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission ELECTRIC ENERGY ACCOUNT Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year. Line No. Item MegaWatt Hours (a) (b) Line No. Item MegaWatt Hours (a) (b) 1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY 2 Generation (Excluding Station Use): 22 Sales to Ultimate Consumers (Including 3 Steam 12,317,503 4 Nuclear 9,410,980 Interdepartmental Sales) 23 Requirements Sales for Resale (See 24 Non-Requirements Sales for Resale (See 6 Hydro-Pumped Storage 25 Energy Furnished Without Charge 24,920,924 26 Energy Used by the Company (Electric 7,825,768 27 Total Energy Losses 28 TOTAL (Enter Total of Lines 22 Through 11 Power Exchanges: 12 Received 633,695 13 Delivered 639,817 14 Net Exchanges (Line 12 minus line 13) 27) (MUST EQUAL LINE 20) -6,122 15 Transmission For Other (Wheeling) 16 Received 47,821,543 17 Delivered 47,821,543 18 Net Transmission for Other (Line 16 minus line 17) 19 Transmission By Others Losses 20 TOTAL (Enter Total of lines 9, 10, 14, 18 32,740,570 and 19) FERC FORM NO. 1 (ED. 12-90) 61,297 Dept Only, Excluding Station Use) through 8) 10 Purchases 2,835,161 instruction 4, page 311.) 3,192,441 8 Less Energy for Pumping 9 Net Generation (Enter Total of lines 3 56,998 instruction 4, page 311.) 5 Hydro-Conventional 7 Other 28,018,011 Page 401a 1,769,103 32,740,570 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission MONTHLY PEAKS AND OUTPUT Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 2,658,273 448,575 4,303 26 8:00 30 February 2,177,078 344,736 3,758 1 8:00 31 March 2,361,400 314,951 4,032 20 19:00 32 April 2,253,917 213,054 4,208 23 18:00 33 May 2,649,153 216,193 5,411 23 18:00 34 June 3,316,902 161,465 7,367 20 18:00 35 July 3,666,863 175,440 7,131 7 17:00 36 August 3,694,615 311,528 6,562 9 18:00 37 September 2,986,606 213,082 6,377 12 17:00 38 October 2,599,546 285,301 4,648 4 17:00 39 November 2,096,183 147,598 3,575 1 19:00 40 December 2,280,034 199,802 3,925 22 8:00 32,740,570 3,031,725 41 TOTAL FERC FORM NO. 1 (ED. 12-90) Page 401b 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 401 Line No.: 29 Column: b Prior period adjustment Schedule Page: 401 Line No.: 30 Column: b Prior period adjustment Schedule Page: 401 Line No.: 32 Column: b Prior period adjustment Schedule Page: 401 Line No.: 35 Column: b Prior period adjustment Schedule Page: 401 Line No.: 35 Column: c Prior period adjustment Loss calculation correction Schedule Page: 401 Line No.: 36 Column: b Prior period adjustment Schedule Page: 401 Line No.: 36 Column: c Prior period adjustment Loss calculation correction Schedule Page: 401 Line No.: 37 Column: b Prior period adjustment Schedule Page: 401 Line No.: 38 Column: c Loss calculation correction Schedule Page: 401 Line No.: 39 Column: c Loss calculation correction Schedule Page: 401 Line No.: 40 Column: c Loss calculation correction FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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 240370 9147 55.638 56.545 3.091 0.034 11030.568 Page 402 Oil Bbls 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoors 1962 1981 113.60 112 5798 0 116 116 38 398758025 1426006 20758266 145305861 6435774 173925907 1531.0379 2313084 13559714 0 1799558 0 0 264168 1164172 0 14182 1126453 751737 1676754 277406 236096 23183324 0.0581 Gas MCF 1516 856163 4.430 2.753 3.215 0.035 11030.543 (c) Coal Tons 752857 9145 51.496 52.158 2.852 0.031 10950.808 Steam Over 50% Outdoors 1980 1981 312.30 272 7463 0 271 271 59 1258142307 3922733 57348576 402189874 15035298 478496481 1532.1693 1338704 39245750 0 5006287 0 0 199407 2185292 0 65348 1767789 1946107 5967811 5986343 2361296 66070134 0.0525 Oil Gas Bbls MCF 1583 0 129002 0 98.304 0.000 4.289 0.000 0.792 0.000 0.009 0.000 10950.809 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2017/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 113.60 105 1666 0 110 110 11 89594000 137462 2348993 27273788 5186294 34946537 307.6280 0 3544366 0 280759 0 0 65 284646 0 7536 0 149926 211717 278821 -331 4757505 0.0531 Gas MCF 978818 1051282 3.300 3.621 3.444 0.040 11485.301 (c) Steam Units 1, 2, 3 Over 50% Outdoors 1974 1976 337.34 321 23761 0 315 315 0 1153824997 0 0 0 0 0 0.0000 6088142 33715517 0 2492734 0 0 1248832 8018366 130117 0 671882 285613 3685313 843685 659061 57839262 0.0501 Coal Tons 580461 10741 54.083 56.758 2.642 0.029 10831.437 Oil Bbls 5023 134870 72.916 153.188 27.043 0.293 10831.438 0 0 0.000 0.000 0.000 0.000 0.000 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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% Outdoors 1974 2008 72.40 41 52 0 54 0 1 664000 0 848195 7693823 0 8542018 117.9837 3119 484387 0 0 0 0 0 1487 0 0 147 265 0 339914 11029 840348 1.2656 Oil Gas Bbls MCF 76 0 138235 0 3584.335 0.000 6371.841 0.000 1097.483 0.000 0.729 0.000 664.702 0.000 (c) 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 2007 2008 60.50 48 2216 0 48 0 3 68145220 13711 1041908 36471283 0 37526902 620.2794 543906 4604007 0 0 0 0 0 464806 0 0 3632 72619 0 485382 10348 6184700 0.0908 Oil Gas Bbls MCF 0 738208 0 1040573 0.000 3.962 0.000 6.237 0.000 5.994 0.000 0.068 0.000 11272.387 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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 51 382 0 55 0 0 6441007 0 1539190 20899931 0 22439121 422.5823 0 503597 0 0 0 0 0 79332 0 0 1967 63734 0 189680 12261 850571 0.1321 Gas MCF 117214 1058224 2.729 4.296 4.060 0.078 19257.577 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 74 596 0 79 0 0 30188200 0 57876 29858026 0 29915902 382.0677 2197497 0 0 0 0 0 0 0 0 0 869 62374 0 254275 2436 2517451 0.0834 Gas MCF 0 424939 0 1059955 0.000 3.285 0.000 5.171 0.000 4.879 0.000 0.073 0.000 14920.284 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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 62 603 0 55 0 1 15135000 0 1721263 19656059 0 21377322 402.5861 7731 607260 0 0 0 0 487 0 0 0 175 5713 0 294095 14261 929722 0.0614 Gas MCF 274546 1048624 1.405 2.212 2.109 0.040 19021.837 Plant Name: Sundance (c) 0 0 0.000 0.000 0.000 0.000 0.000 Comb. Turbine Over 50% Outdoors 2002 2002 605.00 423 13148 0 420 0 13 381338403 681252 13729664 276417705 0 290828621 480.7085 0 18993825 0 0 0 0 828152 3156558 0 0 13039 1117782 0 4558155 138258 28805769 0.0755 Gas MCF 0 4063299 0 1029496 0.000 2.969 0.000 4.674 0.000 4.541 0.000 0.050 0.000 10969.652 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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 135.60 108 2431 0 117 0 9 217709218 32909 7347885 83344924 0 90725718 669.0687 170134 8641937 0 0 0 0 304739 86247 0 0 7208 174952 0 867298 74017 10326532 0.0474 Gas MCF 1830185 1048307 2.999 4.722 4.504 0.040 8812.654 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 569.60 479 11891 0 506 0 32 1998351500 18896 20844799 297272465 0 318136160 558.5256 1628710 81161408 0 0 0 0 5196668 2469250 0 0 61792 1146560 0 6894621 372196 98931205 0.0495 Gas MCF 0 15650287 0 2097701 0.000 3.294 0.000 5.186 0.000 4.944 0.000 0.041 0.000 8214.150 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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 410.82 401 8017 0 382 0 194 3081283388 1126125 205030429 558328859 16930153 781415566 1902.0874 8136412 24041569 0 4043088 0 0 3170406 14479564 7586405 0 2811487 782175 6369142 4811441 1540887 77772576 0.0252 Nuclear Kg Uranium 468 0 66704 0 2831.994 0.000 51417.892 0.000 0.759 0.000 0.008 0.000 10283.848 0.000 Plant Name: Palo Verde 3 (c) Nuclear Under 50% Outdoors 1988 1988 410.82 406 8626 0 382 0 223 3280612229 1659706 326335002 796424357 23171686 1147590751 2793.4150 8136148 26069502 0 2887914 0 0 3045582 13936918 7586405 0 504391 476252 2253899 2442871 852328 68192210 0.0208 Nuclear Kg Uranium 507 66704 0.000 51417.892 0.773 0.008 10283.848 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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 1373078 8809 57.929 61.820 3.509 0.034 9751.394 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoors 1969 1970 515.40 484 6394 0 485 485 90 2490318726 14014 13694580 116331991 9671566 139712151 271.0752 2279877 86084981 0 6638469 0 0 666486 4075851 396691 285580 869493 3382980 9324306 1458776 1891918 117355408 0.0471 Gas MCF 91262 1025551 12.001 13.169 12.841 0.125 9751.394 FERC FORM NO. 1 (REV. 12-03) Coal Tons 1000895 8813 56.171 59.616 3.382 0.035 10361.076 0 0 0.000 0.000 0.000 0.000 0.000 Steam Over 50% Outdoors 1969 1970 515.40 492 4523 0 485 485 92 1710665367 50032 19968324 469090510 9678744 498787610 967.7680 2547122 60514344 0 6613028 0 0 438318 4018207 396691 246928 869493 3960104 22921044 5876774 1189327 109591380 0.0641 Gas MCF 81284 1026759 9.478 10.401 10.130 0.105 10361.076 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 96 2161 0 110 110 13 110675100 152893 2261767 27049951 5186294 34650905 305.0256 0 4458871 0 245826 0 0 2209701 284646 0 7744 0 20401 248799 152209 226425 7854622 0.0710 Gas MCF 1245390 1051455 3.263 3.580 3.405 0.040 11831.676 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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 18 95 0 19 0 2 888000 33986 1694224 3254726 0 4982936 211.1414 3797 53401 0 0 0 0 619693 8718 0 0 474 54161 0 107299 112 847655 0.9546 Gas MCF 15474 1036756 2.062 3.246 3.131 0.057 18066.306 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 18 88 0 19 0 1 766000 0 1421722 4674291 0 6096013 258.3056 3009 43419 0 0 0 0 0 1404 0 0 71 1476 0 146519 0 195898 0.2557 Gas MCF 14161 1036278 1.948 3.066 2.959 0.057 19157.298 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 50 990 0 55 0 1 16298000 0 833630 15588253 0 16421883 226.8216 51152 913631 0 0 0 0 0 23941 0 0 625 7380 0 181441 5098 1183268 0.0726 Gas MCF 324609 1036136 1.788 2.815 2.716 0.056 20636.848 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) 05/09/2018 This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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 2101 0 48 0 2 62662900 0 1029252 38218019 0 39247271 648.7152 492668 4048053 0 0 0 0 0 242542 0 0 3561 74163 0 457031 101140 5419158 0.0865 Gas MCF 680718 1039354 3.777 5.947 5.722 0.065 11290.691 FERC FORM NO. 1 (REV. 12-03) Comb. Turbine Over 50% Outdoors 1972 1972 26.10 20 62 0 16 0 0 293000 9557 103952 5447219 0 5560728 213.0547 0 1943 0 0 0 0 0 1993 0 0 308 23636 0 133283 12156 173319 0.5915 0 0 0.000 0.000 0.000 0.000 0.000 Oil Bbls 373 138671 5.208 5.208 0.894 0.007 7414.379 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 54 410 0 55 0 0 7553600 0 1389975 15534458 0 16924433 318.7276 0 595397 0 0 0 0 0 88607 0 0 281 24833 0 134110 9487 852715 0.1129 Gas MCF 188584 1059326 2.005 3.157 2.980 0.079 26447.233 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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: Octotillo 2 Name: West Phoenix 1 No. Name: Octotillo 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 54 454 0 55 0 1 8623262 0 1470427 25377207 0 26847634 505.6052 0 506577 0 0 0 0 -1 75627 0 0 1244 112710 0 412386 29133 1137676 0.1319 Gas MCF 187162 1050146 1.719 2.707 2.577 0.059 22792.717 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 50 389 0 55 0 1 11203462 0 1719176 20062942 0 21782118 410.2094 0 656466 0 0 0 0 -1 86374 0 0 319 122905 0 199689 409 1066161 0.0952 Gas MCF 209210 1051492 1.993 3.138 2.984 0.059 19635.273 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 47 156 0 55 0 1 1846000 6294 2318339 18129908 0 20454541 385.2079 14911 80879 0 0 0 0 940 0 0 0 269 126113 0 1628317 41487 1892916 1.0254 Gas MCF 63479 1044320 0.809 1.274 1.220 0.044 35911.452 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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 86 2800 0 88 0 4 144051544 0 481503 41930089 0 42411592 321.2999 74456 5684515 0 0 0 0 0 70264 0 0 4747 1786022 0 901913 28998 8550915 0.0594 Gas MCF 1413639 1049818 2.554 4.021 3.830 0.039 10302.315 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 88 3367 0 88 0 5 167005295 10962 6028958 72614406 0 78654326 595.8661 32294 6712017 0 0 0 0 0 30475 0 0 4642 103118 0 963823 27932 7874301 0.0472 Gas MCF 1667134 1049234 2.557 4.026 3.837 0.040 10474.001 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 84 2837 0 88 0 3 180167119 1379 2152140 41281534 0 43435053 329.0534 121243 7151089 0 0 0 0 0 114417 0 0 5451 82095 0 1122135 -1367 8595063 0.0477 Gas MCF 1621855 1048194 2.801 4.409 4.206 0.040 9435.792 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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 573.10 366 18204 0 492 0 33 2068551325 1846217 20270858 274749638 0 296866713 518.0016 130674 71112860 0 0 0 0 1865178 4879054 0 0 66673 713957 0 3732461 534773 83035630 0.0401 Gas MCF 13954541 2072634 3.237 5.096 4.917 0.034 6991.103 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 567.20 362 19923 0 492 0 14 2327749433 338563 3717315 239852239 0 243908117 430.0214 106609 79208202 0 0 0 0 1865178 3980542 0 0 64780 583091 0 3133814 427428 89369644 0.0384 Gas MCF 15792048 2073229 3.186 5.016 4.839 0.034 7032.647 Page 403.5 Nuclear Under 50% Outdoors 1986 1988 410.82 405 8018 0 382 0 221 3049084272 1756354 335841110 845707512 39002466 1222307442 2975.2871 8315329 24492485 13628445 4194052 0 0 2867780 14221142 7586405 0 1604012 824520 6909857 4918683 1326793 90889503 0.0298 0 0 0.000 0.000 0.000 0.000 0.000 Nuclear Kg Uranium 476 66704 2803.917 51417.892 0.781 0.008 10283.848 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) 05/09/2018 This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report End of 2017/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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 Comparative 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 Comparative 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 Comparative Financial Statements. FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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) 05/09/2018 This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Year/Period of Report 2017/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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/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) Page 408 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report End of 2017/Q4 PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued) 6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. 7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract. FERC Licensed Project No. Plant Name: (c) FERC Licensed Project No. Plant Name: (d) FERC Licensed Project No. Plant Name: (e) Line No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 FERC FORM NO. 1 (REV. 12-03) Page 409 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 (2) X A Resubmission GENERATING PLANT STATISTICS (Small Plants) 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/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 1.02 60 7,344,544 3 Star 1998 0.22 564 2,048,571 4 Tempe 1998 0.01 5 Glendale Airport 1999 0.07 95 114,593 6 Gilbert 2001 0.12 224 56,928 7 Scottsdale Covered Parking 1999 0.29 518 557,305 8 Municipal Rooftops 1999 9 Yuma 2002 0.17 306 562,311 2002 0.18 391 162,310 10 Prescott Earu 38,661 51,361 11 Prescott 2001 2.71 4,234 2,393,945 12 Red Rock 2016 40.00 121,258 89,904,203 13 Phoenix 1998 9.21 64 32,338,850 14 Hyder I 2011 16.00 38,483 73,340,993 15 Hyder II 2013 14.00 36,400 51,811,899 16 Cotton Center 2011 17.00 32,594 80,506,466 17 Paloma 2011 17.00 38,592 66,071,021 18 Us Airways Center 2011 0.18 341 1,350,091 19 Chase Field 2011 0.06 70 1,284,717 20 Chino Valley 2012 19.00 41,738 86,992,112 21 Foothills I & II 2013 35.00 95,588 143,313,165 22 APS Solar For Schools 2012 12.72 21,608 52,045,363 23 DVN1 2013 0.02 41 24 Palo Verde Emergency Ops Center 2013 0.03 62 25 Gila Bend I 2014 16.00 50,265 55,077,128 26 Gila Bend II 2014 16.00 49,933 55,077,128 10.00 17,273 32,362,873 27 Carol Spring 2015 28 Desert Star 2015 29 Luke AFB 2015 528,504 30 Total Solar Operation/Maint. 10.00 29,442 30,668,105 237.02 580,142 866,003,145 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 FERC FORM NO. 1 (REV. 12-03) Page 410 This Report Is: Name of Respondent Date of Report Year/Period of Report (Mo, Da, Yr) 2017/Q4 End of Arizona Public Service Company 05/09/2018 (2) X A Resubmission GENERATING PLANT STATISTICS (Small Plants) (Continued) 3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant. 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Plant Cost (Incl Asset Retire. Costs) Per MW (g) Operation Exc'l. Fuel (h) Production Expenses Fuel (i) Maintenance (j) Kind of Fuel (k) Fuel Costs (in cents Line (per Million Btu) No. (l) 1 7,197,894 2 9,144,098 3 6,620,113 4 1,598,678 5 494,169 6 1,949,708 7 8 3,389,701 9 880,587 10 881,922 11 2,247,605 12 3,511,085 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 4,091,153 22 23 24 3,442,320 25 3,442,320 26 3,236,287 28 3,066,811 29 27 3,653,770 5,048,014 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 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 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION LINE STATISTICS Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. 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 PALO VERDE DELANEY FOUR CORNERS YAVAPAI WESTWING CHOLLA PLANT LIBERTY LIBERTY LIBERTY COCONINO VERDE ROUND VALLEY PINNACLE PEAK EL SOL AGUA FRIA OCOTILLO PLANT OCOTILLO PLANT VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 345.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 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 DELANEY SUN VALLEY 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 Designed (d) 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 500.00 345.00 230.00 345.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 (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 (A) (3) STEEL (A) (3) STEEL (C) (1) STEEL (3) STEEL (D) (2) WOOD (3) STEEL (D) (1) WOOD (1) WOOD (1) WOOD (1) WOOD (1) WOOD (3) STEEL (3) STEEL (3) STEEL (3) STEEL (4) U.G. 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 10.30 881.15 85 256.00 76.00 180.00 206.00 47.00 120.00 242.70 13.30 0.25 18.50 35.68 111.50 14.70 28.30 566.00 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 5,305.11 (h) 1 1 1 1 1 1 1 1 1 1 1 1 2 1 1 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: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION LINE STATISTICS Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. 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 OCOTILLO PLANT KYRENE OCOTILLO PLANT 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 SUN VALLEY PALM VALLEY TUBA CITY TAP SAGUARO PLANT ORACLE VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 69.00 69.00 115.00 115.00 SRP TAP KYRENE SUB KNOX 68th ST & SALT RIVER 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 TRILBY WASH TRILBY WASH POWELL SUB SAN MANUEL SAN MANUEL Designed (d) 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 230.00 115.00 (1) STEEL (1) STEEL (A) (3) STEEL (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 (3) STEEL (1) STEEL (2) WOOD (2) WOOD (2) WOOD TOTAL 36 FERC FORM NO. 1 (ED. 12-87) LENGTH (Pole miles) (In the case of underground lines report circuit miles) Supporting On Structure On Structures of Another of Line Structure Line Designated (e) (g) (f) Type of Page 422.1 6.50 4.38 (h) 2 1.60 1 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 1 881.15 85 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 36.53 1.67 12.00 9.00 11.90 0.16 0.17 20.48 3.30 3.30 0.75 14.13 15.90 60.00 41.50 21.06 5,305.11 Number Of Circuits Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION LINE STATISTICS Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. 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 ADAMS SANTA ROSA ASARCO ASARCO WILLOW LAKE UNDERGROUND OVERHEAD RELATED TRANSMISSION EHV STRUCTURES TEMP VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase) To (b) Operating (c) 115.00 115.00 115.00 115.00 115.00 69.00 69.00 MURAL ASARCO VISTA VISTA BAGDAD Designed (d) 115.00 115.00 115.00 115.00 115.00 69.00 69.00 (2) WOOD (2) WOOD (2) WOOD (1) WOOD (2) WOOD TOTAL 36 FERC FORM NO. 1 (ED. 12-87) LENGTH (Pole miles) (In the case of underground lines report circuit miles) Supporting On Structure On Structures of Another of Line Structure Line Designated (e) (g) (f) Type of Page 422.2 47.15 11.00 3.81 3.02 49.00 31.57 2,770.27 1.64 5,305.11 Number Of Circuits (h) 1 1 1 1 1 30.58 1 881.15 85 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material (i) 1780 ACSR 1780 ACSR 2156 ACSR 2156 ACSR 2156 ACSR 2156 ACSR 2156 ACSR 1780 ACSR 2156 ACSR 1590 KCM 1590 KCM 954 ACSR 1780 ACSR 1780 ACSR 1780 ACSR 1780 ACSR 2156 ACSR 2156 ACSR 1780 ACSR 1780 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 EXPENSES, EXCEPT DEPRECIATION AND TAXES Land rights, and clearing right-of-way) Land (j) 4,014,276 2,321,510 743,746 1,347,761 1,350,823 8,522 661,631 1,175,680 50,610 12,237,938 354,415 14,724,560 4,939,865 8,660,805 4,744,391 515,099 138,023 40,721 322,268 803,802 35,944 157,325 7,663 12,147,022 220,297 112,180 820,160 182,536,971 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 8,926,601 1,208,159 5,891,070 60,391,579 5,151,452 4,751,077 17,090,839 626,769 23,915,404 5,971,160 42,238,623 9,670,347 1,208,159 7,238,831 61,742,402 5,159,974 5,412,708 18,266,519 677,379 29,540,970 1,027,221 32,395,319 3,178,473 104,642,446 14,863,356 35,211,578 30,649,195 947,577 3,424,030 4,531,616 5,084,497 2,207,232 3,352,137 3,761,039 3,250,560 2,252,013 7,704,155 536,518 3,218,080 6,759,381 1,826,612 41,778,908 1,381,636 47,119,879 3,178,473 104,642,446 19,803,221 43,872,383 35,393,586 947,577 3,939,129 4,669,639 5,125,218 2,529,500 4,155,939 3,796,983 3,407,885 2,259,676 19,851,177 756,815 3,330,260 7,579,541 1,826,612 1,268,664,768 1,451,201,739 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 30,877,684 423 5,529,090 7,719,039 44,125,813 36 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material (i) 954 ACSR 954 ACSR 954A/1113A 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 ACSS 2156 KCMIL 954 ACSR 954 ACSR 556 ACSR EXPENSES, EXCEPT DEPRECIATION AND TAXES Land rights, and clearing right-of-way) Land Construction and Other Costs (k) (j) 1,749,240 91,269 Total Cost Operation Expenses (m) (l) 3,042,380 486,722 17,978 3,283,837 3,628,837 1,324,874 203,127 869,381 4,791,620 577,991 17,978 3,321,098 4,012,559 1,611,847 374,308 1,012,053 46,640 74,057 2,785,385 6,122,495 5,672,649 1,669,401 4,171,221 1,601,133 6,704,094 1,203,882 4,485,834 4,206,368 7,441,633 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 21,022,026 22,953,329 2,380,164 1,972,623 3,113,685 2,854,367 7,144,077 5,757,743 1,711,637 4,561,653 1,679,562 7,223,112 1,585,729 5,419,295 4,347,567 7,794,017 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 39,017,549 41,629,607 2,380,164 2,019,263 3,187,742 182,536,971 1,268,664,768 1,451,201,739 37,261 383,722 286,973 171,181 142,672 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 8,241,786 6,332,845 17,995,523 18,676,278 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 30,877,684 423.1 5,529,090 7,719,039 44,125,813 36 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material (i) 556 ACSR 795 ACSR 795 ACSR 795 ACSR 795 ACSR EXPENSES, EXCEPT DEPRECIATION AND TAXES Land rights, and clearing right-of-way) Land (j) 435,033 93,110 18,029 12,019 365,101 38,658,597 21,621 182,536,971 FERC FORM NO. 1 (ED. 12-87) Construction and Other Costs (k) 2,115,819 433,334 392,494 229,551 3,055,685 54,140,798 562,350,363 5,328,484 315,726 1,268,664,768 Total Cost Operation Expenses (m) (l) Maintenance Expenses (n) Rents (o) 2,550,852 526,444 410,523 241,570 3,420,786 54,140,798 601,008,960 5,350,105 315,726 1,451,201,739 Page 30,877,684 5,529,090 7,719,039 30,877,684 5,529,090 7,719,039 423.2 Total Expenses (p) Line No. 1 2 3 4 5 6 7 8 9 44,125,813 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 44,125,813 36 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 FOOTNOTE DATA Schedule Page: 422.2 Line No.: 8 Column: a INCLUDES MINOR NAVAJO UNITS 1, 2, 3, FOUR CORNERS COMMON UNITS 1, 2, 3, PALO VERDE UNITS 1, 2, 3, REDHAWK COMBINED CYCLE UNITS 1 AND 2, AND WEST PHOENIX PLANT TO WEST PHOENIX COMBINED CYCLE RELATED TRANSMISSION Schedule Page: 422.2 Line No.: 10 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: Page 422 LINE# 4 - NAVAJO PLANT TO WESTWING Page 422 LINE# 5 - NAVAJO PLANT TO MOENKOPI Page 422 LINE# 6 - MOENKOPI TO WESTWING Page 422 LINE# 8 - PALO VERDE TO WESTWING Page 422 LINE# 9 - PALO VERDE TO NORTH GILA Page 422 LINE#10 - WESTWING TO MEAD Page 422 LINE#11 - MEAD TO MARKET PLACE Page 422 LINE# 1 - PALO VERDE TO KYRENE Page 422 LINE# 2 - PALO VERDE TO WESTWING #2 Page 422 LINE#14 - PALO VERDE TO RUDD Page 422 LINE#15 - PALO VERDE TO HASSAYAMPA Page 422 LINE #16 - MORGAN TO PINNACLE PEAK Page 422 LINE #18 - HASSAYAMPA TO NORTH GILA Page 422 LINE #19 - PALO VERDE TO DELANEY Page 422 LINE #20 - DELANEY TO SUN VALLEY Page 422.1 LINE #2 KYRENE TO KNOX 1. CO-OWNERS OF LINES 1, 2, 8, AND 15 ON PAGE 422 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, PUBLIC SERVICE OF NEW MEXICO, AND ARIZONA PUBLIC SERVICE COMPANY 2. CO-OWNERS OF LINES 4 & 6 ON PAGE 422 ARE SALT RIVER PROJECT, TUCSON ELECTRIC POWER, U.S. ELECTRIC DEPARTMENT OF ENERGY, AND ARIZONA PUBLIC SERVICE COMPANY 3. CO-OWNERS OF LINE 5 ON PAGE 422 ARE SALT RIVER PROJECT, TUCSON ELECTRIC POWER, NEVADA POWER COMPANY, LOS ANGELES DEPARTMENT OF WATER AND POWER, U.S. DEPARTMENT OF ENERGY AND ARIZONA PUBLIC SERVICE COMPANY 4. CO-OWNERS OF LINE 9 ON PAGE 422 ARE THE IMPERIAL IRRIGATION DISTRICT, SAN DIEGO GAS AND ELECTRIC, AND ARIZONA PUBLIC SERVICE COMPANY 5. CO-OWNERS OF LINES 10 & 11 ON PAGE 422 ARE M-S-R PUBLIC POWER AGENCY, SALT RIVER PROJECT, CITY OF VERNON, SOUTHERN CALIFORNIA PUBLIC AUTHORITY, U.S. DEPARTMENT OF ENERGY AND ARIZONA PUBLIC SERVICE COMPANY FERC FORM NO. 1 (ED. 12-87) Page 450.1 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent Arizona Public Service Company This Report is: (1) An Original (2) X A Resubmission Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 FOOTNOTE DATA 6. CO-OWNERS OF LINE 18 ON PAGE 422 ARE THE IMPERIAL IRRIGATION DISTRICT AND ARIZONA PUBLIC SERVICE COMPANY ARIZONA PUBLIC SERVICE COMPANY 7. CO-OWNERS OF LINES 19 AND 20 ON PAGE 422 ARE CENTRAL ARIZONA PROJECT AND ARIZONA PUBLIC SERVICE COMPANY 8. CO-OWNERS OF LINES 14 & 16 ON PAGE 422 AND LINE 2 ON PAGE 422.1 ARE SALT RIVER PROJECT AND ARIZONA PUBLIC SERVICE COMPANY 9. EXPENSES TO OPERATE THESE LINES ARE ALLOCATED TO PARTICIPANTS BASED ON OWNERSHIP AS SET FORTH IN OPERATION AND MAINTENANCE AGREEMENTS 10. 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 SEGREGATED IN THE COMPANY'S BOOKS FOR EACH TRANSMISSION LINE FERC FORM NO. 1 (ED. 12-87) Page 450.2 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Year/Period of Report 2017/Q4 End of (2) X A Resubmission TRANSMISSION LINES ADDED DURING YEAR 1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. 2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the Line No. LINE DESIGNATION From To (a) (b) Line Length in Miles (c) SUPPORTING STRUCTURE Average Type Number per Miles (d) (e) CIRCUITS PER STRUCTURE Present Ultimate (f) (g) 1 OVERHEAD RAINTREE 1.40 STEEL 18.00 1 1 3 HOHOKAM POLK 1.02 STEEL 27.00 1 1 4 CACTUS ALTADENA 4.05 STEEL 12.00 1 2 2.02 STEEL & WOOD 22.00 1 1 79.00 4 5 2 EASTEND 5 PEBBLE CREEK/PALM VLLY PIMA TAP 6 7 UNDERGROUND 8 EASTEND 0.89 RAINTREE 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 9.38 44 TOTAL FERC FORM NO. 1 (REV. 12-03) Page 424 Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission TRANSMISSION LINES ADDED DURING YEAR (Continued) Year/Period of Report 2017/Q4 End of costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m). 3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic. CONDUCTORS Size Specification (h) (i) Configuration and Spacing (j) Voltage KV (Operating) (k) Land and Land Rights (l) LINE COST Poles, Towers Conductors Asset and Fixtures and Devices Retire. Costs (n) (o) (m) Total Line No. (p) 1 R795X ACSS Various 69 3,845,370 1,648,016 5,493,386 2 R795X ACSS Various 69 1,382,774 592,618 1,975,392 3 Various 69 976,286 418,409 1,394,695 4 Various 69 611,815 262,207 874,022 5 R795X&795 R795X ACSS 6 7 2500 KCMIL PARALLEL 69 678,321 290,709 969,030 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 7,494,566 FERC FORM NO. 1 (REV. 12-03) Page 425 3,211,959 10,706,525 44 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 424 Line No.: 2 Column: j SINGLE CKT/DELTA Schedule Page: 424 Line No.: 3 Column: j SINGLE CKT/DELTA Schedule Page: 424 Line No.: 4 Column: i Line No.: 4 Column: j ACSS & ACCS_C7 Schedule Page: 424 DOUBLE CRKT/VERTICAL Schedule Page: 424 Line No.: 5 Column: j SINGLE CKT/DELTA FERC FORM NO. 1 (ED. 12-87) Page 450.1 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 ANITA - COCONINO D 69.00 12.00 10 ANTELOPE - PRESCOTT D 69.00 12.00 11 AQUEDUCT - PHOENIX D 69.00 4.16 12 ARABY - YUMA D 69.00 12.00 13 ARICA - ELOY D 69.00 12.00 14 ARLINGTON - MARICOPA COUNTY D 69.00 12.00 15 ARROWHEAD - GLENDALE D 69.00 12.00 16 ARROYO - PHOENIX D 69.00 12.00 17 ASARCO PIT - CASA GRANDE D 69.00 12.00 18 ASHFORK - ASHFORK D 69.00 12.00 19 AZTEC - DATELAND D 69.00 12.00 20 BACON - N.W. OF SNOWFLAKE D 69.00 12.00 21 BADGER SUB - TONOPAH D 69.00 12.00 22 BAGDAD NEW TOWN - BAGDAD T 115.00 12.00 23 BAGDAD 115kV CAP. - BAGDAD T 115.00 24 BAJA - SAN LUIS D 69.00 12.00 25 BALD MOUNTAIN - PRESCOTT VALLEY D 69.00 12.00 26 BALD MOUNTAIN - PRESCOTT VALLEY D 69.00 27 BASELINE - BUCKEYE D 69.00 12.00 28 BEARDSLEY - SURPRISE D 69.00 12.00 29 BELL - PEORIA D 69.00 12.00 30 BISCUIT FLATS - PHOENIX D 69.00 31 BLACK MESA #2 - GRAY MOUNTAIN D 69.00 32 BLACK PEAK(BOUSE APA) - PARKER T 161.00 69.00 33 BLACK PEAK(BOUSE APA) - PARKER D 69.00 12.00 34 BLUE RIDGE - BLUE RIDGE D 69.00 21.60 35 BLUE WATER - N. OF PARKER D 34.50 12.00 36 BONNEYBROOK - FLORENCE D 115.00 12.00 37 BOOTHILL - E. OF TOMBSTONE D 115.00 21.00 38 BOULEVARD - SCOTTSDALE D 69.00 12.00 39 BUCKEYE - BUCKEYE T 230.00 69.00 40 BUCKEYE - BUCKEYE D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426 Tertiary (e) 12.40 12.00 12.00 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 BUFFALO - PHOENIX D Primary (c) 69.00 2 BUNYAN - NW. OF GILA BEND D 69.00 12.00 Secondary (d) 12.00 3 BUTTE - TEMPE D 69.00 12.00 4 CACTUS-SCOTTSDALE T 230.00 69.00 5 CACTUS-SCOTTSDALE D 69.00 12.00 6 CALDERWOOD - PEORIA D 69.00 12.00 7 CAMELBACK - SCOTTSDALE D 69.00 12.00 8 CAMERON - CAMERON D 69.00 12.00 9 CANAL - PHOENIX D 69.00 12.00 10 CAPITAL BUTTE - SEDONA D 69.00 12.00 11 CASA GRANDE - CASA GRANDE T 230.00 69.00 12 CASA GRANDE - CASA GRANDE T 230.00 12.00 13 CASA GRANDE - CASA GRANDE D 69.00 12.00 12.00 14 CAVE CREEK - CAVE CREEK D 69.00 15 CEDAR MOUNTAIN - WILLIAMS T 525.00 16 CENTURY - SCOTTSDALE D 69.00 12.00 17 CHANDLER - CHANDLER D 69.00 12.00 18 CHAPARRAL - SCOTTSDALE D 69.00 12.00 19 CHERYL - PHOENIX D 69.00 12.00 20 CHILDS - CAMP VERDE D 69.00 Tertiary (e) 12.00 12.00 21 CHINO VALLEY - CHINO VALLEY D 69.00 12.00 22 CHOLLA - JOSEPH CITY A,T 525.00 345.00 34.50 23 CHOLLA - JOSEPH CITY A,T 525.00 24 CHOLLA - JOSEPH CITY A,T 345.00 230.00 12.00 25 CHOLLA - JOSEPH CITY A,T 345.00 69.00 26 CHOLLA - JOSEPH CITY A,T 230.00 69.00 27 CIELO GRANDE - PHOENIX D 69.00 12.00 28 CLINIC - SCOTTSDALE D 69.00 12.00 29 COCONINO - FLAGSTAFF T 230.00 69.00 30 COCONINO - FLAGSTAFF D 69.00 12.00 31 COCOPAH - W. OF YUMA D 69.00 12.00 32 COLDWATER - GOODYEAR D 69.00 12.00 33 COLORADO - N. OF PARKER D 69.00 12.00 34 COLTER - AVONDALE D 69.00 12.00 35 COMMERCE - PHOENIX D 69.00 12.00 36 CONLEY - SNOWFLAKE T 69.00 37 COOLIDGE - N. OF COOLIDGE D 12.40 38 COPPER CANYON - N. OF CAMP VERDE D 69.00 12.00 39 CORDES - CORDES JUNCTION D 69.00 12.00 40 CORNVILLE - CORNVILLE 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 (a) 1 COTTON CENTER - N. OF GILA BEND 2 COTTONWOOD - COTTONWOOD Character of Substation D Primary (c) 69.00 Secondary (d) 12.00 D 69.00 12.00 (b) 3 COTTONWOOD - COTTONWOOD D 4 COUNTRY CLUB - PHOENIX D 69.00 12.00 5 COUNTRY CLUB - PHOENIX T 230.00 69.00 69.00 12.00 6 COUNTY LINE - TONOPAH D 7 COUNTY LINE - TONOPAH D 8 CROSSROADS - N. OF PARKER D 34.50 12.00 9 DAISY MOUNTAIN - PHOENIX D 69.00 12.00 D 69.00 12.00 10 DALE - SCOTTSDALE 11 DALE - SCOTTSDALE D 69.00 12 DAVENPORT - E OF WILLIAMS D 69.00 12.00 13 DEADMAN WASH - PHOENIX D 69.00 12.00 14 DEADMAN WASH - PHOENIX D 69.00 15 DEER VALLEY - PHOENIX T 230.00 69.00 16 DEER VALLEY - PHOENIX D 69.00 12.00 17 DEL RIO - PEORIA D 69.00 12.00 18 DELANEY - TONOPAH T 525.00 69.00 19 DELANO - PRESCOTT D 69.00 12.00 20 DESERT RIDGE - SCOTTSDALE D 69.00 12.00 21 DESERT SANDS - YUMA T 69.00 22 DESERT SKY - BUCKEYE D 69.00 12.00 23 DESERT SPRINGS - PHOENIX D 69.00 12.00 24 DEWEY - N. OF DEWEY D 69.00 12.00 25 DIXILETA - N. OF SCOTTSDALE D 69.00 12.00 26 DON LUIS - BISBEE D 69.00 12.00 27 DOUBLETREE - PHOENIX D 69.00 12.00 28 DOVE VALLEY - PHOENIX D 69.00 12.00 29 DOWNING - SCOTTSDALE D 69.00 12.00 30 DRAKE - PAULDEN D 69.00 31 DRY LAKE - HOLBROOK D 69.00 7.20 32 DUGAS - MAYER T 525.00 69.00 33 DUGAS - MAYER T 525.00 34 DURANGO - PHOENIX D 69.00 12.00 35 DYSART - SURPRISE D 69.00 12.00 36 EAGLE EYE - W. OF AGUILA T 230.00 69.00 37 EAST END - SCOTTSDALE D 69.00 12.00 38 EASTERN OFFICE - PHOENIX D 69.00 12.00 39 EASTGATE - CASA GRANDE D 69.00 12.00 40 EGG RANCH - TONOPAH 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 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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) 34.50 Secondary (d) 12.00 T 230.00 69.00 3 EL SOL - YOUNGTOWN D 69.00 12.00 4 ELDEN - FLAGSTAFF D 69.00 12.00 5 ENCANTO - PHOENIX D 69.00 12.00 6 ESTRELLITA - GOODYEAR D 69.00 12.00 7 EVANS CHURCHILL - PHOENIX D 69.00 12.00 8 FAIRVIEW - N. OF DOUGLAS D 69.00 12.00 9 FARMER - SURPRISE T 69.00 10 FESTIVAL RANCH - BUCKEYE D 69.00 12.00 11 FILLMORE - PHOENIX D 69.00 12.00 12 FISH SAWMILL - N. OF FLAGSTAFF D 69.00 12.00 13 FLORES - CONGRESS D 69.00 12.00 14 FLYING E - WICKENBURG D 69.00 12.00 15 FOOTHILLS - YUMA D 69.00 12.00 (a) 1 EHRENBERG - EHRENBERG 2 EL SOL - YOUNGTOWN (b) Tertiary (e) 12.00 16 FORTIETH PLACE - PHOENIX D 69.00 12.00 17 FOUR CORNERS - FRUITLAND, NM A,T 525.00 345.00 14.00 18 FOUR CORNERS - FRUITLAND, NM A,T 345.00 230.00 14.40 19 FOUR CORNERS - FRUITLAND, NM A,T 230.00 69.00 4.16 20 GARFIELD - PHOENIX D 69.00 12.00 21 GARLAND PRAIRIE - E. OF WILLIAMS D 69.00 12.00 22 GATEWAY - PHOENIX D 69.00 12.00 23 GAVILAN PEAK - PHOENIX T 230.00 69.00 24 GAVILAN PEAK - PHOENIX D 69.00 12.00 25 GILA BEND - GILA BEND T 230.00 69.00 26 GILA BEND - GILA BEND D 69.00 12.00 27 GILBERT - GILBERT D 69.00 12.00 28 GILLESPIE#1 - BUCKEYE D 69.00 12.00 29 GLENDALE - GLENDALE D 230.00 12.00 30 GRAND CANYON - GRAND CANYON D 69.00 12.00 31 GRANITE CREEK - CHINO VALLEY T 69.00 32 GRANITE REEF - SCOTTSDALE D 69.00 12.00 33 GRAY MOUNTAIN - CAMERON D 69.00 21.60 34 GREENBRIER - GLENDALE D 69.00 12.00 35 GREENWAY - GLENDALE D 69.00 12.00 36 GREY BEARS - CHINO VALLEY D 69.00 12.00 37 GRISWOLD - PHOENIX D 69.00 12.00 38 HAMBLIN - CAMERON D 69.00 12.00 39 HANKS - N. OF FLAGSTAFF D 69.00 12.00 40 HAPPY VALLEY TEMP - PEORIA D 69.00 12.00 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 HARBOR - PHOENIX D Primary (c) 69.00 2 HARQUAHALA - TONOPAH D 69.00 Secondary (d) 12.00 12.00 3 HASHKNIFE - HEBER D 69.00 4 HATFIELD - PEORIA D 69.00 12.00 5 HAVASU - PARKER D 69.00 12.00 6 HAYDEN - HAYDEN D 21.00 7.00 7 HAYES GULCH - GLOBE D 69.00 21.00 8 HEARN - SURPRISE D 69.00 12.00 9 HEDGEPETH HILLS - PHOENIX D 69.00 12.00 D 69.00 12.00 12.00 10 HOHOKAM - PHOENIX 11 HONEYWELL - PHOENIX D 69.00 12 HOODOO WASH - DATELAND T 525.00 13 HORN - HORN D 69.00 12.00 14 HOWARD MESA - WILLIAMS D 69.00 12.00 15 HUMBUG - PEORIA D 69.00 12.00 16 HYDER - DATELAND D 69.00 12.00 17 INDIAN BEND - PHOENIX D 69.00 12.00 18 INDIANOLA - PHOENIX D 69.00 12.00 19 IVALON - YUMA D 69.00 12.00 20 JACKSON STREET - PHOENIX D 69.00 12.00 21 JAVELINA - SURPRISE D 69.00 12.00 22 JOMAX - SCOTTSDALE D 69.00 12.00 23 KACHINA - KACHINA VILLAGE D 69.00 12.00 24 KAIBAB - WILLIAMS D 69.00 12.00 25 KEAMS CANYON - W. OF KEAMS CANYON D 69.00 21.00 26 KEARNY - KEARNY D 21.00 27 KIRKLAND JUNCTION - SE.OF KIRKLAND D 69.00 12.00 28 LAGUNA - SOMERTON D 69.00 12.00 29 LE BARRON HILL - FLAGSTAFF D 69.00 7.20 30 LEROUX - N. OF HOLBROOK D 69.00 12.00 31 LEUPP JUNCTION - W. OF WINSLOW D 69.00 21.00 32 LIBERTY IRON - PHOENIX D 69.00 33 LINCOLN STREET (230kV) - PHOENIX T 230.00 69.00 34 LINCOLN STREET NORTH - PHOENIX D 69.00 12.00 35 LINCOLN STREET WEST - PHOENIX D 69.00 12.00 36 LITCHFIELD - LITCHFIELD PARK D 69.00 12.00 37 LOMA VISTA - PHOENIX D 69.00 12.00 38 LONE PEAK - PHOENIX T 230.00 69.00 39 LONE PEAK - PHOENIX D 69.00 12.00 40 LONESOME VALLEY - PRESCOTT D 69.00 12.00 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) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 LOOKOUT - PHOENIX D Primary (c) 69.00 2 LUKE FIELD NORTH - LUKE AFB D 69.00 3 MAGNOLIA - STANTON D 69.00 7.20 4 MARINE AIR BASE - YUMA D 69.00 12.00 5 MARINETTE - SUN CITY D 69.00 12.00 6 MARTINEZ WASH - WICKENBURG D 69.00 7.20 7 MAZATZAL - RYE D 69.00 21.00 8 MCGUIREVILLE - RIM ROCK D 69.00 12.00 9 MCCORMICK - SCOTTSDALE D 69.00 12.00 D 69.00 12.00 10 MCDOWELL - PHOENIX Secondary (d) 12.00 12.00 11 MCMICKEN - SURPRISE D 69.00 12.00 12 MEADOWBROOK - PHOENIX T 230.00 69.00 13 MEADOWBROOK - PHOENIX D 69.00 12.00 14 MERIDIAN - GLENDALE D 69.00 15 MERRILL - FLORENCE D 69.00 12.00 12.00 16 METRO - PHOENIX D 69.00 17 MILLER WASH - VALLE D 69.00 7.20 18 MILLIGAN - ELOY T 230.00 69.00 19 MILLIGAN TEMP - ELOY D 69.00 12.00 20 MINGUS - JEROME D 69.00 7.20 12.00 21 MITTRY - YUMA D 69.00 22 MOENKOPI - CAMERON T 525.00 23 MOENKOPI - CAMERON T 525.00 24 MONTE CRISTO - PHOENIX D 69.00 12.00 25 MOON VALLEY - PHOENIX D 69.00 12.00 26 MORGAN - PEORIA T 525.00 230.00 27 MORRISTOWN - MORRISTOWN D 69.00 12.00 28 MOUNTAIN VIEW - SUN CITY D 69.00 12.00 29 MT. FLOYD - SELIGMAN T 230.00 12.00 30 MUMMY MOUNTAIN - PARADISE VALLEY D 69.00 12.00 31 MUNDS PARK - S.OF FLAGSTAFF D 69.00 21.00 32 MURAL - BISBEE D 69.00 12.00 33 MURAL - BISBEE T 115.00 69.00 69.00 7.20 34 NADASY - N. OF WILLIAMS D 35 NAVAJO - PAGE A,T 525.00 36 NAVAJO - PAGE A,T 525.00 37 NAVAJO ARMY DEPOT - FLAGSTAFF D 69.00 12.00 38 NEW RIVER - NEW RIVER D 69.00 12.00 7.20 39 NEWMAN PARK - S. OF FLAGSTAFF D 69.00 40 NORTH GILA - YUMA T 525.00 FERC FORM NO. 1 (ED. 12-96) Page 426.5 Tertiary (e) 12.00 12.00 34.50 12.00 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 NORTH GILA - YUMA T Primary (c) 525.00 2 NORTH VALLEY - PHOENIX D 69.00 12.00 3 OAK CREEK - OAK CREEK D 69.00 12.00 4 OBERLIN TEMP - SURPRISE D 69.00 12.00 5 OCOTILLO - TEMPE A,T 230.00 69.00 6 OCOTILLO - TEMPE A,T 230.00 7 OCOTILLO - TEMPE A,T 69.00 Secondary (d) 69.00 8 OLD HOME MANOR - CHINO VALLEY D 69.00 9 ORANGEWOOD - PHOENIX D 69.00 12.00 10 ORMES - MAYER D 69.00 4.16 11 OSBORNE TANK - FLAGSTAFF D 69.00 12.00 12 PADRE - FLAGSTAFF D 69.00 12.00 13 PALM VALLEY - GOODYEAR T 230.00 69.00 14 PALM VALLEY - GOODYEAR D 69.00 12.00 15 PALOMA - W. OF GILA BEND D 69.00 12.00 69.00 12.00 16 PALOMINAS -HEREFORD D 17 PANDA - GILA BEND A,T 18 PAPAGO BUTTE - SCOTTSDALE D 69.00 12.00 19 PARADISE - PHOENIX D 69.00 12.00 20 PARKS - PARKS D 69.00 12.00 21 PATTERSON - OUT OF BUCKEYE D 69.00 12.00 22 PATTON - OUT OF MORRISTON D 69.00 12.00 23 PAULDEN - PAULDEN D 69.00 12.00 24 PEBBLECREEK - GOODYEAR D 69.00 12.00 25 PEORIA - PEORIA D 69.00 12.00 Tertiary (e) 34.50 12.00 12.00 230.00 26 PERRYVILLE - PERRYVILLE D 69.00 12.00 27 PICKET - SUPERIOR T 115.00 12.00 28 PIMA - GOODYEAR D 69.00 12.00 29 PINAL - GLOBE T 115.00 69.00 30 PINAL - GLOBE D 69.00 21.00 21.00 31 PINE SPRINGS - W. OF WILLIAMS D 69.00 7.20 32 PINNACLE PEAK - PHOENIX T 525.00 230.00 34.50 33 PINNACLE PEAK - PHOENIX T 345.00 230.00 14.40 34 PINNACLE PEAK - PHOENIX T 230.00 69.00 12.40 35 PIONEER - PHOENIX D 69.00 12.00 36 PLANET - NE. OF PARKER D 69.00 12.00 37 PLEASANT - GLENDALE D 69.00 12.00 38 POLAND JUNCTION - NW. OF MAYER D 69.00 12.00 39 POLK - PHOENIX D 69.00 12.00 40 POLK - PHOENIX D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.6 This Report Is: Name of Respondent Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 POLLOCK -CHINO VALLEY D Primary (c) 69.00 2 POPLAR WASH - PEEPLES VALLEY D 69.00 7.20 3 PREACHER CANYON - STAR VALLEY T 345.00 69.00 4 PREACHER CANYON - STAR VALLEY D 69.00 21.60 5 PRESCOTT CHINO WELLS - CHINO VALLEY D 69.00 4.60 6 PRESCOTT CHINO WELLS - CHINO VALLEY D 69.00 12.00 7 PRESCOTT CITY - PRESCOTT D 69.00 12.00 8 PYRAMID PEAK - GLENDALE D 69.00 12.00 9 QUAIL SPRINGS - SE. OF COTTONWOOD D 69.00 12.00 D 69.00 12.00 10 QUARTZSITE - QUARTZSITE Secondary (d) 12.00 11 QUECHAN - YUMA D 69.00 12.00 12 RACEWAY - PEORIA T 230.00 69.00 13 RAINBOW VALLEY - SE.OF BUCKEYE D 69.00 12.00 14 RAINTREE - SCOTTSDALE D 69.00 12.00 15 RAMON ASO - RED LAKE,N. OF WILLIAMS D 69.00 12.40 Tertiary (e) 12.00 12.40 16 RAWHIDE - SCOTTSDALE D 69.00 12.00 17 REACH - SCOTTSDALE T 230.00 69.00 18 RED LAKE - E. OF WILLIAMS D 69.00 21.00 19 RED ROCK - RED ROCK T 115.00 12.00 20 REDONDO - YUMA D 69.00 12.00 21 REIDHEAD - SNOWFLAKE D 69.00 7.20 22 RINCON - WICKENBURG D 69.00 7.20 23 RIO SALADO - TEMPE D 69.00 12.00 24 RIO VISTA - SUN CITY D 69.00 12.00 25 RIVERSIDE - YUMA D 69.00 12.00 26 ROAD RUNNER - PHOENIX D 69.00 12.00 27 ROBBINS BUTTE - OUT OF BUCKEYE D 69.00 12.00 28 ROCK SPRINGS - ROCK SPRINGS D 69.00 12.00 29 ROGERS LAKE - SW. OF FLAGSTAFF D 69.00 7.20 30 ROSE GARDEN - PHOENIX D 69.00 12.00 31 ROUND VALLEY - KINGMAN T 230.00 32 SADDLE MOUNTAIN - W. OF TONOPAH D 69.00 34 SADDLEBROOK - ORACLE T 115.00 35 SAGE VALLEY - VALLE D 69.00 12.00 36 SAGUARO 525kV - RED ROCK A,T 525.00 115.00 34.50 37 SAGUARO 230kV - RED ROCK A,T 230.00 115.00 12.40 38 SAGUARO 115kV - RED ROCK A,D 115.00 12.00 39 SALOME - S.E. OF SALOME D 69.00 12.00 40 SAN LUIS - SAN LUIS D 69.00 12.00 12.00 12.00 33 SADDLE MOUNTAIN - W. OF TONOPAH FERC FORM NO. 1 (ED. 12-96) Page 426.7 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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) 34.50 D 115.00 46.00 3 SAN MANUEL - SAN MANUEL D 115.00 12.00 4 SAN PEDRO - W. OF DOUGLAS D 69.00 12.00 5 SANDVIG - FLAGSTAFF D 69.00 12.00 (a) 1 SAN LUIS (MEXICO CONN.) - SAN LUIS 2 SAN MANUEL - SAN MANUEL (b) 6 SANGUINETTI - YUMA T 69.00 7 SANTA ROSA - SE. OF MARICOPA T 230.00 69.00 8 SARIVAL - GOODYEAR D 69.00 12.00 9 SEDONA - SEDONA D 69.00 12.00 10 SELIGMAN COMPRESSER STATION - SELIGMAN D 230.00 11 SHAW - PHOENIX D 69.00 12.00 12 SHEA - SCOTTSDALE D 69.00 12.00 13 SHERMAN STREET - PHOENIX D 69.00 12.00 14 SHOW LOW - SHOW LOW D 69.00 12.00 15 SHOW LOW - SHOW LOW D 69.00 16 SHUMWAY - SHOW LOW D 69.00 17 SHUMWAY - SHOW LOW D 69.00 18 SKUNK CREEK - GLENDALE D 69.00 12.00 19 SNOWFLAKE - SNOWFLAKE D 69.00 12.00 20 SOLDIERS TRAIL - FLAGSTAFF D 69.00 12.00 21 SONORA - SUPERIOR D 69.00 21.60 22 SOUTH O'NEIL - YUMA T 69.00 23 SPANISH GARDENS - SURPRISE D 69.00 24 SPIDER WEB - FLAGSTAFF D 69.00 4.16 25 STAGECOACH - SCOTTSDALE D 69.00 12.00 26 STANTON - S. OF YARNELL D 69.00 7.20 27 STARDUST - SUN CITY WEST D 69.00 28 STOUT - PHOENIX D 69.00 12.00 Tertiary (e) 12.40 12.00 12.00 29 STRAWBERRY - STRAWBERRY D 69.00 21.00 30 STURM RUGER - N. OF PRESCOTT D 69.00 4.16 12.40 31 STURM RUGER - N. OF PRESCOTT D 69.00 32 SUGARLOAF - SNOWFLAKE T 525.00 69.00 34.50 33 SUN VALLEY PARKWAY - BUCKEYE T 525.00 230.00 34.50 34 SUNDOG - PRESCOTT D 69.00 12.00 35 SUNNYSLOPE - PHOENIX T 230.00 69.00 13.80 36 SUNNYSLOPE - PHOENIX T 230.00 69.00 12.40 37 SUNNYSLOPE - PHOENIX D 69.00 12.40 38 SUNSHINE - WINSLOW D 69.00 12.00 39 SURPRISE - SURPRISE T 230.00 69.00 40 SURPRISE - SURPRISE D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.8 12.40 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 7.20 3 TABLE MESA - NEW RIVER D 69.00 7.20 4 TAPCO - E. OF CLARKDALE D 69.00 2.40 5 TARTESSO TEMPORARY - BUCKEYE D 69.00 12.00 6 TAT MOMOLI - CASA GRANDE T 230.00 7 TEMPE - TEMPE D 69.00 12.00 8 TENTH STREET - YUMA D 69.00 12.00 9 THAYER - THAYER D 69.00 12.00 10 THIRTY-SECOND STREET - YUMA D 69.00 12.00 11 THOMPSON PEAK - SCOTTSDALE D 69.00 12.00 12 TOLTEC - ELOY D 69.00 12.00 13 TONALEA - TUBA CITY D 69.00 21.60 14 TONOPAH - TONOPAH D 69.00 12.00 15 TONTO - PAYSON D 69.00 21.00 (a) 1 SWITZER CANYON - FLAGSTAFF 2 SYCAMORE - DUGAS (b) 16 TONTO - PAYSON D 69.00 17 TRIBLY WASH - SURPRISE T 230.00 69.00 18 TUBA CITY - TUBA CITY D 69.00 12.00 19 TURF - PHOENIX D 69.00 12.00 20 TUSAYAN -TUSAYAN D 69.00 12.00 21 TUSAYAN -TUSAYAN D 69.00 22 TUTHILL - BUCKEYE D 69.00 12.00 23 TWENTY - THIRD STREET-PHOENIX D 69.00 12.00 24 TWIN ARROWS - FLAGSTAFF T 69.00 25 UNION HILLS - PHOENIX D 69.00 12.00 26 UTTING - SE. OF BOUSE D 69.00 12.00 27 VALENCIA - BUCKEYE D 69.00 12.00 28 VALLE - WILLIAMS D 69.00 21.00 29 VALLEY FARMS - FLORENCE T 115.00 69.00 30 VALLEY FARMS - FLORENCE D 69.00 12.00 31 VARNEY - SURPRISE D 69.00 12.00 32 VERDE - CLARKDALE T 230.00 69.00 33 VICKSBURG - S. OF VICKSBURG JUNCTION D 69.00 12.00 34 VISTA - CASA GRANDE D 69.00 12.00 35 WADDELL - SURPRISE D 69.00 12.00 36 WALDRIP - YUMA T 69.00 37 WATSON - BUCKEYE D 69.00 12.00 38 WELCH - ASHFORK D 69.00 2.40 39 WELLFIELD - PRESCOTT VALLEY D 69.00 12.00 40 WENDON TEMP - LA PAZ D 69.00 12.00 FERC FORM NO. 1 (ED. 12-96) Page 426.9 Tertiary (e) 12.00 12.40 12.40 Name of Respondent This Report Is: Date of Report (Mo, Da, Yr) 05/09/2018 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS Year/Period of Report 2017/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 (a) 1 WEST PHOENIX - PHOENIX 2 WEST PHOENIX - PHOENIX Character of Substation T Primary (c) 230.00 Secondary (d) 69.00 D 69.00 12.40 (b) Tertiary (e) 12.40 3 WESTBROOK - PEORIA D 69.00 12.00 4 WESTWING - SUN CITY T 525.00 230.00 5 WESTWING - SUN CITY T 525.00 6 WESTWING - SUN CITY T 525.00 7 WESTWING - SUN CITY D 69.00 12.00 8 WESTWING - SUN CITY T 230.00 69.00 9 WHITE SPAR - PRESCOTT D 69.00 12.00 10 WHITE TANKS - AVONDALE T 230.00 69.00 11 WHY - AJO D 69.00 21.60 12 WICKENBURG - WICKENBURG D 69.00 12.00 13 WILD BURRO - NEW RIVER D 69.00 7.20 14 WILD FLOWER - GOODYEAR D 69.00 12.00 15 WILHOIT - PRESCOTT D 69.00 12.00 16 WILLIAMS - WILLIAMS D 69.00 12.00 17 WILLIS - GOODYEAR D 69.00 12.00 18 WILLOW LAKE - PRESCOTT T 230.00 115.00 12.40 19 WILLOW LAKE - PRESCOTT T 230.00 69.00 12.40 20 WINDMILL - SEDONA D 69.00 7.20 21 WINONA - WINONA D 69.00 12.00 22 WINSLOW - WINSLOW D 69.00 12.00 23 WINTERSBURG - TONOPAH D 69.00 12.00 24 WOODRUFF - HOLBROOK D 69.00 21.00 25 WOODY MOUNTAIN - FLAGSTAFF D 69.00 12.00 26 WUPATKI - FLAGSTAFF D 69.00 12.00 27 YALE - PHOENIX D 69.00 12.00 28 YARNELL - YARNELL D 69.00 12.00 29 YAVAPAI - CHINO VALLEY T 525.00 230.00 12.40 30 YAVAPAI - CHINO VALLEY T 230.00 69.00 12.40 31 YORKSHIRE - PHOENIX D 69.00 12.00 32 YOUNG'S CANYON - DONEY PARK T 345.00 69.00 33 YUCCA - YUMA T 161.00 69.00 34 YUMA PALMS TEMP - YUMA D 69.00 12.00 35 ZENIFF - SNOWFLAKE D 69.00 36 37 38 39 40 FERC FORM NO. 1 (ED. 12-96) Page 426.10 34.50 12.40 12.40 12.00 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 12 20 1 capacitor bank-12kV 2 4 13 16 1 83 2 capacitor bank-69kV 1 22 9 1 capacitor bank-69kV 1 7 10 11 14 15 42 1 16 9 1 17 9 1 18 20 1 19 4 1 20 20 1 21 30 1 22 capacitor bank-115kV 5 49 23 24 20 1 capacitor bank-69kV 1 14 83 2 capacitor bank-12kV 4 10 25 26 capacitor bank-69kV 1 7 capacitor bank-69kV 2 22 27 40 2 20 1 28 83 2 29 capacitor bank-69kV 1 14 30 31 32 112 1 9 1 33 10 1 34 15 1 35 13 1 36 20 1 37 83 2 38 267 2 39 20 1 40 FERC FORM NO. 1 (ED. 12-96) 1 Page 427 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 83 2 7 1 167 4 522 3 125 3 83 2 6 125 3 7 2 1 8 83 2 40 2 100 1 50 1 20 1 13 40 2 14 83 2 16 83 2 17 83 2 18 40 2 19 38 2 21 1002 6 capacitor bank-69kV 1 10 2 3 4 capacitor bank-69kV 1 48 5 9 capacitor bank-12kV 4 14 10 11 12 1 15 20 1 capacitor bank-525kV 1 569 22 shunt reactor-525kV 4 167 23 capacitor bank-345kV 2 282 24 203 1 143 1 25 150 2 26 83 2 capacitor bank-12kV 2 7 40 2 capacitor bank-12kV 4 7 27 28 29 355 2 40 2 capacitor bank-69kV 2 36 30 83 2 capacitor bank-69kV 1 14 31 83 2 capacitor bank-69kV 1 29 9 1 33 83 2 34 42 1 capacitor bank-12kV 2 5 32 35 36 37 40 2 20 1 20 1 FERC FORM NO. 1 (ED. 12-96) capacitor bank-12kV 4 12 38 39 capacitor bank 69kv Page 427.1 1 7 40 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 2 40 2 Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 1 capacitor bank-69kV capacitor bank-12kV 1 2 11 2 6 3 4 125 3 355 2 5 2 40 20 1 42 1 83 2 3 1 83 2 564 3 125 3 22 1 269 3 40 2 83 2 capacitor bank-69kV 4 21 6 capacitor bank-12kV 2 4 7 8 9 capacitor bank-12kV 2 7 10 capacitor bank-69kV 1 29 11 capacitor bank-12kV 2 7 13 capacitor bank-69kV 1 29 12 14 15 capacitor bank-69kV 1 48 16 17 18 1 19 capacitor bank-12kV 2 10 20 21 22 4 1 83 2 capacitor bank-12kV 2 10 23 40 2 capacitor bank-69kV 1 14 24 83 2 capacitor bank-12kV 2 7 25 26 20 1 42 1 83 2 capacitor bank-12kV 2 4 28 123 3 capacitor bank-69kV 1 48 29 capacitor bank-69kV 3 22 27 1 269 3 30 31 1 shunt reactor-525kV 1 190 32 capacitor bank525kV 1 536 33 capacitor bank-12kV 2 7 34 83 2 125 3 35 100 2 36 41 1 capacitor bank-12kV 2 5 37 41 1 capacitor bank-12kV 1 5 38 41 1 capacitor bank-12kV 2 14 39 40 2 FERC FORM NO. 1 (ED. 12-96) 40 Page 427.2 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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) 5 1 2 2 83 2 48 3 40 2 83 2 5 41 1 capacitor bank-12kV 1 4 6 83 2 capacitor bank-12kV 4 10 7 41 1 capacitor bank-12kV 4 10 8 20 1 83 2 20 20 1 376 1 capacitor bank-69kV 2 1 4 9 10 capacitor bank-69kV 1 29 11 1 capacitor bank-69kV 1 7 13 20 1 capacitor bank-69kV 2 22 14 83 2 capacitor bank-69kV 2 29 15 1 12 2 83 2 capacitor bank-12kV 2 7 16 1025 3 1 shunt reactor-525kV 3 125 17 1400 2 1 shunt reactor-345kV 4 125 18 19 106 2 shunt reactor-230kV 2 200 167 4 capacitor bank-12kV 4 10 20 10 1 21 42 1 22 188 1 23 41 1 24 200 2 25 83 2 capacitor bank-69kV 2 83 2 capacitor bank-12kV 40 2 capacitor bank-69kV 100 2 9 1 30 26 2 8 27 1 14 28 29 30 31 32 41 1 1 2 33 1 34 41 3 20 1 36 41 1 37 1 38 1 39 1 40 18 FERC FORM NO. 1 (ED. 12-96) capacitor bank-12kV Page 427.3 3 11 35 125 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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) 125 3 1 20 1 2 3 41 1 4 20 1 5 10 1 6 20 1 7 83 2 capacitor bank-69kV 1 14 8 83 2 capacitor bank-69kV 1 29 9 20 1 capacitor bank-12kV 2 5 10 83 2 11 10 1 13 1 14 40 2 15 12 16 capacitor bank-12kV 2 7 17 83 2 125 3 18 40 2 19 125 3 20 83 2 21 41 1 22 9 1 23 20 1 24 9 1 25 26 9 1 36 2 27 capacitor bank-69kV 2 29 28 1 29 20 1 30 6 1 31 188 1 33 83 2 capacitor bank-69kV 1 35 167 4 capacitor bank-12kV 8 19 83 2 36 83 2 37 376 2 38 41 1 39 40 2 40 32 FERC FORM NO. 1 (ED. 12-96) Page 427.4 34 35 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company. Capacity of Substation (In Service) (In MVa) Number of Transformers In Service (f) (g) Number of Spare Transformers Type of Equipment Number of Units (h) (i) (j) CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No. Total Capacity (In MVa) (k) 83 2 1 40 2 2 1 3 capacitor bank-12kV 2 7 4 83 2 83 2 5 1 6 20 1 7 16 1 8 83 2 9 83 2 10 83 2 11 188 1 125 3 capacitor bank-69kV 1 48 41 1 capacitor bank-69kV 2 14 15 125 3 capacitor bank-12kV 4 10 16 188 1 12 13 14 17 1 18 1 19 1 2 20 7 1 21 capacitor bank-525kV 4 2,041 22 shunt reactor-525kV 10 646 23 83 2 24 83 2 25 600 1 26 1 9 1 capacitor bank-69kV 1 11 27 83 2 capacitor bank-69kV 1 48 28 50 1 29 83 2 30 9 1 31 9 1 1 50 1 1 capacitor bank-12kV 4 10 32 33 34 1 shunt reactor-525kV 2 380 capacitor bank-525kV 2 1,738 35 36 6 1 37 20 1 38 1 39 shunt reactor-525kV FERC FORM NO. 1 (ED. 12-96) Page 427.5 2 381 40 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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-525kV Number of Units (j) Line Total Capacity No. (In MVa) (k) 1 2 979 509 6 83 2 2 40 2 3 16 1 4 355 2 5 capacitor bank-12kV 2 5 capacitor bank230kV 2 314 6 capacitor bank-69kV 1 48 7 8 125 3 9 4 1 10 1 11 12 1 13 188 1 1 83 2 14 20 1 15 20 1 16 40 2 18 125 3 5 1 20 1 21 17 16 capacitor bank-12kV 2 7 19 9 1 22 20 1 23 41 1 24 83 2 25 20 1 26 13 1 36 2 28 84 1 29 41 1 30 1 31 1872 3 2025 3 27 1 shunt reactor-525kV 1 190 32 159 34 33 1 752 4 83 2 4 1 36 20 1 37 9 1 38 83 2 FERC FORM NO. 1 (ED. 12-96) capacitor bank-230kV 3 35 Page 427.6 capacitor bank-69kV 2 29 39 capacitor bank-12kV 2 10 40 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 2 3 1 1 2 162 2 3 16 1 4 3 3 5 9 1 6 40 2 7 41 1 8 40 2 capacitor bank-69kV 2 22 9 16 1 capacitor bank-69kV 2 7 10 83 2 11 188 1 12 9 1 13 83 2 14 1 1 15 2 16 83 capacitor bank-69kV 1 48 17 376 2 4 1 50 1 20 1 20 1 21 18 capacitor bank-12kV 2 9 19 1 22 83 2 23 83 2 24 9 1 25 2 26 83 1 3 27 16 1 28 1 29 2 30 83 31 20 1 capacitor bank-69kV 1 7 capacitor bank-12kV 4 9 32 33 34 35 1 1450 2 shunt reactor-525kV 896 2 1 22 1 2 4 167 36 37 capacitor bank-115kV 2 49 38 20 1 capacitor bank-69kV 2 7 39 40 2 capacitor bank-69kV 1 7 40 FERC FORM NO. 1 (ED. 12-96) Page 427.7 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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 bank34.5kV Line No. Total Capacity (In MVa) (k) Number of Units (j) 1 4 1 20 1 65 4 2 138 5 3 20 1 4 60 3 5 6 355 2 83 2 40 2 capacitor bank-230kV capacitor bank-69kV 2 2 94 7 29 8 9 10 83 2 11 83 2 12 83 2 13 40 2 9 1 14 capacitor bank-12kV 4 10 capacitor bank-69kV 1 14 15 16 capacitor bank-12kV 2 6 capacitor bank-69kV 2 14 17 83 2 18 40 2 19 20 1 1 2 21 83 2 23 1 24 83 2 25 1 1 26 83 2 27 83 2 28 9 1 29 5 3 capacitor bank-69kV 1 7 20 22 30 1 31 20 1 269 3 capacitor bank-69kV 1 14 32 600 1 shunt reactor-525kV 1 190 33 40 2 capacitor bank-69kV 2 14 34 167 1 35 188 1 36 83 2 2 3 564 3 125 3 FERC FORM NO. 1 (ED. 12-96) 1 capacitor bank-69kV 1 43 37 38 capacitor bank-69kV 1 53 39 40 Page 427.8 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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) 56 9 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) 3 1 1 2 1 3 2 4 1 5 6 83 2 7 40 2 8 20 1 9 83 2 10 83 2 11 41 1 1 2 16 1 capacitor bank-69kV 1 10 14 40 2 capacitor bank-69kV 1 7 15 capacitor bank-21kV 4 10 16 capacitor bank-12kV 2 6 188 1 20 1 83 2 9 1 capacitor bank-69kV 2 14 12 13 17 18 19 capacitor bank-12kV 6 7 20 capacitor bank-69kV 1 7 21 41 1 22 83 2 23 24 83 2 25 11 1 26 40 2 27 2 3 28 188 1 29 41 1 41 capacitor bank-69kV 1 7 30 31 1 capacitor bank-69kV 4 29 32 200 2 20 1 83 2 83 2 35 2 37 33 capacitor bank-12kV 4 14 34 36 83 1 38 20 1 39 10 1 40 FERC FORM NO. 1 (ED. 12-96) Page 427.9 This Report Is: Name of Respondent 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company (2) X A Resubmission SUBSTATIONS (Continued) Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/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) 564 3 (i) capacitor bank-69kV 83 2 capacitor bank-12kV 41 1 4500 9 41 1 376 2 Number of Units (j) Line Total Capacity No. (In MVa) (k) 1 1 35 4 10 2 3 4 4 shunt reactor-525kV 3 571 5 capacitor bank-525kV 1 340 6 7 1 shunt reactor- 230kV 2 212 capacitor bank-12kV 4 12 8 9 40 2 376 2 10 3 1 11 36 2 capacitor bank-69kV 1 12 12 1 13 83 2 14 3 1 15 16 2 capacitor bank-69kV 1 6 16 41 1 capacitor bank-69kV 1 14 17 166 2 shunt reactor-230kV 1 25 18 376 2 19 1 1 20 3 1 21 20 2 22 18 1 23 4 1 24 20 1 capacitor bank-69kV 1 7 25 26 1 2 9 1 28 672 2 29 100 1 30 1 31 20 150 1 84 1 20 capacitor bank-12kV 1 4 10 27 83 capacitor bank-69kV 1 14 capacitor bank-69kv 1 25 32 33 34 1 35 36 37 38 39 40 FERC FORM NO. 1 (ED. 12-96) Page 427.10 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/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 4.8 MVa Schedule Page: 426 Line No.: 10 Column: k Line No.: 12 Column: k Line No.: 13 Column: k Line No.: 15 Column: k Line No.: 20 Column: f Line No.: 23 Column: k Line No.: 24 Column: k Line No.: 25 Column: k Line No.: 26 Column: k 7.2 MVa Schedule Page: 426 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426 Line No.: 27 Column: k Line No.: 30 Column: k Line No.: 34 Column: f 21.6 MVa Schedule Page: 426 14.4 MVa Schedule Page: 426 10.4 MVa Schedule Page: 426.1 Line No.: 2 Column: k 9.6 MVa Schedule Page: 426.1 Line No.: 10 Column: k Line No.: 22 Column: k Line No.: 23 Column: k Line No.: 24 Column: k Line No.: 27 Column: k Line No.: 28 Column: k Line No.: 31 Column: k Line No.: 32 Column: k Line No.: 35 Column: k Line No.: 40 Column: k 14.4 MVa Schedule Page: 426.1 568.9 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.: 2 Column: k Line No.: 6 Column: k Line No.: 7 Column: k 10.8 MVa Schedule Page: 426.2 21.6 MVa Schedule Page: 426.2 4.8 MVa Schedule Page: 426.2 Line No.: 10 Column: k Line No.: 11 Column: k Line No.: 13 Column: k Line No.: 14 Column: k Line No.: 20 Column: k Line No.: 22 Column: f Line No.: 23 Column: k 7.2 MVa Schedule Page: 426.2 28.8 MVa Schedule Page: 426.2 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 FERC FORM NO. 1 (ED. 12-87) Page 450.3 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.2 Line No.: 24 Column: k Line No.: 25 Column: k Line No.: 28 Column: k Line No.: 30 Column: k Line No.: 31 Column: f Line No.: 33 Column: k Line No.: 34 Column: k Line No.: 37 Column: k Line No.: 38 Column: k Line No.: 39 Column: k 14.4 MVa Schedule Page: 426.2 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: 426.3 Line No.: 1 Column: k Line No.: 6 Column: k Line No.: 7 Column: k Line No.: 8 Column: k 4.8 MVa Schedule Page: 426.3 3.6 MVa Schedule Page: 426.3 9.6 MVa Schedule Page: 426.3 9.6 MVa Schedule Page: 426.3 Line No.: 11 Column: k Line No.: 12 Column: f Line No.: 13 Column: k Line No.: 14 Column: k Line No.: 15 Column: k Line No.: 16 Column: k Line No.: 20 Column: k Line No.: 27 Column: k Line No.: 28 Column: k Line No.: 33 Column: f 28.8 MVa Schedule Page: 426.3 0.3 MVa Schedule Page: 426.3 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 FERC FORM NO. 1 (ED. 12-87) Page 450.4 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.3 Line No.: 35 Column: k Line No.: 38 Column: f Line No.: 39 Column: f 10.8 MVa Schedule Page: 426.3 0.1 MVa Schedule Page: 426.3 0.1 MVa Schedule Page: 426.4 Line No.: 8 Column: k Line No.: 9 Column: k 14.4 MVa Schedule Page: 426.4 28.8 MVa Schedule Page: 426.4 Line No.: 10 Column: k Line No.: 14 Column: f Line No.: 17 Column: k Line No.: 28 Column: k Line No.: 29 Column: f Line No.: 34 Column: k Line No.: 35 Column: k 4.8 MVa Schedule Page: 426.4 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: 426.5 Line No.: 3 Column: f Line No.: 4 Column: k Line No.: 6 Column: f 0.1 MVa Schedule Page: 426.5 7.2 MVa Schedule Page: 426.5 0.1 MVa Schedule Page: 426.5 Line No.: 15 Column: k Line No.: 16 Column: k Line No.: 17 Column: f Line No.: 22 Column: k Line No.: 27 Column: k Line No.: 32 Column: k Line No.: 34 Column: f Line No.: 36 Column: k Line No.: 37 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 FERC FORM NO. 1 (ED. 12-87) Page 450.5 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.5 Line No.: 39 Column: f 0.1 MVa Schedule Page: 426.6 Line No.: 1 Column: k Line No.: 3 Column: k Line No.: 6 Column: k 978.3 MVa Schedule Page: 426.6 4.8 MVa Schedule Page: 426.6 313.5 MVa Schedule Page: 426.6 Line No.: 10 Column: f Line No.: 11 Column: f Line No.: 12 Column: f Line No.: 19 Column: k Line No.: 27 Column: f Line No.: 31 Column: f Line No.: 32 Column: k Line No.: 36 Column: f Line No.: 39 Column: k Line No.: 40 Column: k 3.5 MVa Schedule Page: 426.6 0.1 MVa Schedule Page: 426.6 0.1 MVa Schedule Page: 426.6 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: 426.7 Line No.: 1 Column: f Line No.: 2 Column: f Line No.: 5 Column: f Line No.: 6 Column: f Line No.: 9 Column: k 1.5 MVa Schedule Page: 426.7 0.56 MVa Schedule Page: 426.7 3.3 MVa Schedule Page: 426.7 9.38 MVa Schedule Page: 426.7 21.6 MVa Schedule Page: 426.7 Line No.: 10 Column: k Line No.: 15 Column: f Line No.: 18 Column: f Line No.: 19 Column: k Line No.: 21 Column: f 7.2 MVa Schedule Page: 426.7 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) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.7 Line No.: 22 Column: f Line No.: 27 Column: f Line No.: 29 Column: f Line No.: 32 Column: k Line No.: 33 Column: k Line No.: 35 Column: f Line No.: 36 Column: k Line No.: 38 Column: f Line No.: 38 Column: k Line No.: 39 Column: k Line No.: 40 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 9.6 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: 426.8 Line No.: 1 Column: k Line No.: 7 Column: k Line No.: 8 Column: k 3.6 MVa Schedule Page: 426.8 93.6 MVa Schedule Page: 426.8 28.8 MVa Schedule Page: 426.8 Line No.: 14 Column: k Line No.: 15 Column: k Line No.: 17 Column: k Line No.: 20 Column: k Line No.: 21 Column: f Line No.: 24 Column: f Line No.: 26 Column: f Line No.: 30 Column: f Line No.: 32 Column: k Line No.: 33 Column: k 9.6 MVa Schedule Page: 426.8 14.4 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 FERC FORM NO. 1 (ED. 12-87) Page 450.7 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.8 Line No.: 34 Column: k Line No.: 37 Column: k Line No.: 38 Column: f 14.4 MVa Schedule Page: 426.8 43.2 MVa Schedule Page: 426.8 1.68 MVa Schedule Page: 426.9 Line No.: 2 Column: f Line No.: 3 Column: f Line No.: 4 Column: f 0.1 MVa Schedule Page: 426.9 0.25 MVa Schedule Page: 426.9 0.2 MVa Schedule Page: 426.9 Line No.: 12 Column: k Line No.: 13 Column: f Line No.: 14 Column: k Line No.: 15 Column: k Line No.: 16 Column: i Line No.: 16 Column: k Line No.: 20 Column: k Line No.: 21 Column: k Line No.: 26 Column: f Line No.: 28 Column: f Line No.: 30 Column: k Line No.: 32 Column: k Line No.: 34 Column: k Line No.: 38 Column: f Line No.: 40 Column: f Line No.: 1 Column: k Line No.: 2 Column: k Line No.: 5 Column: k 14.4 MVa Schedule Page: 426.9 1.12 MVa Schedule Page: 426.9 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: 426.10 35.03 MVa Schedule Page: 426.10 9.6 MVa Schedule Page: 426.10 571.2 MVa FERC FORM NO. 1 (ED. 12-87) Page 450.8 Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company FOOTNOTE DATA Schedule Page: 426.10 Line No.: 13 Column: f Line No.: 16 Column: f Line No.: 17 Column: k Line No.: 20 Column: f Line No.: 24 Column: f Line No.: 25 Column: k Line No.: 26 Column: f Line No.: 27 Column: k Line No.: 32 Column: k Line No.: 33 Column: k 0.25 MVa Schedule Page: 426.10 15.6 MVa Schedule Page: 426.10 14.4 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) 05/09/2018 2017/Q4 Name of Respondent This Report Is: 20180509-8003 FERC PDF (Unofficial) 05/09/2018 (1) An Original Arizona Public Service Company Date of Report (Mo, Da, Yr) 05/09/2018 Year/Period of Report 2017/Q4 End of (2) X A Resubmission TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES 1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. 2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general". 3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote. Account Amount Name of Line Charged or Charged or Associated/Affiliated No. Description of the Non-Power Good or Service Credited Credited Company (a) (b) (c) (d) 1 Non-power Goods or Services Provided by Affiliated 2 Common stock dividends Pinnacle West Capital Corporation 438 296,800,000 3 Share of estimated income taxes Pinnacle West Capital Corporation 236 14,361,962 4 Share of withholding and payroll taxes Pinnacle West Capital Corporation 236,241,408 268,021,485 Pinnacle West Capital Corporation 228.3 99,876,608 5 Share of pension and other post retirement 6 benefits contributions 7 Share of employee benefits (excluding pension and Pinnacle West Capital Corporation 228.3,925,926 151,270,783 Pinnacle West Capital Corporation 143,232,242 81,277,129 10 Shared services Pinnacle West Capital Corporation various 36,045,649 11 Compensation paid in stock Pinnacle West Capital Corporation various 23,852,737 12 NTEC APS 4CA 2016 Settlement Agreement Pinnacle West Capital Corporation 234 10,218,840 El Dorado Investment Company 107 327,858 21 Equity Infusion Pinnacle West Capital Corporation 207 150,000,000 22 Tax Settlements Pinnacle West Capital Corporation 236 14,229,811 23 Shared services Pinnacle West Capital Corporation various 12,172,303 24 Four Corners Capital- 4CA Pinnacle West Capital Corporation 131 27,143,267 25 Four Corners Reclamation Funding- 4CA Pinnacle West Capital Corporation 131 1,189,535 26 Four Corners Coal- 4CA Pinnacle West Capital Corporation 131 447,783 27 Four Corners O&M- 4CA Pinnacle West Capital Corporation 131 10,445,223 28 Four Corners Shared Services- 4CA Pinnacle West Capital Corporation 131 3,762 29 Four Corners Miscellaneous 8 OPEB contributions) 9 Employee programs payroll deductions 13 Space Time inc- Consulting services 14 15 16 17 18 19 20 Non-power Goods or Services Provided for Affiliate Pinnacle West Capital Corporation various 22,489 30 Shared services El Dorado Investment Company various 70,740 31 Shared services Bright Canyon Energy Corporation various 1,055,886 32 33 34 35 36 37 38 39 40 41 42 FERC FORM NO. 1 (New) FERC FORM NO. 1-F (New) Page 429 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Name of Respondent This Report is: (1) An Original (2) X A Resubmission Arizona Public Service Company Date of Report Year/Period of Report (Mo, Da, Yr) 05/09/2018 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%, benefit load tax at 7%, & injuries and damages allocated at 1% Schedule Page: 429 Line No.: 10 Column: d Includes corporate allocations at 100.0% and governance allocations at 98.3% Schedule Page: 429 Line No.: 11 Column: d Includes governance allocations at 98.3% FERC FORM NO. 1 (ED. 12-87) Page 450.1 2017/Q4 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 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 20180509-8003 FERC PDF (Unofficial) 05/09/2018 Document Content(s) Form120171200007.PDF..................................................1-366