### THIS FILING IS
Item 1: An Initial (Original) Submission OR Resubmission No. ____ X



# 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 

### OMB No.1902-0021

OMB No.1902-0029

OMB No.1902-0205 (Expires 12/31/2014)

(Expires 12/31/2014)

(Expires 05/31/2014) Form 1 Approved

Form 1-F Approved

Form 3-Q Approved

FERC FORM No.1/3-Q (REV. 02-04) Exact Legal Name of Respondent (Company) Year/Period of Report End of 2012/Q4 Arizona Public Service Company

### INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION I. Purpose FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.

II. Who Must Submit Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400). Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following: (1) one million megawatt hours of total annual sales, (2) 100 megawatt hours of annual sales for resale, (3) 500 megawatt hours of annual power exchanges delivered, or (4) 500 megawatt hours of annual wheeling for others (deliveries plus losses).

III. What and Where to Submit (a) Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report for your files. Any electronic submission must be created by using the forms submission software provided free by the Commission at its web site:

## http://www.ferc.gov/docs-filing/eforms/form-1/elec-subm-soft.asp. The software is used to submit the electronic filing to the Commission via the Internet. (b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings. (c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at: Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 (d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

FERC FORM 1 & 3-Q (ED. 03-07) i

### 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 Pages Comparative Balance Sheet 110-113 Statement of Income 114-117 Statement of Retained Earnings 118-119 Statement of Cash Flows 120-121 Notes to Financial Statements 122-123 e) Thefollowing 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/eforms/form-1/form-1.pdfand 

## http://www.ferc.gov/docs-filing/eforms.asp#3Q-gas

. IV. When to Submit: FERC Forms 1 and 3-Q must be filed by the following schedule:

FERC FORM 1 & 3-Q (ED. 03-07) ii

### a)FERC Form 1 for each year ending December 31 must be filed by April 18thof the following year (18 CFR § 141.1), and b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400). V. Where to Send Comments on Public Reporting Burden. The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 150 hours per response. Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

FERC FORM 1 & 3-Q (ED. 03-07) iii

### 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

### 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

### 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

### "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

### IDENTIFICATION 

## FERC FORM NO. 1/3-Q: REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Denise R. Danner 

### 400 North 5th Street, Phoenix, AZ 85004 2012/Q4

400 North 5th Street, Phoenix, AZ 85004 01 Exact Legal Name of Respondent

(1) An Original (2) A Resubmission X 02 Year/Period of Report End of 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)

05 Name of Contact Person 06 Title of Contact Person

07 Address of Contact Person (Street, City, State, Zip Code)

08 Telephone of Contact Person,Including Area Code 09 This Report Is 10 Date of Report (Mo, Da, Yr)

01 Name

02 Title 03 Signature 04 Date Signed 

### (Mo, Da, Yr)

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. 

### / /

Jeffrey B. Guldner SR VP Customers & Regulation

(602) 250-2952 04/10/2013

Denise R. Danner
VP, Controller & Chief Acct Officer 04/10/2013 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.



## FERC FORM No.1/3-Q (REV. 02-04) Page 1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of LIST OF SCHEDULES (Electric Utility) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Title of Schedule Reference Page No. Remarks (c) (b) (a) 

### 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".

101 General Information 1 102 Control Over Respondent 2 103 Corporations Controlled by Respondent 3 104 Officers 4 105 Directors 5 106(a)(b) Information on Formula Rates 6 108-109 Important Changes During the Year 7 110-113 Comparative Balance Sheet 8 114-117 Statement of Income for the Year 9 118-119 Statement of Retained Earnings for the Year 10 120-121 Statement of Cash Flows 11 122-123 Notes to Financial Statements 12 122(a)(b) Statement of Accum Comp Income, Comp Income, and Hedging Activities 13 200-201 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14 202-203 Nuclear Fuel Materials 15 204-207 Electric Plant in Service 16 213 Electric Plant Leased to Others 17 214 Electric Plant Held for Future Use 18 216 Construction Work in Progress-Electric 19 219 Accumulated Provision for Depreciation of Electric Utility Plant 20 224-225 Investment of Subsidiary Companies 21 227 Materials and Supplies 22 228(ab)-229(ab) Allowances 23 230 Extraordinary Property Losses 24 230 Unrecovered Plant and Regulatory Study Costs 25 231 Transmission Service and Generation Interconnection Study Costs 26 232 Other Regulatory Assets 27 233 Miscellaneous Deferred Debits 28 234 Accumulated Deferred Income Taxes 29 250-251 Capital Stock 30 253 Other Paid-in Capital 31 254 Capital Stock Expense 32 256-257 Long-Term Debt 33 261 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34 262-263 Taxes Accrued, Prepaid and Charged During the Year 35 266-267 Accumulated Deferred Investment Tax Credits 36

FERC FORM NO. 1 (ED. 12-96) Page 2LIST OF SCHEDULES (Electric Utility) (continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Title of Schedule Reference Page No. Remarks (c) (b) (a) 

### 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".

269 Other Deferred Credits 37 272-273 Accumulated Deferred Income Taxes-Accelerated Amortization Property 38 274-275 Accumulated Deferred Income Taxes-Other Property 39 276-277 Accumulated Deferred Income Taxes-Other 40 278 Other Regulatory Liabilities 41 300-301 Electric Operating Revenues 42 302 Regional Transmission Service Revenues (Account 457.1) 43 304 Sales of Electricity by Rate Schedules 44 310-311 Sales for Resale 45 320-323 Electric Operation and Maintenance Expenses 46 326-327 Purchased Power 47 328-330 Transmission of Electricity for Others 48 331 Transmission of Electricity by ISO/RTOs 49 332 Transmission of Electricity by Others 50 335 Miscellaneous General Expenses-Electric 51 336-337 Depreciation and Amortization of Electric Plant 52 350-351 Regulatory Commission Expenses 53 352-353 Research, Development and Demonstration Activities 54 354-355 Distribution of Salaries and Wages 55 356 Common Utility Plant and Expenses 56 397 Amounts included in ISO/RTO Settlement Statements 57 398 Purchase and Sale of Ancillary Services 58 400 Monthly Transmission System Peak Load 59 400a Monthly ISO/RTO Transmission System Peak Load 60 401 Electric Energy Account 61 401 Monthly Peaks and Output 62 402-403 Steam Electric Generating Plant Statistics 63 406-407 Hydroelectric Generating Plant Statistics 64 408-409 Pumped Storage Generating Plant Statistics 65 410-411 Generating Plant Statistics Pages 66

FERC FORM NO. 1 (ED. 12-96) Page 3LIST OF SCHEDULES (Electric Utility) (continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Title of Schedule Reference Page No. Remarks (c) (b) (a) 

### 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".

422-423 Transmission Line Statistics Pages 67 424-425 Transmission Lines Added During the Year 68 426-427 Substations 69 429 Transactions with Associated (Affiliated) Companies 70 450 Footnote Data 71 

### Stockholders' Reports Check appropriate box: X Two copies will be submitted No annual report to stockholders is prepared

FERC FORM NO. 1 (ED. 12-96) Page 4

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report

End of
GENERAL INFORMATION Arizona Public Service Company 

### X 04/10/2013 2012/Q4

Arizona - February 6, 1920 James R. Hatfield, Senior V.P. & Chief Financial Officer, 400 N. 5th Street, Phoenix, AZ 85004 

### 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.

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.

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.

4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.

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) Yes...Enter the date when such independent accountant was initially engaged: (2) No X Not Applicable

State of Arizona - Class A Electric Utility

FERC FORM No.1 (ED. 12-87) PAGE101

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report

End of
CONTROL OVER RESPONDENT Arizona Public Service Company 

### X 04/10/2013 2012/Q4



### 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, 2012, as filed with the Securities and Exchange Commission.

Page 102 FERC FORM NO. 1 (ED. 12-96)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
CORPORATIONS CONTROLLED BY RESPONDENT Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company Controlled Kind of Business Percent Voting Stock Owned (c) (b) (a) Footnote Ref. (d) 

### 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.

Conducts exploration 100 1 Bixco, Inc. activities for gas, oil, and 2 coal for possible use in APS 3 utility operations - Inactive 4 5 A non-profit corporation 100 6 APS Foundation, Inc. which makes distributions 7 to charitable organizations 8 9 A corporation which is 100 10 Axiom Power Solutions, Inc. engaged in the sales of 11 security and energy 12 management systems - 13 Inactive 14 15 Organized primarily to own 100 16 PWENewco, Inc. real and personal property 17 18 19 20 21 22 23 24 25 26 27

FERC FORM NO. 1 (ED. 12-96) Page 103Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
OFFICERS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Title Name of Officer Salary for Year (c) (b) (a) 

### 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.

Chief Executive Officer 1,146,000 Donald E. Brandt 1 2 President and Chief Operating Officer 685,000 Donald G. Robinson 3 4 Vice President, Controller and Chief Accounting Officer 285,000 Denise R. Danner 5 6 Vice President, Resource Management 253,000 Patrick Dinkel 7 8 Executive Vice President and Chief Nuclear Officer 900,000 Randall K. Edington 9 10 Executive Vice President and General Counsel 487,000 David P. Falck 11 12 Vice President, Energy Delivery 285,000 Daniel T. Froetscher 13 14 Senior Vice President, Customers and Regulation 315,000 Jeffrey B. Guldner 15 16 Executive Vice President and Chief Financial Officer 515,000 James R. Hatfield 17 18 Vice President, Communications 258,000 John S. Hatfield 19 20 Vice President and Chief Customer Officer 252,000 Tammy D. McLeod 21 22 Vice President and Treasurer 255,000 Lee R. Nickloy 23 24 Executive Vice President, Operations 435,000 Mark A. Schiavoni 25 26 Senior Vice President, Human Resources and Ethics 333,000 Lori S. Sundberg 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

### 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 among the affiliated companies where the person also serves as an officer. Schedule Page: 104 Line No.: 5 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 among the affiliated companies where the person also serves as an officer. Schedule Page: 104 Line No.: 7 Column: a 

## Appointed Vice President, Resource Management on June 26, 2012 (formerly Vice President, Power Marketing, Resource Planning and Acquisition) Schedule Page: 104 Line No.: 11 Column: a Appointed Executive Vice President and General Counsel on December 19, 2012 (formerly Executive Vice President, General Counsel and Secretary) Schedule Page: 104 Line No.: 11 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 among the affiliated companies where the person also serves as an officer. Schedule Page: 104 Line No.: 15 Column: a 

## Appointed Senior Vice President, Customers and Regulation on June 26, 2012 (formerly Vice President, Rates and Regulation, and Chief Compliance Officer) Schedule Page: 104 Line No.: 17 Column: a 

## Appointed Executive Vice President and Chief Financial Officer on December 19, 2012 (formerly Senior Vice President and Chief Financial 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 among the affiliated companies where the person also serves as an officer. Schedule Page: 104 Line No.: 23 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 among the affiliated companies where the person also serves as an officer. Schedule Page: 104 Line No.: 25 Column: a 

## Appointed Executive Vice President, Operations on June 26, 2012 (formerly Senior Vice President, Fossil Operations) Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
DIRECTORS Arizona Public Service Company X 04/10/2013 2012/Q4

Line Name (and Title) of Director Principal Business Address (b) (a) No. 

### 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.

Phoenix, Arizona Donald E. Brandt, Chairman and CEO 1 2 Chandler, Arizona Edward N. Basha, Jr 3 4 Phoenix, Arizona Michael L. Gallagher 5 6 Phoenix, Arizona Roy A. Herberger, Jr. 7 8 Austin, Texas Dale E. Klein 9 10 Paradise Valley, Arizona Susan Clark - Johnson 11 12 Tucson, Arizona Humberto S. Lopez 13 14 La Jolla, California Kathryn L. Munro 15 16 Flagstaff, Arizona Bruce J. Nordstrom 17 18 Fountain Hills, Arizona Denis A. Cortese 19 20 Note: Currently there is no Executive 21 Committee of the Board of Directors 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

FERC FORM NO. 1 (ED. 12-95) Page 105Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
INFORMATION ON FORMULA RATES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. FERC Rate Schedule or Tariff Number FERC Proceeding Does the respondent have formula rates? Yes No 

### X

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. FERC Rate Schedule/Tariff Number FERC Proceeding

ER10-1264 FERC Electric Tariff, Volume 2 1 ER09-1402 FERC Electric Tariff, Volume 5 2 ER10-1386 FERC Electric Rate Schedule No. 182 3 ER09-1349 FERC Electric Tariff, Volume 6 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

FERC FORM NO. 1 (NEW. 12-08) Page106

### Schedule Page: 106 Line No.: 4 Column: a 

## The WestConnect Tariff does not have any direct FERC Form No. 1 inputs however the relevant input to the WestConnect Tariff is APS's FERC Electric Tariff Volume 2 which does have FERC Form No. 1 inputs. Out of an abundance of caution, APS included the WestConnect Tariff on page 106 of the FERC Form No. 1. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. \ Filed Date Accession No. Date Docket No. Description Formula Rate FERC Rate Schedule Number or Tariff Number INFORMATION ON FORMULA RATES

Does the respondent file with the Commission annual (or more frequent) Yes No 

### X 2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website FERC Rate Schedule/Tariff Number FERC Proceeding

filings containing the inputs to the formula rate(s)?

Document

05/14/2012 20120514-5095 ER11-3638 See FootnoteFERC Electric Tariff, Volume 2 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 (NEW. 12-08) Page106a

### Schedule Page: 1061 Line No.: 1 Column: d 

## Informational Filing - Annual Update of Formula Transmission Service Rates - Arizona Public Service Company under ER11-3638. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Page No(s). Schedule Column Line No INFORMATION ON FORMULA RATES

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 Formula Rate Variances

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.

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) Page106b

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report Year/Period of Report End of

IMPORTANT CHANGES DURING THE QUARTER/YEAR 

### Arizona Public Service Company X 04/10/2013 2012/Q4

PAGE 108 INTENTIONALLY LEFT BLANK SEE PAGE 109 FOR REQUIRED INFORMATION. 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.

FERC FORM NO. 1 (ED. 12-96) Page 108

## 1. The Gila Bend and Paradise Valley franchises were renewed on March 13, 2012 and became effective May 15, 2012 and January 13, 2013, respectively. The Camp Verde and Surprise franchises were renewed on November 26, 2012 and December 17, 2012, respectively. As with all of Arizona Public Service Company’s (“APS”) municipal franchises, all of the referenced franchises include a 2% franchise fee and are renewed for a term of twenty-five years.

2. None.

3. None.

4.

Lease to APS Effective Dates Grant Expire Length of Terms Payment Cycle Parties Rents Other Conditions Authorizing Commission Foothills Solar State Land Commercial Lease 03-115986-99 3/28/2012 3/28/2047 35 Annual Payments, escalating every 5 years State Land $138,750.00 N/A N/A



## 5. No important extension or reduction of the transmission or distribution system occurred in 2012 for APS. Only our normal company growth patterns were experienced.



## 6. Lines of Credit and Short-Term Borrowing The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2012 (dollars in millions):

Credit Facility Expiration Amount Committed Unused Amount (a) Commitment Fees APS Revolving Credit Facility November 2016 500 408 0.175% APS Revolving Credit Facility February 2015 500 500 0.20% Total $ 1,000 $ 908

(a) At December 31, 2012, APS had $92 million of outstanding commercial paper. Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $908 million. APS maintains committed revolving credit facilities in order to enhance liquidity and provide credit support for its commercial paper program. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.1

## The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2012, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $92 million at December 31, 2012. On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2015. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. On November 4, 2011, APS refinanced its $500 million revolving credit facility that would have matured in February 2013, with a new $500 million facility. The new revolving credit facility terminates in November 2016. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. Long-Term Debt All of APS’s debt is unsecured. The following table presents the components of long-term debt on the Comparative Balance Sheet outstanding at December 31, 2012 (dollars in thousands):

Maturity Dates (a) Interest Rates December 31, 2012 APS Pollution Control Bonds: Variable 2029-2038 (b) $ 75,580 Fixed 2024-2034 1.25%-6.00% 490,275 Pollution control bonds with senior notes 5.05% -- Total Pollution Control Bonds 565,855

Senior unsecured notes 2014-2042 4.50%-8.75% 2,575,000 Unamortized discount (9,486) Total APS long-term debt $ 3,131,369

(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities. (b) The weighted-average rate for the variable rate pollution control bonds was 0.13%-0.15% at December 31, 2012. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.2

## The following table shows principal payments due on APS’s total long-term debt (dollars in millions):

Year APS 2013 $ 96 2014 515 2015 332 2016 358 2017 -- Thereafter 1,840 Total $ 3,141

Credit Facilities and Debt Issuances On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012. On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project), 2009 Series B, due 2029. On June 1, 2012 these bonds were remarketed. Currently, the interest rate on these bonds is reset daily by a remarketing agent. The daily rate at December 31, 2012 was 0.13% per annum. Additionally, the bonds are supported by a letter of credit. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2012 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2011. On June 1, 2012, pursuant to the mandatory tender provision, APS changed the interest rate mode for the approximately $38 million of Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A. The new term rate period for these bonds commenced on June 1, 2012, and ends, subject to a mandatory tender, on May 29, 2014. During this time, the bonds will bear interest at a rate of 1.25% per annum. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2012 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2011. On November 1, 2012 APS redeemed at par all $90 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.3

## Contractual Obligations The following table summarizes APS’s contractual requirements as of December 31, 2012 (dollars in millions):

2013 2014 - 2015 2016 - 2017 Thereafter Total Long-term debt payments, including

interest: (a) $275 $1,149 $604 $3,282 $5,310 Fuel and purchased power commitments (b) 489 1,116 955 6,329 8,889 Renewable energy credits (c) 51 81 80 491 703 Purchase obligations (d) 96 29 14 221 360 Coal reclamation 1 74 27 17 119 Nuclear decommissioning funding

requirements 17 36 4 67 124 Operating lease payments 68 125 7 40 240 Total contractual commitments $ 997 $ 2,610 $ 1,691 $ 10,447 $15,745
(a) The long-term debt matures at various dates through 2042 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2012. (b) Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. (c) Contracts to purchase renewable energy credits in compliance with the Arizona Renewable Energy Standard and Tariff (“RES”). (d) These contractual obligations include commitments for capital expenditures and other obligations. These amounts do not include the purchase of Southern California Edison’s (“SCE”) interest in Four Corners Power Plant (“Four Corners”) Units 4 and 5 due to additional approvals required. This table excludes $133 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. This table also excludes approximately zero, $89 million and $112 million in estimated minimum pension contributions for 2013, 2014 and 2015, respectively.

Financial Assurances APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2012, approximately $76 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. One of these letters of credit expires in 2015 and two expire in 2016. Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements including certain natural gas tolling contracts entered into with third parties. At December 31, 2012, $65 million of such letters of credit were outstanding that will expire in 2013 and 2015. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.4

## Authorizations On February 6, 2013, the Arizona Corporation Commission (the “ACC”) issued a financing order (Decision No. 73659) in which it, subject to specified parameters and procedures, (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017. APS’s issuances of short-term debt are authorized by the ACC in its Decision No. 73659 and/or by Arizona Revised Statutes Section 40-302.D and the issuances of long-term debt are authorized by the ACC in its Decision No. 73659. 7. The Articles of Incorporation were amended May 16, 2012 to allow the APS Board of Directors to consist of not less than nine or more than twenty-one persons. 8. The union and non-union annualized wage scale increases during 2012 through December 31, 2012 were as follows: Type of Cost Number of Increases Annualized Costs

a. Union Negotiated 1,761 $ 3,216,010

b. Non-Union Base Salary Increases 3,642 9,602,387

c. Special Increases 231 650,957

d. Promotions 311 1,430,504

Total 5,945 $ 14,899,858

COMMENTS:

a. The negotiated union contract for the Security Police and Fire Professionals of America wage adjustment effective February 1, 2012 was 3%. For 2012, the negotiated International Brotherhood of Electrical Workers union wage adjustment was 2.5%. 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. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.5

## c. Salary adjustments to base pay were awarded to non-union employees throughout the year in special instances. d. Promotions were awarded to non-union employees due to changes in job functions or grade level changes.

9. Legal Proceedings

I. LITIGATION & ENVIRONMENTAL MATTERS UPDATE

Environmental Matters Climate Change Legislative Initiatives.There have been no recent attempts by Congress to pass legislation that would regulate greenhouse gas (“GHG”) emissions and, with its focus on other issues, such as economic recovery and job growth, it is unclear if and when the 113thCongress will consider a climate change bill. In the event climate change legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is enacted and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed emissions; whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned; the cost to reduce emissions or buy allowances in the marketplace; and the availability of offsets and mitigating factors to moderate the costs of compliance. In addition to federal legislative initiatives, state-specific initiatives may also impact our business. While Arizona has no pending legislation and no proposed agency rule regulating GHGs in Arizona, the California legislature enacted AB 32 and SB 1368 in 2006 to address GHG emissions. In October 2011, the California Air Resources Board approved final regulations that established a state-wide cap on GHG emissions beginning on January 1, 2013 and established a GHG allowance trading program under that cap. The first phase of the program, which applies to, among other entities, importers of electricity, commenced on January 1, 2013. Under the program, importers of electricity, including APS, must hold carbon allowances to cover GHG emissions associated with electricity imported into California from outside the state. APS is authorized to recover the cost of these carbon allowances through the power supply adjustor (the “PSA”) approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the portion of APS’s retail base rates attributable to fuel and purchased power costs (the “Base Fuel Rate”). We are monitoring Arizona regulatory activities and other state legislative developments to understand the extent to which they may affect our business, including our sales into the impacted states or the ability of our out-of-state power plant participants to continue their participation in certain coal-fired power plants. In particular, SCE, a participant in Four Corners, has indicated that SB 1368 may prohibit it from making emission control expenditures at the plant. Regulatory Initiatives.In December 2009, the Environmental Protection Agency (“EPA”) determined that GHG emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that GHGs fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, EPA has the authority to regulate GHG emissions of new motor vehicles under the Clean Air Act. As a result Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.6

## of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. On June 3, 2010, EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new GHG emissions thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. “New Source Review,” or “NSR,” is a pre-construction permitting program under the Clean Air Act that requires analysis of pollution controls prior to building a new stationary source or making major modifications to an existing stationary source. The tailoring rule became effective on August 2, 2010 and it became applicable to power plants on January 2, 2011. Several groups filed lawsuits challenging EPA’s endangerment finding and the tailoring rule, but on June 26, 2012, the United States Court of Appeals for the District of Columbia Circuit issued its decision upholding the rules. APS does not expect the tailoring rule to have a significant impact on its current operations. The rule will require APS to consider the impact of GHG emissions as part of its traditional New Source Review analysis for new sources and major modifications to existing plants. On December 30, 2010, pursuant to its authority under the Clean Air Act, EPA finalized a GHG Federal Implementation Plan (“FIP”) for Arizona relating to pre-construction permits for construction of new sources or major modifications of existing sources. Subsequently, in March 2011, EPA and the Arizona Department of Environmental Quality (“ADEQ”) entered into an agreement under which EPA delegated to ADEQ authority to issue GHG pre-construction permits and to modify existing GHG pre-construction permits. The GHG FIP will remain in place until such time as EPA approves a State Implementation Plan (“SIP”) that applies pre-construction permit requirements to GHG-emitting stationary sources in Arizona. APS does not expect the GHG FIP to have a significant impact on its current operations. Pursuant to its authority under the Clean Air Act, on March 27, 2012, EPA proposed New Source Performance Standards (“NSPS”) for GHG emissions from new electric generating units. Once finalized, APS does not expect the GHG NSPS for new units to have an impact on its current operations. EPA has indicated that the rule will not apply to modified, reconstructed, or existing electric generating units. It is unclear when, or if, EPA will propose such standards, which could affect Four Corners, Cholla, and the Navajo Plant once promulgated. At the present time, we cannot predict what other rules or regulations may ultimately result from EPA’s endangerment finding and what impact other potential rules or regulations will have on APS’s operations. If any emission reduction legislation or additional regulations are enacted, we will assess our compliance alternatives, which may include replacement of existing equipment, installation of additional pollution control equipment, purchase of allowances, retirement or suspension of operations at certain coal-fired facilities, or other actions. Although associated capital expenditures or operating costs resulting from GHG emission regulations or legislation could be material, we believe that we would be able to recover the costs of these environmental compliance initiatives through our regulated rates. Company Response to Climate Change Initiatives

.We have undertaken a number of initiatives to address emission concerns, including renewable energy procurement and development, promotion of programs and rates that promote energy conservation, renewable energy use and energy efficiency. APS currently has a diverse portfolio of renewable resources, including wind, geothermal, solar, biogas and biomass, and we are focused on increasing the percentage of our energy that is produced by renewable resources. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.7

## APS prepares an inventory of GHG emissions from its operations. This inventory is reported to EPA under the EPA GHG Reporting Program and is voluntarily communicated to the public in Pinnacle West’s annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com). The report provides information related to the Company and its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report. Climate Change Lawsuit.In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law. The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages. In June 2008, the defendants filed motions to dismiss the action, which were granted. The plaintiffs filed an appeal with the United States Court of Appeals for the Ninth Circuit in November 2009. On September 21, 2012, a three-judge panel of the Ninth Circuit affirmed the district court’s dismissal of the Kivalinaplaintiffs’ federal common law public nuisance action. The court declined to address any other issue raised by the parties, including the plaintiffs’ state nuisance law claim. On October 4, 2012, the plaintiffs filed a petition for rehearing by the entire Ninth Circuit, but on November 27, 2012, the court denied the plaintiffs’ petition. APS continues to believe the action inKivalinais without merit and will continue to defend against both the federal and state claims. EPA Environmental Regulation Regional Haze Rules.Over a decade ago, EPA announced regional haze rules to reduce visibility impairment in national parks and wilderness areas. The rules require states (or, for sources located on tribal land, EPA) to determine what pollution control technologies constitute the “best available retrofit technology” (“BART”) for certain older major stationary sources. EPA subsequently issued the Clean Air Visibility Rule, which provides guidelines on how to perform a BART analysis. The Four Corners and Navajo Plant participants’ obligations to comply with EPA’s final BART determinations (and Cholla’s obligations to comply with ADEQ’s and EPA’s determinations), coupled with the financial impact of potential future climate change legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.

Cholla.In 2007, ADEQ required APS to perform a BART analysis for Cholla pursuant to the Clean Air Visibility Rule. APS completed the BART analysis for Cholla and submitted its BART recommendations to ADEQ on February 4, 2008. The recommendations include the installation of certain pollution control equipment that APS believes constitutes BART. ADEQ reviewed APS’s recommendations and submitted its proposed BART SIP for Cholla and other sources within the state on March 2, 2011. On December 2, 2011, EPA provided notice of a proposed consent decree to address a lawsuit filed by a number of environmental organizations, which alleged that EPA failed to promulgate FIPs for states that have not Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.8

## yet submitted all or part of the required regional haze SIPs. In accordance with the consent decree, on December 5, 2012, EPA issued a final BART rule applicable to Cholla. EPA approved ADEQ’s BART emissions limits for sulfur dioxide (“SO2”) and emissions of particulate matter (“PM”), but added an SO2removal efficiency requirement of 95%. In addition, EPA disapproved ADEQ’s BART determinations for oxides of nitrogen (“NOx”) and promulgated a FIP establishing a new, more stringent “bubbled” NOxemissions rate applicable to the two BART-eligible Cholla units owned by APS and the other BART-eligible unit owned by PacifiCorp. In order to comply with this new rate, APS will be required to install selective catalytic reduction (“SCR”) technology on all three of the Cholla units. APS’s total costs for these post-combustion NOxcontrols would be approximately $187 million. This amount is not included in our current estimates for environmental capital expenditures. Under the FIP, APS has five years from December 2012 to complete installation of the equipment and achieve the BART emissions limit for NOx. APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. The State of Arizona and three other utilities also filed similar petitions. On February 4, 2013, APS filed a Petition for Reconsideration and Stay of the final BART rule with EPA.

Four Corners. On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule includes two compliance alternatives. The first emission control alternative finalized by EPA would require the installation of post-combustion controls on each of Units 1-5 at Four Corners to reduce NOxemissions. Current estimates indicate that APS’s share of total costs for Four Corners for these controls would be approximately $400 million. Under the second emission control alternative finalized by EPA, the owners of Four Corners would have the option to permanently close Units 1-3 by January 1, 2014 and install post-combustion NOxcontrols on each of Units 4 and 5 by July 31, 2018. APS’s share of total costs for these controls would be approximately $300 million. The majority of these costs are not included in the capital expenditure estimates since they would be incurred in years following 2015. For PM emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/mmBtu and Units 1-5 to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Because the Mercury and Air Toxics Standards will force the installation of baghouses on Units 1-3 if APS chooses not to close those units, EPA determined it is not necessary or appropriate to set new PM limits for Units 1-3 under the final Four Corners BART rule. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations. The Four Corners participants have until July 1, 2013 to notify EPA of which emission control approach Four Corners will follow.

On October 22, 2012, WildEarth Guardians filed a petition for review in the United States Court of Appeals for the Ninth Circuit alleging that EPA violated the Endangered Species Act (“ESA”) when it promulgated the final Four Corners BART FIP. On November 21, 2012, APS filed a motion for leave to intervene as a defendant, and the court granted that motion on December 10, 2012. EPA and APS have pending motions with the court to dismiss the petition or, in the alternative, transfer the case to the United States Court of Appeals for the Tenth Circuit, the circuit in which we believe the petition should have been filed. We cannot currently predict the outcome of this case or whether such outcome will have a material adverse impact on our financial position, results of operations, or cash Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-96) Page 109.9

## flows.

Navajo Plant. On January 18, 2013, EPA issued a proposed BART rule for the Navajo Plant, which would require installation of SCR technology in order to achieve a new, more stringent plantwide NOxemission limit. Under the proposal, the Navajo Plant participants would have up to five years after EPA issues its final determinations to achieve compliance with the BART requirements. APS’s total costs for post-combustion NOx controls could be up to approximately $158 million. The majority of these costs are not included in the capital expenditure estimates since they will be incurred in years following 2015. EPA’s proposal also includes an “Alternative to BART,” which would provide the Navajo Plant with additional time to install the SCR technology. Under this “better than BART” alternative, the Navajo Plant participants would be required to install SCR technology on one unit per year in 2021, 2022 and 2023. EPA is also requesting comments on other options that could set longer time frames for installing pollution controls if the Navajo Plant can achieve additional emission reductions. Comments are due to EPA by May 6, 2013. Mercury and other Hazardous Air Pollutants.On December 16, 2011, EPA issued the final Mercury and Air Toxics Standards (“MATS”), which established maximum achievable control technology (“MACT”) standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired power plants. Generally, plants will have three years after the effective date of the rule to achieve compliance. In the case of Cholla, APS will have a total of four years after the MATS’ effective date to comply with the new MACT standards because on September 24, 2012, the permitting authority granted APS’s request for a one-year compliance date extension. The MATS will require APS to install additional pollution control equipment. APS has installed certain of the equipment necessary to meet the anticipated standards. APS currently estimates that the cost for the remaining equipment necessary to meet these standards is approximately $124 million for Cholla Units 1-3. The estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3. Cholla’s estimated costs for the next three years are included in our environmental expenditure estimates. Salt River Project Agricultural Improvement and Power District (“SRP”), the operating agent for the Navajo Plant, is still evaluating compliance options under the MATS. Cooling Water Intake Structures.EPAissued its proposed cooling water intake structures rule on April 20, 2011, which provides national standards applicable to certain cooling water intake structures at existing power plants and other facilities pursuant to Section 316(b) of the Clean Water Act. The proposed standards are intended to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). To minimize impingement mortality, the proposed rule would require facilities, such as Four Corners and the Navajo Plant, to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity, and to take certain protective measures with respect to impinged fish. To minimize entrainment mortality, the proposed rule would also require these facilities to conduct a “structured site-specific analysis” to determine what site-specific controls, if any, should be required. Additional studies and a peer review process will also be required at these facilities. As proposed, existing facilities subject to the rule would have to comply with the impingement mortality requirements as soon as possible, but in no event later than eight years after the effective date of the rule, and would Name of Respondent

Arizona Public Service Company 

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## have to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. APS is performing analyses to determine the costs of compliance with the proposed rule. EPA is working to finalize the standards by June 27, 2013.

Coal Combustion Waste.On June 21, 2010, EPA released its proposed regulations governing the handling and disposal of coal combustion residuals (“CCRs”), such as fly ash and bottom ash. APS currently disposes of CCRs in ash ponds and dry storage areas at Cholla and Four Corners, and also sells a portion of its fly ash for beneficial reuse as a constituent in concrete production. EPA proposes regulating CCRs as either non-hazardous waste or hazardous waste and requested comments on three different alternatives. The hazardous waste proposal would phase out the use of ash ponds for disposal of CCRs. The other two proposals would regulate CCRs as non-hazardous waste and impose performance standards for ash disposal. One of these proposals would require retrofitting or closure of currently unlined ash ponds, while the other proposal would not require the installation of liners or pond closures. EPA has not yet indicated a preference for any of the alternatives. On April 5, 2012, a coalition of environmental groups filed suit to compel EPA to finalize its proposed CCR rule. Soon thereafter, coal ash recyclers filed similar lawsuits against EPA. Although we do not know when EPA will issue a final rule or by when compliance will ultimately be required, in an October 11, 2012 filing with the court, EPA took the position that it will need at least a year to finalize the rule. Motions and cross-motions for summary judgment are currently pending before the court. We cannot currently predict the outcome of the lawsuit or EPA’s actions or whether such actions will have a material adverse impact on our financial position, results of operations, or cash flows. Effluent Limitation Guidelines.EPA is subject to a consent decree deadline to propose revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired electric generating units by April 19, 2013, and to finalize the rule by May 22, 2014. EPA has indicated that it expects the revised standards to target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities and scrubber-related operations. If EPA requires such conversions under the final rule, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change their waste disposal techniques. EPA may also revise standards for metals and other pollutants for wastewater streams not associated with ash handling. We cannot currently predict the shape of EPA’s final rule or whether this action will have a material adverse impact on our financial position, results of operations, or cash flows.Ozone National Ambient Air Quality Standards.In March 2008, EPA adopted new, more stringent eight-hour ozone standards, known as national ambient air quality standards (“NAAQS”). In January 2010, EPA proposed to adopt even more stringent eight-hour ozone NAAQS. However, on September 2, 2011, President Obama decided to withdraw EPA’s revised ozone standards until at least 2013 when EPA would be required to review them as part of its five-year NAAQS review process. As ozone standards become more stringent, our fossil generation units may come under increasing pressure to reduce emissions of nitrogen oxides and volatile organic compounds and/or to generate emission offsets for new projects or facility expansions. At this time, APS is unable to predict what impact the adoption of these standards may have on its financial position, results of operations, or cash flows.

New Source Review
.On April 6, 2009, APS received a request from EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that EPA has undertaken under the Clean Air Act. EPA has taken the position that many Name of Respondent

Arizona Public Service Company 

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## utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the New Source Review provisions of the Clean Air Act. Other electric utilities have received and responded to similar Section 114 requests, and several of them have been the subject of notices of violation and lawsuits by EPA. APS responded to EPA’s request in August 2009 and is currently unable to predict the timing or content of EPA’s response, if any, or any resulting actions.

Clean Air Act Lawsuit

.On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss, which are pending. We are unable to determine a range of potential losses that are reasonably possible of occurring. Endangered Species Act.On January 30, 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against the Office of Surface Mining Reclamation and Enforcement (“OSM”) and the United States Department of the Interior (“DOI”), alleging that OSM failed to engage in mandatory ESA consultation with the Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners. The lawsuit alleged that activities at the mine, including mining and the disposal of coal combustion residuals, would adversely affect several endangered species and their critical habitats. APS is not a party to the lawsuit but is monitoring it to determine its potential impact on APS’s operations. On March 14, 2012, the district court entered an order dismissing the plaintiffs’ lawsuit without prejudice. On May 14, 2012, the plaintiffs appealed the court’s order to the United States Court of Appeals for the Tenth Circuit. Superfund.The Comprehensive Environmental Response, Compensation and Liability Act (“Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated. Manufactured Gas PlantSites.Certain properties which APS now owns or which were previously owned by it or its corporate predecessors were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations or cash flows. Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-96) Page 109.12

## Navajo Nation Environmental Issues Four Corners and the Navajo Plant are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the Navajo Nation Pesticide Act (collectively, the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners and the Navajo Plant. On October 17, 1995, the Four Corners participants and the Navajo Plant participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Plant. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement. In April 2000, the Navajo Nation Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations. On July 12, 2000, the Four Corners participants and the Navajo Plant participants each filed a petition with the Navajo Supreme Court for review of these regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.On May 18, 2005, APS, SRP, as the operating agent for the Navajo Plant, and the Navajo Nation executed a Voluntary Compliance Agreement to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter

. Water Supply Assured supplies of water are important for APS’s generating plants. At the present time, APS has adequate water to meet its needs. However, the Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS iscontinuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of the plant.The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners. Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions, which, in addition to future supply conditions, have the potential to impact APS operations. San Juan River Adjudication.Both groundwater and surface water in areas important to APS’s operations have been the subject of inquiries, claims, and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-96) Page 109.13

## adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss. Gila River Adjudication.A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Arizona Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’s rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’s other power plants are also located within the geographic area subject to the summons. APS’s claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’s water rights claims has been set in this matter. Little Colorado River Adjudication.APS has filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’s claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’s water rights claims has been set in this matter. Although the above matters remain subject to further evaluation, APS does not expect that the described litigation will have a material adverse impact on its financial position, results of operations, or cash flows. Spent Nuclear Fuel and Waste Disposal On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the United States Department of Energy (“DOE”) in the U.S. Court of Federal Claims. The lawsuit seeks to recover APS’s damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. APS currently estimates it will incur $122 million over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2012, APS had a regulatory liability of $46 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage. Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-96) Page 109.14

## FERC Market Issues On July 25, 2001, FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit and ultimately remanded to FERC for further consideration. On October 3, 2011, FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001. The first phase of the hearing is currently expected to commence in April 2013. However, APS and Pinnacle West have entered into settlement agreements with all claimants with direct claims against us. The last of these settlement agreements was filed with FERC on December 5, 2012 and is currently pending FERC approval. Thus, we do not expect the outcome of the hearing to have a material adverse impact on our financial position, results of operations or cash flows. Southwest Power Outage On September 8, 2011 at approximately 3:30PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service. Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected. Service to all affected APS customers was restored by 9:15PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9. The FERC and the North American Electric Reliability Corporation (“NERC”) conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) with their analyses and conclusions as to the causes of the events. The report includes recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination. The Joint Report does not address potential reliability violations or an assessment of responsibility of the parties involved. APS continues to analyze business practices and procedures related to the September 8 events. APS cannot predict the timing, results or potential impacts of enforcement actions that may be brought against APS relating to the September 8 events, or any claims that may be made as a result of the outages. If violations of NERC Reliability Standards are ultimately determined to have occurred, FERC has the legal authority to assert a possible fine of up to $1 million per violation per day that a violation is found to have been in existence. Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-96) Page 109.15

## II. REGULATORY PROCEEDINGS

Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the Settlement Agreement without material modifications. Settlement Agreement The Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate for fuel and purchased power costs from $0.03757 to $0.03207 per kWh; and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million. APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement. Other key provisions of the Settlement Agreement include the following:

• An authorized return on common equity of 10.0%;

• A capital structure comprised of 46.1% debt and 53.9% common equity;

• A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;

• Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:

• Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

• Deferral of 100% in all years if Arizona property tax rates decrease; Name of Respondent

Arizona Public Service Company 

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## • A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners;

• Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;

• Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;

• Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

• A limitation on the use of the RES surcharge and the demand side management adjustment charge (“DSMAC”) to recoup capital expenditures not required under the terms of the 2008 rate case settlement agreement discussed below;

• Allowing a negative credit that currently exists in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

• Modification of the transmission cost adjustor (“TCA”) to streamline the process for future transmission-related rate changes; and

• Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS. The Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2008 rate case settlement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case. 2008 General Retail Rate Case On-Going Impacts On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008. The settlement agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

• A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

• Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and Name of Respondent

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2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.17

## • Various modifications to the existing energy efficiency, demand side management and renewable energy programs that require APS to, among other things, expand its conservation and demand side management programs through 2012 and its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand side management costs and incentives. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms. Renewable Energy Standard.In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requested 2012 RES funding of $129 million to $152 million. On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million. Within that budget, the ACC authorized APS to, among other items, own up to an additional 100 MW under its AZ Sun Program, for a total potential program amount of up to 200 MW. The AZ Sun program, originally approved by the ACC in March 2010, contemplates the development of photovoltaic solar plants which APS will own. Under this program to date, APS has executed contracts for the development of 118 MW of new solar generation, representing an investment commitment of approximately $502 million. On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requested 2013 RES funding of $97 million to $107 million. In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan. That budget includes $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for commercial distributed energy production-based incentives. The ACC further ordered that a hearing take place to consider: (i) APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits; and (ii) removing retail sales to APS’s largest industrial customers when calculating APS’s compliance with the annual RES requirements. Demand Side Management Adjustor Charge.The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC. In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand side management programs over the current year. Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis. The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives. The ACC previously approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2008 retail rate Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.18

## case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery was amortized over a three-year period, which ended in 2012. On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Standards, which became effective January 1, 2011. The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the 2008 retail rate case settlement agreement (2.75% of total energy resources for the same two-year period). The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates. On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan. In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million. Although this proposed budget is approximately $5.6 million more than the approved 2012 budget, the expiration of the three-year amortization of 2009 costs and prior year credits would result in a small decrease in the DSMAC. APS expects to receive a decision from the ACC in the second quarter of 2013.

PSA Mechanism and Balance.The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

• APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

• an adjustment to the PSA rate is made annually each February 1st(unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

• the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

• the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

• the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.19

## The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2012 and 2011 (dollars in millions):

Twelve Months Ended December 31, 2012 2011 Beginning balance $ 28 $ (58) Deferred fuel and purchased power costs – current period (72) (69) Amounts credited to customers 117 155 Ending balance $ 73 $ 28 The PSA rate for the PSA year beginning February 1, 2013 is $0.0013 per kWh as compared to ($0.0042) per kWh for the prior year. This represents a $0.0055 per kWh increase over the 2012 PSA charge. This new rate is comprised of a forward component of ($0.0010) per kWh and a historical component of $0.0023 per kWh. The Settlement Agreement allowed APS to exceed the $0.004 per kWh cap to PSA rate changes in this instance. Any uncollected (overcollected)deferrals during the 2013 PSA year will be included inthe calculation of the PSA rate for the PSA year beginning February 1, 2014. Transmission Rates and Transmission Cost Adjustor

.In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts. Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38 million of this revenue increase relates to Retail Transmission Charges. The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.20

## Effective June 1, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula. Because of higher relative system demand by APS’s retail customers, the approximately $16 million increase reflects roughly a $2 million decrease for wholesale customers and an $18 million increase for APS retail customers. On May 14, 2012, APS filed an application with the ACC to implement the FERC-approved transmission rates for retail customers discussed above. On July 18, 2012, the ACC approved the application authorizing the implementation of the FERC-approved transmission rates for retail customers, which became effective August 2012. As part of APS’s proposed acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing agreement that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California. APS expects to file a request with FERC seeking authorization to cancel the existing agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 29-year period. APS believes the costs associated with the termination of the existing agreement are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance. Lost Fixed Cost Recovery (“LFCR”) 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 the Company in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as roof-top solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the recent rate case and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The kWh’s lost from energy efficiency are based on a third-party evaluation of the Company’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques. APS filed its first LFCR adjustment on January 15, 2013 and will file for its LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved an LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the Settlement Agreement went into effect on July 1, 2012.

10. None. 11. (RESERVED)

12. N/A Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.21

## 13. Board and Officer Elections, Retirements, Resignations and Changes During 2012:



## Directors- W. Douglas Parker, resigned Pinnacle West Capital Corporation Board of Directors, February 3, 2012. Pamela Grant, retired Pinnacle West Capital Corporation Board of Directors, May 16, 2012.

Officers– Warren Kotzmann,Vice President, Strategic Initiatives and Risk, retired March 16, 2012. John H. Hesser, Vice President, Engineering, PVNGS, retired April 27, 2012. Mark A. Schiavoni, formerly Senior VP, Fossil Operations, became Executive VP, Operations on June 26, 2012. David A. Hansen, formerly VP, Fossil Operations, became VP, Fossil Generation on June 26, 2012. Jeffrey B. Guldner, formerly VP, Rates and Regulation, became Senior VP, Customers and Regulation on June 26, 2012. Patrick Dinkel, formerly VP, Power Marketing, Resource Planning and Acquisition, became VP, Resource Management on June 26, 2012. Barbara M. Gomez, formerly VP, Supply Chain Management, became VP, Supply Chain on June 26, 2012. Cindy K. Berger, became Vice President and Chief Information Officer on October 18, 2012. John J. Cadogan, became Vice President, Nuclear Engineering, PVNGS on October 18, 2012. James R. Hatfield, formerly Senior VP and Chief Financial Officer, became Executive VP and Chief Financial Officer on December 19, 2012. Edward Z. Fox, formerly Vice President Chief Sustainability Officer changed to Vice President, State and Local Affairs on December 19, 2012. David P. Falck, formerly Executive VP, General Counsel and Secretary, changed to Executive VP and General Counsel on December 19, 2012. Ann Becker,formerly Associate General Counsel, became Vice President, Environmental and Chief Sustainability Officer on December 19, 2012. Diane Wood, formerly Associate General Counsel, became Associate General Counsel and Secretary on December 19, 2012. Ken Bohlen,Vice President and Chief Information Officer, retired December 31, 2012.

14. N/A Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.22

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission X Date of Report (Mo, Da, Yr) Year/Period of Report

End of COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

Line No. Title of Account (a) Ref. Page No. (b) Current Year End of Quarter/Year Balance

(c) Prior Year End Balance 12/31

(d) Arizona Public Service Company 04/10/2013 2012/Q4

UTILITY PLANT 1 14,914,905,234 14,293,093,724 200-201 Utility Plant (101-106, 114) 2 456,350,998 387,396,423 200-201 Construction Work in Progress (107) 3 15,371,256,232 14,680,490,147 TOTAL Utility Plant (Enter Total of lines 2 and 3) 4 5,683,978,497 5,450,571,192 200-201 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5 9,687,277,735 9,229,918,955 Net Utility Plant (Enter Total of line 4 less 5) 6 109,365,418 109,348,410 202-203 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7 0 0 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8 256,728,088 231,473,149 Nuclear Fuel Assemblies in Reactor (120.3) 9 0 0 Spent Nuclear Fuel (120.4) 10 0 0 Nuclear Fuel Under Capital Leases (120.6) 11 133,950,187 113,374,710 202-203 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12 232,143,319 227,446,849 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13 9,919,421,054 9,457,365,804 Net Utility Plant (Enter Total of lines 6 and 13) 14 0 0 Utility Plant Adjustments (116) 15 0 0 Gas Stored Underground - Noncurrent (117) 16 OTHER PROPERTY AND INVESTMENTS 17 5,255,512 5,255,512 Nonutility Property (121) 18 1,688,381 1,665,035 (Less) Accum. Prov. for Depr. and Amort. (122) 19 0 0 Investments in Associated Companies (123) 20 8,746 8,746 224-225 Investment in Subsidiary Companies (123.1) 21 (For Cost of Account 123.1, See Footnote Page 224, line 42) 22 0 0 228-229 Noncurrent Portion of Allowances 23 0 0 Other Investments (124) 24 0 0 Sinking Funds (125) 25 570,625,425 513,732,954 Depreciation Fund (126) 26 0 0 Amortization Fund - Federal (127) 27 311,453 250,211 Other Special Funds (128) 28 0 0 Special Funds (Non Major Only) (129) 29 41,563,063 58,272,888 Long-Term Portion of Derivative Assets (175) 30 0 3,803,618 Long-Term Portion of Derivative Assets – Hedges (176) 31 616,075,818 579,658,894 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32 CURRENT AND ACCRUED ASSETS 33 0 0 Cash and Working Funds (Non-major Only) (130) 34 3,263,558 7,420,504 Cash (131) 35 0 0 Special Deposits (132-134) 36 218,475 218,108 Working Fund (135) 37 17,248 12,234,189 Temporary Cash Investments (136) 38 924,992 924,992 Notes Receivable (141) 39 203,615,582 201,792,722 Customer Accounts Receivable (142) 40 71,198,680 78,291,280 Other Accounts Receivable (143) 41 3,340,209 3,748,325 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42 0 0 Notes Receivable from Associated Companies (145) 43 0 15,545 Accounts Receivable from Assoc. Companies (146) 44 31,334,390 21,999,982 227 Fuel Stock (151) 45 0 0 227 Fuel Stock Expenses Undistributed (152) 46 0 0 227 Residuals (Elec) and Extracted Products (153) 47 218,095,667 204,386,748 227 Plant Materials and Operating Supplies (154) 48 0 0 227 Merchandise (155) 49 0 0 227 Other Materials and Supplies (156) 50 0 0 202-203/227 Nuclear Materials Held for Sale (157) 51 0 0 228-229 Allowances (158.1 and 158.2) 52



### FERC FORM NO. 1 (REV. 12-03) Page110

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission X Date of Report (Mo, Da, Yr) Year/Period of Report

End of COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

Line No. Title of Account (a) Ref. Page No. (b) Current Year End of Quarter/Year Balance

(c) Prior Year End Balance 12/31

(d) Arizona Public Service Company 04/10/2013 2012/Q4 (Continued)

0 0 (Less) Noncurrent Portion of Allowances 53 0 0 227 Stores Expense Undistributed (163) 54 0 0 Gas Stored Underground - Current (164.1) 55 0 0 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56 32,147,460 28,303,420 Prepayments (165) 57 0 0 Advances for Gas (166-167) 58 0 0 Interest and Dividends Receivable (171) 59 0 0 Rents Receivable (172) 60 94,845,364 125,239,466 Accrued Utility Revenues (173) 61 81,483,059 201,328,176 Miscellaneous Current and Accrued Assets (174) 62 84,997,558 136,116,648 Derivative Instrument Assets (175) 63 41,563,063 58,272,888 (Less) Long-Term Portion of Derivative Instrument Assets (175) 64 0 11,090,253 Derivative Instrument Assets - Hedges (176) 65 0 3,803,618 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66 777,238,761 963,537,202 Total Current and Accrued Assets (Lines 34 through 66) 67 DEFERRED DEBITS 68 22,491,524 21,181,437 Unamortized Debt Expenses (181) 69 0 0 230a Extraordinary Property Losses (182.1) 70 0 0 230b Unrecovered Plant and Regulatory Study Costs (182.2) 71 1,200,038,505 1,409,619,466 232 Other Regulatory Assets (182.3) 72 6,401,837 6,012,305 Prelim. Survey and Investigation Charges (Electric) (183) 73 0 0 Preliminary Natural Gas Survey and Investigation Charges 183.1) 74 0 0 Other Preliminary Survey and Investigation Charges (183.2) 75 -96,367 166,152 Clearing Accounts (184) 76 0 0 Temporary Facilities (185) 77 240,529,568 245,310,527 233 Miscellaneous Deferred Debits (186) 78 0 0 Def. Losses from Disposition of Utility Plt. (187) 79 0 0 352-353 Research, Devel. and Demonstration Expend. (188) 80 19,561,430 20,486,731 Unamortized Loss on Reaquired Debt (189) 81 894,894,567 1,078,997,258 234 Accumulated Deferred Income Taxes (190) 82 0 0 Unrecovered Purchased Gas Costs (191) 83 2,383,821,064 2,781,773,876 Total Deferred Debits (lines 69 through 83) 84 13,696,556,697 13,782,335,776 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85



### FERC FORM NO. 1 (REV. 12-03) Page111

### Year/Period of Report Name of Respondent This Report is: (1) An Original (2) A Resubmission x Date of Report (mo, da, yr) end of

Line No. Title of Account (a) Ref. Page No. (b) Current Year End of Quarter/Year Balance

(c) Prior Year End Balance 12/31

(d) Arizona Public Service Company 04/10/2013 2012/Q4 

### COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

PROPRIETARY CAPITAL 1 178,162,367 178,162,367 Common Stock Issued (201) 2 250-251 0 0 Preferred Stock Issued (204) 3 250-251 0 0 Capital Stock Subscribed (202, 205) 4 0 0 Stock Liability for Conversion (203, 206) 5 2,398,807,687 2,398,807,686 Premium on Capital Stock (207) 6 18,400,365 18,400,365 Other Paid-In Capital (208-211) 7 253 0 0 Installments Received on Capital Stock (212) 8 252 0 0 (Less) Discount on Capital Stock (213) 9 254 37,511,652 37,511,652 (Less) Capital Stock Expense (214) 10 254b 1,510,731,982 1,624,229,623 Retained Earnings (215, 215.1, 216) 11 118-119 7,746 7,746 Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119 0 0 (Less) Reaquired Capital Stock (217) 13 250-251 0 0 Noncorporate Proprietorship (Non-major only) (218) 14 -125,591,173 -89,095,286 Accumulated Other Comprehensive Income (219) 15 122(a)(b) 3,943,007,322 4,093,000,849 Total Proprietary Capital (lines 2 through 15) 16 LONG-TERM DEBT 17 655,855,000 565,855,000 Bonds (221) 18 256-257 0 0 (Less) Reaquired Bonds (222) 19 256-257 0 0 Advances from Associated Companies (223) 20 256-257 2,648,177,037 2,599,730,406 Other Long-Term Debt (224) 21 256-257 0 0 Unamortized Premium on Long-Term Debt (225) 22 7,198,492 9,486,025 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 23 3,296,833,545 3,156,099,381 Total Long-Term Debt (lines 18 through 23) 24 OTHER NONCURRENT LIABILITIES 25 0 0 Obligations Under Capital Leases - Noncurrent (227) 26 0 0 Accumulated Provision for Property Insurance (228.1) 27 973,537 1,826,753 Accumulated Provision for Injuries and Damages (228.2) 28 1,260,339,226 1,051,452,575 Accumulated Provision for Pensions and Benefits (228.3) 29 0 0 Accumulated Miscellaneous Operating Provisions (228.4) 30 9,834,939 535,736 Accumulated Provision for Rate Refunds (229) 31 92,880,131 96,654,266 Long-Term Portion of Derivative Instrument Liabilities 32 68,137,406 4,331,681 Long-Term Portion of Derivative Instrument Liabilities - Hedges 33 279,642,641 357,097,415 Asset Retirement Obligations (230) 34 1,711,807,880 1,511,898,426 Total Other Noncurrent Liabilities (lines 26 through 34) 35 CURRENT AND ACCRUED LIABILITIES 36 0 92,175,000 Notes Payable (231) 37 322,040,469 215,589,681 Accounts Payable (232) 38 0 0 Notes Payable to Associated Companies (233) 39 19,566,059 74,317,008 Accounts Payable to Associated Companies (234) 40 72,176,064 79,688,507 Customer Deposits (235) 41 121,338,952 126,056,280 Taxes Accrued (236) 42 262-263 54,454,119 48,741,548 Interest Accrued (237) 43 0 0 Dividends Declared (238) 44 0 0 Matured Long-Term Debt (239) 45



### FERC FORM NO. 1 (rev. 12-03) Page112

### Year/Period of Report Name of Respondent This Report is: (1) An Original (2) A Resubmission x Date of Report (mo, da, yr) end of

Line No. Title of Account (a) Ref. Page No. (b) Current Year End of Quarter/Year Balance

(c) Prior Year End Balance 12/31

(d) Arizona Public Service Company 04/10/2013 2012/Q4 (continued) 

### COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

0 0 Matured Interest (240) 46 6,069 -12,813 Tax Collections Payable (241) 47 131,763,719 156,272,165 Miscellaneous Current and Accrued Liabilities (242) 48 1,029,418 0 Obligations Under Capital Leases-Current (243) 49 217,232,686 200,831,352 Derivative Instrument Liabilities (244) 50 92,880,131 96,654,266 (Less) Long-Term Portion of Derivative Instrument Liabilities 51 150,332,729 5,478,201 Derivative Instrument Liabilities - Hedges (245) 52 68,137,406 4,331,681 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53 928,922,747 898,150,982 Total Current and Accrued Liabilities (lines 37 through 53) 54 DEFERRED CREDITS 55 116,805,411 109,359,166 Customer Advances for Construction (252) 56 58,240,341 99,819,092 Accumulated Deferred Investment Tax Credits (255) 57 266-267 18,307,928 13,734,136 Deferred Gains from Disposition of Utility Plant (256) 58 189,532,594 222,935,180 Other Deferred Credits (253) 59 269 470,102,597 513,088,229 Other Regulatory Liabilities (254) 60 278 501,596 458,291 Unamortized Gain on Reaquired Debt (257) 61 0 0 Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277 2,428,297,226 2,570,393,448 Accum. Deferred Income Taxes-Other Property (282) 63 619,976,589 507,619,517 Accum. Deferred Income Taxes-Other (283) 64 3,901,764,282 4,037,407,059 Total Deferred Credits (lines 56 through 64) 65 13,782,335,776 13,696,556,697 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66



### FERC FORM NO. 1 (rev. 12-03) Page113Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
STATEMENT OF INCOME Arizona Public Service Company X 04/10/2013 2012/Q4

Line

(c) (b) (a) Title of Account No. Total Current Year to Date Balance for

Quarter/Year (d) (Ref.) Page No. 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 Ended Quarterly Only No 4th Quarter (e) Prior 3 Months Ended Quarterly Only No 4th Quarter (f) Total Prior Year to Date Balance for

Quarter/Year

UTILITY OPERATING INCOME 1 3,317,931,261 3,274,438,030 300-301 Operating Revenues (400) 2Operating Expenses 3 1,705,929,816 1,751,027,005 320-323 Operation Expenses (401) 4 205,959,108 210,680,823 320-323 Maintenance Expenses (402) 5 328,826,684 359,134,941 336-337 Depreciation Expense (403) 6 6,495,644 2,494,645 336-337 Depreciation Expense for Asset Retirement Costs (403.1) 7 68,446,302 63,533,348 336-337 Amort. & Depl. of Utility Plant (404-405) 8 336-337 Amort. of Utility Plant Acq. Adj. (406) 9 55,045 96,328 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 431,516 863,035 (Less) Regulatory Credits (407.4) 13 184,088,582 171,393,974 262-263 Taxes Other Than Income Taxes (408.1) 14 279,934 6,901,954 262-263 Income Taxes - Federal (409.1) 15 13,011,314 19,177,086 262-263 - Other (409.1) 16 947,004,484 1,164,902,602 234, 272-277 Provision for Deferred Income Taxes (410.1) 17 703,460,192 986,025,594 234, 272-277 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 18 266 Investment Tax Credit Adj. - Net (411.4) 19 4,573,792 4,573,774 (Less) Gains from Disp. of Utility Plant (411.6) 20Losses from Disp. of Utility Plant (411.7) 21 4,169,987 (Less) Gains from Disposition of Allowances (411.8) 22 4,008,180 179,975 Losses from Disposition of Allowances (411.9) 23Accretion Expense (411.10) 24 2,751,469,606 2,758,060,278 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25 566,461,655 516,377,752 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26

FERC FORM NO. 1/3-Q (REV. 02-04) Page 114Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STATEMENT OF INCOME FOR THE YEAR (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line Previous Year to Date (in dollars) (k) (j) (g) ELECTRIC UTILITY
No. Current Year to Date (in dollars) OTHER UTILITY

(l) GAS UTILITY Previous Year to Date (in dollars) Current Year to Date (in dollars) Previous Year to Date (in dollars) Current Year to Date (in dollars) (h) (i) 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.

1 3,317,931,261 3,274,438,030 2 3 1,705,929,816 1,751,027,005 4 205,959,108 210,680,823 5 328,826,684 359,134,941 6

6,495,644 2,494,645 7 68,446,302 63,533,348 8 9 55,045 96,328 10 11 12 431,516 863,035 13 184,088,582 171,393,974 14

279,934 6,901,954 15 13,011,314 19,177,086 16 947,004,484 1,164,902,602 17 703,460,192 986,025,594 18 19 4,573,792 4,573,774 20 21 4,169,987 22 4,008,180 179,975 23 24 2,751,469,606 2,758,060,278 25 566,461,655 516,377,752 26

FERC FORM NO. 1 (ED. 12-96) Page 115Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STATEMENT OF INCOME FOR THE YEAR (continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line

Previous Year (c) (b) (a) Title of Account No.

Current Year TOTAL

(d) (Ref.) Page No. Current 3 Months Ended Quarterly Only No 4th Quarter (e) Prior 3 Months Ended Quarterly Only No 4th Quarter (f)

566,461,655 516,377,752 Net Utility Operating Income (Carried forward from page 114) 27Other Income and Deductions 28Other Income 29Nonutilty Operating Income 30 1,694,330 2,729,514 Revenues From Merchandising, Jobbing and Contract Work (415) 31 1,093,830 2,042,617 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32 1,500 1,500 Revenues From Nonutility Operations (417) 33 10,329 34,166 (Less) Expenses of Nonutility Operations (417.1) 34 -143,546 486,952 Nonoperating Rental Income (418) 35 119 Equity in Earnings of Subsidiary Companies (418.1) 36 309,580 405,637 Interest and Dividend Income (419) 37 22,435,728 23,706,665 Allowance for Other Funds Used During Construction (419.1) 38 40,044,684 64,271,430 Miscellaneous Nonoperating Income (421) 39 624,094 472,537 Gain on Disposition of Property (421.1) 40 63,862,211 89,997,452 TOTAL Other Income (Enter Total of lines 31 thru 40) 41 Other Income Deductions 42 1,510,980 1,351,992 Loss on Disposition of Property (421.2) 43Miscellaneous Amortization (425) 44 2,552,595 2,250,854 Donations (426.1) 45 -1,418,011 Life Insurance (426.2) 46 5,302,000 10,245 Penalties (426.3) 47 3,078,370 2,905,075 Exp. for Certain Civic, Political & Related Activities (426.4) 48 46,341,213 70,474,982 Other Deductions (426.5) 49 58,785,158 75,575,137 TOTAL Other Income Deductions (Total of lines 43 thru 49) 50Taxes Applic. to Other Income and Deductions 51 901,863 955,111 262-263 Taxes Other Than Income Taxes (408.2) 52 -7,084,804 -9,024,937 262-263 Income Taxes-Federal (409.2) 53 -703,666 -73,171 262-263 Income Taxes-Other (409.2) 54 100,612 152,625 234, 272-277 Provision for Deferred Inc. Taxes (410.2) 55 1,698,590 2,105,305 234, 272-277 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 56Investment Tax Credit Adj.-Net (411.5) 57 2,817,922 473,093 (Less) Investment Tax Credits (420) 58 -11,302,507 -10,568,770 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59 16,379,560 24,991,085 Net Other Income and Deductions (Total of lines 41, 50, 59) 60Interest Charges 61 191,200,337 209,406,256 Interest on Long-Term Debt (427) 62 2,929,008 3,329,780 Amort. of Debt Disc. and Expense (428) 63 1,329,221 1,329,221 Amortization of Loss on Reaquired Debt (428.1) 64(Less) Amort. of Premium on Debt-Credit (429) 65 43,303 43,303 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66Interest on Debt to Assoc. Companies (430) 67 6,899,565 9,454,554 Other Interest Expense (431) 68 14,971,254 18,357,892 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69 187,343,574 205,118,616 Net Interest Charges (Total of lines 62 thru 69) 70 395,497,641 336,250,221 Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71 Extraordinary Items 72Extraordinary Income (434) 73(Less) Extraordinary Deductions (435) 74Net Extraordinary Items (Total of line 73 less line 74) 75 262-263 Income Taxes-Federal and Other (409.3) 76Extraordinary Items After Taxes (line 75 less line 76) 77 395,497,641 336,250,221 Net Income (Total of line 71 and 77) 78

FERC FORM NO. 1/3-Q (REV. 02-04) Page 117Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
STATEMENT OF RETAINED EARNINGS Arizona Public Service Company X 04/10/2013 2012/Q4

Line Current Quarter/Year Year to Date

Balance

(c) (b) (a) Item Contra Primary

No. Account Affected 

### 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.

Previous Quarter/Year Year to Date

Balance

(d) UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1,403,381,761 1,510,731,982 1 Balance-Beginning of Period 2Changes 3Adjustments to Retained Earnings (Account 439) 4 5 6 7 8 9TOTAL Credits to Retained Earnings (Acct. 439) 10 11 12 13 14 15TOTAL Debits to Retained Earnings (Acct. 439) 336,250,221 395,497,641 16Balance Transferred from Income (Account 433 less Account 418.1) 17Appropriations of Retained Earnings (Acct. 436) 18 19 20 21 22TOTAL Appropriations of Retained Earnings (Acct. 436) 23Dividends Declared-Preferred Stock (Account 437) 24 25 26 27 28 29TOTAL Dividends Declared-Preferred Stock (Acct. 437) 30Dividends Declared-Common Stock (Account 438) ( 228,900,000) -282,000,000 31 32 33 34 35 ( 228,900,000) -282,000,000 36TOTAL Dividends Declared-Common Stock (Acct. 438) 37Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 1,510,731,982 1,624,229,623 38Balance - 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 118Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
STATEMENT OF RETAINED EARNINGS Arizona Public Service Company X 04/10/2013 2012/Q4

Line Current Quarter/Year Year to Date

Balance

(c) (b) (a) Item Contra Primary

No. Account Affected 

### 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.

Previous Quarter/Year Year to Date

Balance

(d) 41 42 43 44 45TOTAL Appropriated Retained Earnings (Account 215) APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1) 46TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1) 47TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 1,510,731,982 1,624,229,623 48TOTAL 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 7,746 7,746 49Balance-Beginning of Year (Debit or Credit) 50Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 7,746 7,746 53Balance-End of Year (Total lines 49 thru 52)

FERC FORM NO. 1/3-Q (REV. 02-04) Page 119(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. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
STATEMENT OF CASH FLOWS Arizona Public Service Company X 04/10/2013 2012/Q4

Line Description (See Instruction No. 1 for Explanation of Codes) Current Year to Date Quarter/Year (b) (a) No. Previous Year to Date Quarter/Year (c) 1 Net Cash Flow from Operating Activities: 336,250,221 395,497,641 2Net Income (Line 78(c) on page 117) 3Noncash Charges (Credits) to Income: 361,629,586 335,322,328 4Depreciation and Depletion 129,461,261 144,995,415 5Amortization of UTL PLT; ACQ; ADJ; Prop Loss; Reg Study; Nuclear Fuel 6 -85,991,422 -45,143,221 7Deferred Fuel and Purchased Power 51,149,448 190,018,457 8Deferred Income Taxes (Net) 57,257,852 41,578,751 9Investment Tax Credit Adjustment (Net) 12,965,490 43,308,391 10Net (Increase) Decrease in Receivables -23,397,630 -23,043,326 11 Net (Increase) Decrease in Inventory 12Net (Increase) Decrease in Allowances Inventory 79,231,375 -102,444,105 13Net Increase (Decrease) in Payables and Accrued Expenses -4,782,074 -15,510,752 14Net (Increase) Decrease in Other Regulatory Assets 135,947,579 44,355,108 15Net Increase (Decrease) in Other Regulatory Liabilities 23,706,665 22,435,728 16(Less) Allowance for Other Funds Used During Construction 17(Less) Undistributed Earnings from Subsidiary Companies 18Other (provide details in footnote): 51,761,278 117,062,176 19Other Current Assets 14,714,614 31,025,646 20Other Current Liabilities -4,087,654 -993,853 21 Other Current Long Term Assets/Liabilities Net 1,088,403,259 1,133,592,928 22Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 23 24Cash Flows from Investment Activities: 25Construction and Acquisition of Plant (including land): -837,847,061 -839,770,854 26Gross Additions to Utility Plant (less nuclear fuel) -37,409,363 -25,254,939 27Gross Additions to Nuclear Fuel 28Gross Additions to Common Utility Plant -561,303 29Gross Additions to Nonutility Plant 18,357,892 14,971,255 30(Less) Allowance for Other Funds Used During Construction 31 Other (provide details in footnote): 38,096,640 49,875,809 32Contributions in Aid of Construction 33 -856,078,979 -830,121,239 34Cash Outflows for Plant (Total of lines 26 thru 33) 35 36Acquisition of Other Noncurrent Assets (d) 37Proceeds from Disposal of Noncurrent Assets (d) 38 39Investments in and Advances to Assoc. and Subsidiary Companies 40Contributions and Advances from Assoc. and Subsidiary Companies 41 Disposition of Investments in (and Advances to) 42Associated and Subsidiary Companies 497,779,660 417,603,316 43Proceeds from Nuclear Decommissioning Trust and Sales (a) 44Purchase of Investment Securities (a) 45Proceeds from Sales of Investment Securities (a)

FERC FORM NO. 1 (ED. 12-96) Page 120(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. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
STATEMENT OF CASH FLOWS Arizona Public Service Company X 04/10/2013 2012/Q4

Line Description (See Instruction No. 1 for Explanation of Codes) Current Year to Date Quarter/Year (b) (a) No. Previous Year to Date Quarter/Year (c) 46Loans Made or Purchased 47Collections on Loans -513,798,660 -434,852,259 48Investment in Nuclear Decommissioning Trust and Sales (a) 49Net (Increase) Decrease in Receivables 50Net (Increase ) Decrease in Inventory 51 Net (Increase) Decrease in Allowances Held for Speculation -3,289,484 -24,524,603 52Net Increase (Decrease) in Payables and Accrued Expenses 53Other (provide details in footnote): 41,438,450 -1,098,995 54Investments and Other Assets 55 56Net Cash Provided by (Used in) Investing Activities -833,949,013 -872,993,780 57Total of lines 34 thru 55) 58 59Cash Flows from Financing Activities: 60Proceeds from Issuance of: 295,353,000 351,081,750 61 Long-Term Debt (b) 62Preferred Stock 63Common Stock 64Other (provide details in footnote): 65 92,175,000 66Net Increase in Short-Term Debt (c) 57,536 67Current Obligations for Capital Leases 68 69 295,410,536 443,256,750 70Cash Provided by Outside Sources (Total 61 thru 69) 71 72Payments for Retirement of: -401,029,418 -497,000,000 73Long-term Debt (b) 74Preferred Stock 75Common Stock 76Other (provide details in footnote): -1,029,418 77Current Obligations for Capital Leases 78Net Decrease in Short-Term Debt (c) 79 80Dividends on Preferred Stock -228,900,000 -222,200,000 81 Dividends on Common Stock 82Net Cash Provided by (Used in) Financing Activities -334,518,882 -276,972,668 83(Total of lines 70 thru 81) 84 85Net Increase (Decrease) in Cash and Cash Equivalents -80,064,636 -16,373,520 86(Total of lines 22,57 and 83) 87 99,937,437 19,872,801 88Cash and Cash Equivalents at Beginning of Period 89 19,872,801 3,499,281 90Cash and Cash Equivalents at End of period

FERC FORM NO. 1 (ED. 12-96) Page 121

### Schedule Page: 120 Line No.: 19 Column: b 

## Risk Management $ 120,906,216 Prepaids (3,844,040) $ 117,062,176 Schedule Page: 120 Line No.: 19 Column: c 

## Risk Management $ 56,718,477 Prepaids (4,957,199) $ 51,761,278
Schedule Page: 120 Line No.: 20 Column: b 

## Risk Management $ 14,318,242 Customer Deposits 7,512,443 Tolling Agreements 5,719,632 FERC 4,818,118 Payroll Accrual 4,766,209 Accrued Taxes 4,717,328 SCE Right of Way 1,030,410 Exchange (1,442,484) Employee Benefits (4,249,936) Interest Accrued (5,712,571) Other (451,745) $ 31,025,646
Schedule Page: 120 Line No.: 20 Column: c 

## Risk Management $ 5,691,893 Accrued Taxes 3,923,493 Customer Deposits 3,863,600 Employee Benefits 3,800,845 SCE Right of Way 3,144,010 Software License Agreement (1,946,705) Payroll Accrual (2,651,297) Other (1,111,225) $ 14,714,614 Schedule Page: 120 Line No.: 21 Column: b


## Deferred Fuel MTM $ 37,371,258 Tolling Agreements 36,607,110 Nuclear Decommissioning Trust 17,248,943 Post-Employment Benefits 10,367,924 Utility Plant 6,559,961 FERC Reserve 5,000,000 Transmission Debits 4,635,639 Line of Credit 3,117,942 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

## Superfund 1,267,245 Coal Reclaimation 963,625 SCE Right of Way 721,961 Prepaid Insurance 122,800 Information Systems Maintenance (747,050) Palo Verde Water Supply (1,962,870) Customer Advances for Construction (2,826,308) Rouse Lease (3,692,289) Palo Verde Sale/Leaseback (4,747,579) Banked Energy (7,769,731) Accumulated Provision for Rate Refunds (9,299,203) Risk Management (37,702,761) Depreciation Fund (56,892,470) Other 662,000 $ (993,853)
Schedule Page: 120 Line No.: 21 Column: c 

## Post-Employment Benefits $ 32,496,230 SCE Right of Way 25,815,001 Accumulated Provision for Rate Refunds 9,834,939 Risk Management 5,449,591 Prepaid Insurance (1,009,802) Line of Credit (1,673,990) Palo Verde Water Supply (3,983,647) Rouse Lease (4,617,281) Palo Verde Sale/Leaseback (4,747,579) Information Systems Maintenance (4,793,837) Customer Advances for Construction (5,632,686) Transmission Debits (9,042,199) Utility Plant (14,649,840) Nuclear Decommissioning Trust (27,827,578) Other 295,024 $ (4,087,654) Schedule Page: 120 Line No.: 54 Column: b 

## Post-Employment Benefits $ (1,061,099) Other (37,896) $ (1,098,995) Schedule Page: 120 Line No.: 54 Column: c 

## Post-Employment Benefits $ 41,665,754 Other (227,304) $ 41,438,450 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report Year/Period of Report End of

NOTES TO FINANCIAL STATEMENTS 

### Arizona Public Service Company X 04/10/2013 2012/Q4

PAGE 122 INTENTIONALLY LEFT BLANK SEE PAGE 123 FOR REQUIRED INFORMATION. 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.

FERC FORM NO. 1 (ED. 12-96) Page 122

## 1. Other Comprehensive Basis of Accounting The accompanying financial statements were prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America. These differences include items, such as reporting certain derivatives in the income statement and balance sheet on a gross basis, reporting cost of removal in accumulated provision for depreciation, not separately reporting current accounts for deferred income taxes or long term debt, requiring deferred tax assets and liabilities to be shown gross on the balance sheet, classifying guidance on accounting for uncertainty in income tax liabilities on temporary differences as deferred income tax liabilities, including intangible assets in net utility plant, reclassification of certain risk management assets and liabilities, the non-consolidation of certain variable interest entities on the Comparative Balance Sheet, including prior year financial data for informational purposes only, and certain other items. APS’ notes to financial statements have been combined with Pinnacle West Capital Corporation’s financial statements and are prepared with generally accepted accounting principles, accordingly certain footnotes are not reflective of APS’s financial statements contained herein.

2. Summary of Significant Accounting Policies Nature of Operations APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. Accounting Records and Use of Estimates Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulatory Accounting APS is regulated by the Arizona Corporation Commission and the Federal Energy Regulatory Commission. The accompanying financial statements reflect the rate-making policies of these commissions.As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers. Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction. This determination reflects the current political and Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.1

## regulatory climate in the state 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 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 net these book-outs, which reduces both revenues and fuel and purchased power costs. For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 retail rate case settlement agreement (see Note 4). Effective July 1, 2012, as a result of the 2011 rate case settlement agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues. Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

Allowance for Doubtful Accounts The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment. Utility Plant and Depreciation 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; Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.2

## • 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 on its regulated assets 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 capitalized in accordance with this accounting guidance. We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2012 were as follows:

• Fossil plant – 16 years;

• Nuclear plant – 27 years;

• Other generation – 26 years;

• Transmission – 39 years;

• Distribution – 35 years; and

• Other – 7 years. APS applied for twenty-year extensions of its operating licenses for each of the three Palo Verde units in December 2008. On April 21, 2011, the NRC approved the extensions of the Palo Verde licenses. The nuclear plant remaining life takes into consideration an ACC decision which authorizes the new Palo Verde Nuclear plant lives, effective January 1, 2012. For the years 2010 through 2012, the depreciation rates ranged from a low of 0.45% to a high of 12.08%. The weighted-average rate was 2.71% for 2012, 2.98% for 2011, and 2.98% for 2010. 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 Statement of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation. AFUDC was calculated by using a composite rate of 8.60% for 2012, 10.25% for 2011, and 9.2% for 2010. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.3

## Materials and Supplies APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
Fair Value Measurements We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 7). Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.

See Note 13 for additional information about fair value measurements. Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emission allowances 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. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.4

## We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. See Note 15 for additional information about our derivative instruments. Loss Contingencies and Environmental Liabilities APS is involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, APS records a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Retirement Plans and Other Benefits Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. Pinnacle West also sponsors anotherpostretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provide 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 charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal costs.

Income Taxes Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes. Pinnacle West Capital Corporation files the federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 5). Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.5

## 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 three years (dollars in thousands): Years ended December 31,

2012 2011 2010 Cash paid during the period for: Income taxes, net of (refunds) $ 1,196 

## $ 25,975 $ 81,339 Interest, net of amounts capitalized 196,038 210,995 208,251 Significant non-cash investing and financing activities: Accrued capital expenditures $ 26,208 $ 27,245 $ 19,226 Dividends payable to associated companies but not paid 59,800 -- --

Intangible Assets We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software. The intangible assets are amortized over their finite useful lives. Amortization expense was $50 million in 2012, $47 million in 2011, and $45 million in 2010. Estimated amortization expense on existing intangible assets over the next five years is $45 million in 2013, $37 million in 2014, $28 million in 2015, $20 million in 2016, and $12 million in 2017. At December 31, 2012, the weighted-average remaining amortization period for intangible assets was 6 years.

Investments Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 13 and Note 17 for more information on these investments.

3. New Accounting Standards During 2012, we adopted amended guidance intended to converge fair value measurement and disclosure requirements for GAAP and international financial reporting standards (“IFRS”). The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures. The adoption of this new guidance resulted in additional fair value disclosures (see Note 13), but did not impact our financial statement results. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.6

## 4. Regulatory Matters Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the Settlement Agreement without material modifications. Settlement Agreement The Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate for fuel and purchased power costs from $0.03757 to $0.03207 per kWh; and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million. APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement. Other key provisions of the Settlement Agreement include the following:

• An authorized return on common equity of 10.0%;

• A capital structure comprised of 46.1% debt and 53.9% common equity;

• A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;

• Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:

• Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

• Deferral of 100% in all years if Arizona property tax rates decrease;

• A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.7

## the related closure of Units 1-3 of Four Corners;

• Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;

• Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;

• Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

• A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2008 rate case settlement agreement discussed below;

• Allowing a negative credit that currently exists in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

• Modification of the TCA to streamline the process for future transmission-related rate changes; and

• Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS. The Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2008 rate case settlement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.

2008 General Retail Rate Case On-Going Impacts On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008. The settlement agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

• A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

• Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and

• Various modifications to the existing energy efficiency, demand side management and renewable energy programs that require APS to, among other things, expand its conservation and demand side Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.8

## management programs through 2012 and its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand side management costs and incentives. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms. Renewable Energy Standard.In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requested 2012 RES funding of $129 million to $152 million. On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million. Within that budget, the ACC authorized APS to, among other items, own up to an additional 100 MW under its AZ Sun Program, for a total potential program amount of up to 200 MW. The AZ Sun program, originally approved by the ACC in March 2010, contemplates the development of photovoltaic solar plants which APS will own. Under this program to date, APS has executed contracts for the development of 118 MW of new solar generation, representing an investment commitment of approximately $502 million. On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requested 2013 RES funding of $97 million to $107 million. In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan. That budget includes $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for commercial distributed energy production-based incentives. The ACC further ordered that a hearing take place to consider: (i) APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits; and (ii) removing retail sales to APS’s largest industrial customers when calculating APS’s compliance with the annual RES requirements. Demand Side Management Adjustor Charge.The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC. In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand side management programs over the current year. Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis. The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives. The ACC previously approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2008 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery was amortized over a three-year period, which ended in 2012. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.9

## On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Standards, which became effective January 1, 2011. The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the 2008 retail rate case settlement agreement (2.75% of total energy resources for the same two-year period). The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates. On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan. In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million. Although this proposed budget is approximately $5.6 million more than the approved 2012 budget, the expiration of the three-year amortization of 2009 costs and prior year credits would result in a small decrease in the DSMAC. APS expects to receive a decision from the ACC in the second quarter of 2013.

PSA Mechanism and Balance.The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

• APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

• an adjustment to the PSA rate is made annually each February 1st(unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

• the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

• the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

• the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.10

## The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2012 and 2011 (dollars in millions):

Twelve Months Ended December 31, 2012 2011 Beginning balance $ 28 $ (58) Deferred fuel and purchased power costs – current period (72) (69) Amounts credited to customers 117 155 Ending balance $ 73 $ 28 The PSA rate for the PSA year beginning February 1, 2013 is $0.0013 per kWh as compared to ($0.0042) per kWh for the prior year. This represents a $0.0055 per kWh increase over the 2012 PSA charge. This new rate is comprised of a forward component of ($0.0010) per kWh and a historical component of $0.0023 per kWh. The Settlement Agreement allowed APS to exceed the $0.004 per kWh cap to PSA rate changes in this instance. Any uncollected (overcollected)deferrals during the 2013 PSA year will be included inthe calculation of the PSA rate for the PSA year beginning February 1, 2014. Transmission Rates and Transmission Cost Adjustor

.In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts. Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38 million of this revenue increase relates to Retail Transmission Charges. The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.11

## Effective June 1, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula. Because of higher relative system demand by APS’s retail customers, the approximately $16 million increase reflects roughly a $2 million decrease for wholesale customers and an $18 million increase for APS retail customers. On May 14, 2012, APS filed an application with the ACC to implement the FERC-approved transmission rates for retail customers discussed above. On July 18, 2012, the ACC approved the application authorizing the implementation of the FERC-approved transmission rates for retail customers, which became effective August 2012. As part of APS’s proposed acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing agreement that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California. APS expects to file a request with FERC seeking authorization to cancel the existing agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 29-year period. APS believes the costs associated with the termination of the existing agreement are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance. 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 the Company in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as roof-top solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the recent rate case and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The kWh’s lost from energy efficiency are based on a third-party evaluation of the Company’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques. APS filed its first LFCR adjustment on January 15, 2013 and will file for its LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved an LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the Settlement Agreement went into effect on July 1, 2012. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.12

## Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in millions): December 31, 2012 2011 Pension and other postretirement benefits (a) $ 780 $ 1,023 Income taxes – AFUDC equity 96 84 Deferred fuel and purchased power – mark-to-market (Note 15) 40 77 Transmission vegetation management 32 41 Coal reclamation 32 37 Deferred compensation 34 33 Deferred fuel and purchased power (b) (c) 73 28 Tax expense of Medicare subsidy 18 20 Prior flow through of tax benefits 11 14 Income taxes – investment tax credit basis adjustment 27 15 Pension and other postretirement benefits deferral 21 12 Demand Side Management -- 8 Other 36 18 Total regulatory assets (d) $ 1,200 $ 1,410 (a) This asset represents the future recovery of under-funded pension and other postretirement benefits obligation through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. (b) See “Cost Recovery Mechanisms” discussion above. (c) Subject to a carrying charge. (d) There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.” The detail of regulatory liabilities is as follows (dollars in millions): December 31, 2012 2011 Asset retirement obligations (a) $ 256 $ 225 Renewable energy standard (b) 43 54 Income taxes – change in rates 69 62 Spent nuclear fuel 46 49 Deferred gains on utility property 14 16 Income taxes- deferred investment tax credit 54 31 Excess deferred taxes 11 14 Other 20 19 Total regulatory liabilities $ 513 $ 470 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.13

## (a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal (see Note 12). (b) See “Cost Recovery Mechanisms” discussion above.

5. Income Taxes APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’s taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement. Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted tax rates. APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities primarily relate to deferred taxes resulting from ITCs and the change in income tax rates. In accordance with regulatory requirements, APS investment tax credits 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, 2012 2011 Current: Federal $ (6,805) $ (2,123) State 12,308 19,104 Total current 5,503 16,981 Deferred: Federal 211,758 162,278 State 27,370 14,173 Total deferred 239,128 176,451 Total income tax expense $ 244,631 $ 193,432
On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.14

## The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):

Year Ended December 31, 2012 2011 Federal income tax expense at 35% statutory rate $ 223,963 $ 185,077 Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit 25,379 21,139 Medicare Subsidy Part-D 483 823 Allowance for equity funds used during construction (see Note 2) (6,158) (6,880) Other 964 (6,727) Income tax expense $ 244,631 $ 193,432

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2012, APS has recorded a regulatory liability of $69 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions making qualified property placed into service in 2013 eligible for 50% bonus depreciation for federal income tax purposes. Full recognition of the cash benefit of this provision would delay realization of approximately $4 million in federal general business income tax credit carryforwards which are classified as current assets as of December31, 2012. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.15

## The components of the net deferred income tax liability were as follows (dollars in thousands):

December 31, 2012 2011 DEFERRED TAX ASSETS Regulatory liabilities: Asset retirement obligation and removal costs $ 101,334 $ 89,956 Renewable energy standard -- 19,722 Unamortized investment tax credits 53,837 31,460 Other 35,014 34,283 Risk management activities 81,515 145,087 Pension and other postretirement liabilities 392,486 494,744 Renewable energy incentives 66,941 57,901 Credit and loss carryforwards 52,441 106,668 Other 111,327 99,176 Total deferred tax assets 894,895 1,078,997 DEFERRED TAX LIABILITIES Plant-related (2,570,394) (2,428,297) Risk management activities (33,212) (57,493) Regulatory assets: Allowance for equity funds used during construction (37,899) (33,347) Deferred fuel and purchased power (28,858) (10,884) Deferred fuel and purchased power – mark-to-market (15,796) (30,559) Pension and other postretirement benefits (316,757) (408,716) Other (69,420) (74,215) Other (5,678) (4,763) Total deferred tax liabilities (3,078,014) (3,048,274) Deferred income taxes – net $ (2,183,119) $ (1,969,277)

As of December 31, 2012, the deferred tax assets for credit and loss carryforwards relate to federal general business credits ($50 million) which first begin to expire in 2031 and other federal and state loss carryforwards ($2 million) which first begin to expire in 2017. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.16

## 6. Lines of Credit and Short-Term Borrowings The table below presents the credit facilities and the amounts available and outstanding as of December 31, 2012 (dollars in millions):

Credit Facility Expiration Amount Committed Unused Amount (a) Commitment Fees

APS Revolving Credit Facility November 2016 500 408 0.175% APS Revolving Credit Facility February 2015 500 500 0.20% Total $ 1,000 $ 908 

## (a) At December 31, 2012, APS had $92 million of outstanding commercial paper. Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $908 million. APS maintains committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs. APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2012, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $92 million at December 31, 2012. See “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.17

## The table below presents the credit facilities and the amounts available and outstanding as of December 31, 2011 (dollars in millions):

Credit Facility Expiration Amount Committed Unused Amount (a) Commitment Fees

APS Revolving Credit Facility November 2016 500 500 0.225% APS Revolving Credit Facility February 2015 500 500 0.250% Total $ 1,000 $ 1,000 

## On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2015. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. On November 4, 2011, APS refinanced its $500 million revolving credit facility that would have matured in February 2013, with a new $500 million facility. The new revolving credit facility terminates in November 2016. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings. The facilities described above are available to support its $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. See “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit.

Debt Provisions Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On February 6, 2013, the ACC issued a financing order in which it, subject to specified parameters and procedures, (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.18

## 7. Long-Term Debt and Liquidity Matters All of APS’s debt is unsecured. The following table presents the components of long-term debt on the Comparative Balance Sheets outstanding at December 31, 2012 and 2011 (dollars in thousands):

December 31, Maturity Dates (a) Interest Rates 2012 2011 APS Pollution Control Bonds: Variable 2029-2038 (b) $ 75,580 $ 43,580 Fixed 2024-2034 1.25%-6.00% 490,275 522,275 Pollution control bonds with senior notes 5.05% -- 90,000 Total Pollution Control Bonds 565,855 655,855

Senior unsecured notes 2014-2042 4.50%-8.75% 2,575,000 2,625,000 Capitalized lease obligations (c) -- 1,029 Unamortized discount (9,486) (7,198) Total Long-Term Debt $ 3,131,369 $ 3,274,686 

## (a) This schedule does not reflect the timing of redemptions that may occur prior to maturities. (b) The weighted-average rate for the variable rate pollution control bonds was 0.13%-0.15% at December 31, 2012 and 0.09% at December 31, 2011. (c) The weighted-average interest rate was 5.27% at December 31, 2011. (d) The weighted-average interest rate was 1.312% at December 31, 2012 and 1.794% at December 31, 2011. The following table shows principal payments due on APS’s total long-term debt (dollars in millions):

Year APS 2013 $ 96 2014 515 2015 332 2016 358 2017 -- Thereafter 1,840 Total $ 3,141 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.19

## Debt Fair Value Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within level 2 of the fair value hierarchy. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

As of December 31, 2012 As of December 31, 2011 Carrying Amount Fair Value Carrying Amount Fair Value

Total $ 3,131 $ 3,677 $ 3,275 $ 3,694

Credit Facilities and Debt Issuances On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012. On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project), 2009 Series B, due 2029. On June 1, 2012 these bonds were remarketed. Currently, the interest rate on these bonds is reset daily by a remarketing agent. The daily rate at December 31, 2012 was 0.13% per annum. Additionally, the bonds are supported by a letter of credit. These bonds are classified as long-term debt on our Comparative Balance Sheets at December 31, 2012 and were classified as current maturities of long-term debt on our Comparative Balance Sheets at December 31, 2011. On June 1, 2012, pursuant to the mandatory tender provision, APS changed the interest rate mode for the approximately $38 million of Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A. The new term rate period for these bonds commenced on June 1, 2012, and ends, subject to a mandatory tender, on May 29, 2014. During this time, the bonds will bear interest at a rate of 1.25% per annum. These bonds are classified as long-term debt on our Comparative Balance Sheets at December 31, 2012 and were classified as current maturities of long-term debt on our Comparative Balance Sheets at December 31, 2011. On November 1, 2012 APS redeemed at par all $90 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029. See Lines of Credit and Short-Term Borrowings in Note 6 and “Financial Assurances” in Note 11 for discussion of APS’s other letters of credit. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.20

## 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, 2012, the ratio was approximately 45% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below. None of APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings. All of APS’s bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. APS does not have a material adverse change restriction for credit facility borrowings. An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2012, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.1 billion, and total capitalization was approximately $7.2 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same.
8. Retirement Plans and Other Benefits Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay. Pinnacle West also sponsors another postretirement benefit plan (Pinnacle West Capital Corporation Group Life and Medical Plan) for the employees of Pinnacle West and its subsidiaries. This plan provides medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits. Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 13 for discussion of how fair values are determined. Due to subjective and complex judgments, which may be required Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.21

## in determining fair values, actual results could differ from the results estimated through the application of these methods. A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset. In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over 3 years beginning in July 2012. We amortized approximately $4 million during 2012. On March 23, 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act (the “Act”). One feature of the Act is the elimination of the tax deduction for prescription drug costs that are reimbursed as part of the Medicare Part D subsidy. Although this tax increase does not take effect until 2013, we are required to recognize the full accounting impact in our financial statements in the period in which the Act is signed. In accordance with accounting for regulated companies, the loss of this deduction is substantially offset by a regulatory asset that will be recovered through future electric revenues. In the first quarter of 2010, Pinnacle West charged regulatory assets for a total of $42 million, with a corresponding increase in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law. 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) (dollars in thousands):

Pension Other Benefits 2012 2011 2012 2011 Service cost-benefits earned during the period $ 63,502 $ 57,605 $ 27,163 $ 21,856 Interest cost on benefit obligation 119,586 124,727 46,467 46,807 Expected return on plan assets (140,979) (133,678) (45,793) (41,536) Amortization of: Transition obligation -- -- 452 452 Prior service cost (credit) 1,143 1,400 (179) (179) Net actuarial loss 44,250 25,956 20,233 15,015 Net periodic benefit cost $ 87,502 $ 76,010 $ 48,343 $ 42,415 Portion of cost charged to expense $ 36,333 $ 29,312 $ 19,321 $ 15,208 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.22

## The following table shows the plans’ changes in the benefit obligations and funded status for the years 2012 and 2011 (dollars in thousands):

Pension Other Benefits Change in Benefit Obligation 2012 2011 2012 2011 Benefit obligation at January 1 $ 2,699,126 $ 2,345,060 $ 1,047,094 $ 827,897 Service cost 63,502 57,605 27,163 21,856 Interest cost 119,586 124,727 46,467 46,807 Benefit payments (113,632) (104,257) (26,279) (24,877) Actuarial (gain) loss 82,264 275,991 (104,027) 171,674 Plan amendments -- -- -- 3,737 Benefit obligation at December 31 2,850,846 2,699,126 990,418 1,047,094 Change in Plan Assets Fair value of plan assets at January 1 1,850,550 1,775,596 608,663 567,410 Actual return on plan assets 259,363 162,042 83,567 58,367 Employer contributions 65,000 -- 22,707 18,769 Benefit payments (95,732) (87,088) (30,716) (35,883) Fair value of plan assets at December 31 2,079,181 1,850,550 684,221 608,663

Funded Status at December 31 $ (771,665) $ (848,576) $ (306,197) $ (438,431)

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, 2012 and 2011 (dollars in thousands):

2012 2011 Projected benefit obligation $ 2,850,846 $ 2,699,126 Accumulated benefit obligation 2,646,306 2,396,575 Fair value of plan assets 2,079,181 1,850,550 The following table shows the amounts recognized on the Comparative Balance Sheets as of December 31, 2012 and 2011 (dollars in thousands):

Pension Other Benefits 2012 2011 2012 2011 Current liability $ (19,107) $ (18,097) $ -- $ -- Noncurrent liability (752,558) (830,479) (306,197) (438,431) Net amount recognized $ (771,665) $ (848,576) $ (306,197) $ (438,431) Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.23

## The following table shows the details related to accumulated other comprehensive loss as of December 31, 2012 and 2011 (dollars in thousands):

Pension Other Benefits 2012 2011 2012 2011 Net actuarial loss $ 644,239 $ 724,605 $ 238,862 $ 400,892 Prior service cost (credit) 3,169 4,312 (475) (655) Transition obligation -- -- -- 452 APS’s portion recorded as a regulatory asset (550,471) (632,099) (230,020) (390,521) Income tax benefit (38,303) (38,243) (2,585) (3,296) Accumulated other comprehensive loss $ 58,634 $ 58,575 $ 5,782 $ 6,872
The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2012 (dollars in thousands):

Pension Other Benefits Net actuarial loss $ 37,574 $ 12,236 Prior service cost (credit) 1,097 (179) Total amounts estimated to be amortized from accumulated other comprehensive loss and regulatory assets in 2013 $ 38,671 $ 12,057 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, Benefit Costs For the Years Ended December 31, 2012 2011 2012 2011 2010 Discount rate-pension 4.01% 4.42% 4.42% 5.31% 5.90% Discount rate-other benefits 4.20% 4.59% 4.59% 5.49% 6.00% Rate of compensation increase 4.00% 4.00% 4.00% 4.00% 4.00% Expected long-term return on plan assets N/A N/A 7.75% 7.75% 8.25% Initial health care cost trend rate 7.50% 7.50% 7.50% 8.00% 8.00% Ultimate health care cost trend rate 5.00% 5.00% 5.00% 5.00% 5.00% Number of years to ultimate trend rate 44 4 4 4 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.24

## In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2013, we are assuming a 7.0% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance. Assumed health care cost trend rates above have a significant effect on the amounts reported for the health care plans. In selecting our health care trend rates, we consider past performance and forecasts of health care costs. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):
1% Increase 1% Decrease Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants $ 14 $ (11) Effect on service and interest cost components of net periodic other postretirement benefit costs 17 (13) Effect on the accumulated other postretirement benefit obligation 172 (136)

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 oftrust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis. Long-term fixed income assets, also known as liability-hedging assets, are designed to offset changes in the benefit obligations due to changes in interest rates.Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury, other government agencies, and corporations. Long-term fixed income assets may also includeinterest rate swaps, U.S. Treasury futures and other instruments. Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments primarily include investments in real estate, but may also include private equity and various other strategies. The plan may hold investments in return-generating assets by holding securities in common and collective trusts. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.25

## Based on the IPS, and given the pension plan’s funded status at year-end 2012, the long-term fixed income assets and the return generating assets each had a target allocation of 50%. The return-generating assets have additional target allocations, as a percent of total plan assets, of 30% equities in U.S. and other developed markets, 6% equities in emerging markets, and 14% in alternative investments.The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade. As of December 31, 2012, long-term fixed income assets represented 44% of total pension plan assets, and return-generating assets represented 56% of total pension plan assets. The asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for an asset allocation target mix of at least 25% of fixed income assets and 55% or less of non-fixed income assets. This asset allocation target mix does not vary with the plan’s funded status. As of December 31, 2012, investment in fixed income assets represented 45% of the other postretirement benefit plan total assets, and non-fixed income assets represent 55% of the other postretirement benefit plan’s assets. Fixed income assets are primarily invested incorporate bonds of investment-grade U.S. issuers, and U.S. Treasuries. Non-fixed income assets are primarily invested in large cap U.S. equities in diverse industries, and international equities in both emerging and developed markets. See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied.The plans invest directly in fixed income and equity securities, in addition to investing indirectly in equity securities and real estate through the use of common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2. The common and collective trusts, which are similar to mutual funds, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 index). The common and collective equity trusts are valued using the concept of net asset value (“NAV”), which is a value derived from the quoted active market prices of the underlying securities. The plans’ common and collective real estate trust is valued using NAV, which is derived from the appraised values of the trust’s underlying real estate assets. As of December 31, 2012 the plans were able to transact in the common and collective trusts at NAV and accordingly classify these investments as Level 2. Because the trust’s shares are offered to a limited group of investors, they are not considered to be traded in an active market. The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.26

## The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2012, by asset category, are as follows (dollars in thousands):

Quoted Prices

in Active Markets for

Identical

Assets (Level 1) Significant Other Observable

Inputs (Level 2) Significant Unobservable Inputs (Level 3) Other (c) Balance at December 31, 2012 Pension Plan: Assets: Cash and cash equivalents $ 579 $ -- $ -- $ -- $ 579 Fixed Income Securities: Corporate -- 607,749 -- -- 607,749 U.S. Treasury 232,161 -- -- -- 232,161 Other (b) -- 67,992 -- -- 67,992 Equities: U.S. Companies 531,291 -- -- -- 531,291 International Companies 43,848 -- -- -- 43,848 Common and collective trusts: U.S. Equities -- 176,694 -- -- 176,694 International Equities -- 271,735 -- -- 271,735 Real estate -- 117,854 -- -- 117,854 Short-term investments and other -- 26,922 2,419(a) (63) 29,278

Total Pension Plan $ 807,879 $ 1,268,946 $ 2,419 $ (63) $ 2,079,181 Other Benefits: Assets: Cash and cash equivalents $ 60 $ -- $ -- $ -- $ 60 Fixed Income Securities: Corporate -- 163,306 -- -- 163,306 U.S. Treasury 112,558 -- -- -- 112,558 Other (b) -- 33,998 -- -- 33,998 Equities: U.S. Companies 205,714 -- -- -- 205,714 International Companies 14,412 -- -- -- 14,412 Common and collective trusts: U.S. Equities -- 60,038 -- -- 60,038 International Equities -- 76,969 -- -- 76,969 Real Estate -- 9,378 -- -- 9,378 Short-term investments and other 402 6,340 -- 1,046 7,788

Total Other Benefits $ 333,146 $ 350,029 $ -- $ 1,046 $ 684,221 

## (a) Represents investments in a partnership that invests in privately held portfolio companies. (b) This category consists primarily of debt securities issued by municipalities. (c) Represents plan receivables and payables. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.27

## The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2011, by asset category, are as follows (dollars in thousands):

Quoted Prices

on Active Markets for Identical Assets (Level 1) Significant Other Observable

Inputs (Level 2) Other (a) Balance at December 31, 2011 Pension Plan: Assets: $ 1,441 $ -- $ -- $ 1,441 Cash and cash equivalents Fixed Income Securities: -- 584,619 -- 584,619 Corporate 207,862 -- -- 207,862 U.S. Treasury -- 62,906 -- 62,906 Other (b) Equities: 436,393 -- -- 436,393 U.S. Companies 118,263 -- -- 118,263 International Companies Common and collective trusts: -- 139,321 -- 139,321 U.S. Equities -- 156,407 -- 156,407 International Equities -- 106,147 -- 106,147 Real estate -- 29,913 7,278 37,191 Short-term investments and other

$ 763,959 $ 1,079,313 $ 7,278 $ 1,850,550

Total Pension Plan Other Benefits: Assets: $ 160 $ -- $ -- $ 160 Cash and cash equivalents Fixed Income Securities: -- 148,417 -- 148,417 Corporate 103,321 -- -- 103,321 U.S. Treasury -- 30,105 -- 30,105 Other (b) Equities: 179,235 -- -- 179,235 U.S. Companies 22,486 -- -- 22,486 International Companies Common and collective trusts: -- 52,507 -- 52,507 U.S. Equities -- 53,504 -- 53,504 International Equities -- 8,446 -- 8,446 Real Estate -- 8,516 1,966 10,482 Short-term investments and other

$ 305,202 $ 301,495 $ 1,966 $ 608,663

Total Other Benefits 

## (a) Represents plan receivables and payables. (b) This category consists primarily of debt securities issued by municipalities. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.28

## The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2012 (dollars in thousands):

Short-Term Investments and Other Pension Beginning balance at January 1, 2012 $ -- Actual return on assets still held at December 31, 2012 (668) Purchases, sales, and settlements 3,087 Transfers in and/or out of Level 3 -- Ending balance at December 31, 2012 $ 2,419

Contributions Pinnacle West made contributions to the pension plan totaling $65 million in 2012, and zero in 2011. The minimum contributions for the pension plan due in 2013, 2014 and 2015 under the recently enacted Moving Ahead for Progress in the 21stCentury Act (MAP-21) are estimated to be zero, $89 million and $112 million, respectively. Pinnacle West expects to make voluntary contributions totaling $140 million to the pension plan in 2013, and contributions up to approximately $175 million in each of 2014 and 2015. With regard to contributions to our other postretirement benefit plans, Pinnacle West made a contribution of approximately $23 million in 2012, and $19 million in 2011. The contributions to our other postretirement benefit plans for 2013, 2014 and 2015 are expected to be approximately $20 million each year. APS and other subsidiaries fund their share of the contributions. APS’s share of the pension plan contribution was $64 million in 2012, and zero in 2011. APS’s share of the contributions to the other postretirement benefit plan was $22 million in 2012, and $19 million in 2011. 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 Other Benefits 2013 $ 126,091 $ 26,934 2014 135,602 29,870 2015 145,438 32,929 2016 155,774 35,893 2017 165,535 38,765 Years 2018-2022 971,362 235,170 Electric plant participants contribute to the above amounts in accordance with their respective participation agreements. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.29

## Employee Savings Plan Benefits Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2012, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $8 million for 2012, and $8 million for 2011.

9. Leases We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. APS’s lease expense was $62 million in 2012, $62 million in 2011. Estimated future minimum lease payments for APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in millions):

Year APS 2013 $ 68 2014 64 2015 61 2016 4 2017 3 Thereafter 40 Total future lease commitments $ 240
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. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.30

## 10.Jointly-Owned Facilities APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs, as well as 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, 2012 (dollars in thousands):

Percent Owned Plant in Service Accumulated Depreciation Construction Work in Progress Generating facilities: Palo Verde Units 1 and 3 29.1% $ 1,717,970 $ 1,006,615 $ 15,122 Palo Verde Unit 2 (a) 16.8% 555,132 324,063 4,125 Palo Verde Common 28.0% (b) 516,950 223,632 83,365 Palo Verde Sale Leaseback (a) 351,050 222,055 -- Four Corners Units 4 and 5 15.0% 167,390 36,311 3,040 Four Corners Common 38.4% (b) 58,810 17,930 1,512 Navajo Generating Station Units 1, 2 and 3 14.0% 269,792 141,914 2,368 Cholla common facilities (c) 63.3% (b) 146,571 43,815 1,680 Transmission facilities: ANPP 500kV System 33.3% (b) 82,490 31,511 1,607 Navajo Southern System 22.2% (b) 55,427 15,815 561 Palo Verde – Yuma 500kV System 18.3% (b) 11,761 4,493 797 Four Corners Switchyards 37.0% (b) 20,874 6,033 1,466 Phoenix – Mead System 17.1% (b) 39,772 11,553 -- Palo Verde – Estrella 500kV System 50.0% (b) 85,643 13,309 4,137 Morgan – Pinnacle Peak System 64.1% (b) 133,073 3,751 331 Round Valley System 50.0% (b) 488 261 -- (a) See Note 16. (b) Weighted-average of interests. (c) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.31

## 11.Commitments and Contingencies Palo Verde Nuclear Generating Station Spent Nuclear Fuel and Waste Disposal On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the DOE in the U.S. Court of Federal Claims. The lawsuit seeks to recover APS’s damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. APS currently estimates it will incur $122 million over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2012, APS had a regulatory liability of $46 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance Liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion of liability coverage is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential retrospective assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million. The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidentaloutage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $18 million for each retrospective 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 $48 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. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.32

## Fuel and Purchased Power Commitments and Purchase Obligations APS is party to purchase obligations and various fuel and purchased power contracts with terms expiring between 2013 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $585 million in 2013; $589 million in 2014; $556 million in 2015; $522 million in 2016; $447 million in 2017; and $6.6 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 have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024. The following table summarizes our estimated coal take-or-pay commitments (dollars in millions):

Years Ended December 31,

2013 2014 2015 2016 2017 Thereafter Coal take-or-pay commitments (a) $ 90 $ 93 $ 96 $ 63 $ 27 $121 (a) Total take-or-pay commitments are approximately $490 million. The total net present value of these commitments is approximately $375 million. APS spends more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes the actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in millions):

Year Ended December 31,

2012 2011 2010 Total purchases $ 196 $ 191 $ 156 Renewable Energy Credits APS has entered into contracts to purchase

## renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $51 million in 2013; $40 million in 2014; $41 million in 2015; $40 million in 2016; $40 million in 2017; and $491 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Also, these amounts do not include purchases of renewable energy credits that are associated with purchased power contracts. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.33

## 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 has recorded a final coal mine reclamation obligation of approximately $119 million at December 31, 2012 and $118 million at December 31, 2011. Under our current coal supply agreements, we expect to make payments to certain coal providers for the final mine reclamation as follows: $1 million in 2013; $25 million in 2014; $49 million in 2015; $25 million in 2016; $2 million in 2017; and $17 million thereafter. Any amendments to current coal supply agreements may change the timing of the reimbursement.

FERC Market Issues On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit and ultimately remanded to the FERC for further consideration. On October 3, 2011, the FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001. The first phase of the hearing is currently expected to commence in April 2013. However, APS and Pinnacle West have entered into settlement agreements with all claimants with direct claims against us. The last of these settlement agreements was filed with FERC on December 5, 2012 and is currently pending FERC approval. Thus, we do not expect the outcome of the hearing to have a material adverse impact on our financial position, results of operations or cash flows. Superfund 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 52ndStreet Superfund Site, OU3 in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS has agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.34

## Climate Change Lawsuit In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law. The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages. In June 2008, the defendants filed motions to dismiss the action, which were granted. The plaintiffs filed an appeal with the United States Court of Appeals for the Ninth Circuit in November 2009. On September 21, 2012, a three-judge panel of the Ninth Circuit affirmed the district court’s dismissal of the Kivalinaplaintiffs’ federal common law public nuisance action. The court declined to address any other issue raised by the parties, including the plaintiffs’ state nuisance law claim. On October 4, 2012, the plaintiffs filed a petition for rehearing by the entire Ninth Circuit, but on November 27, 2012, the court denied plaintiffs’ petition. APS continues to believe the action inKivalinais without merit and will continue to defend against both the federal and state claims. Southwest Power Outage On September 8, 2011 at approximately 3:30PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service. Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected. Service to all affected APS customers was restored by 9:15PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9. The FERC and the North American Electric Reliability Corporation (“NERC”) conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) withtheir analysis and conclusions as to the causes of the events. The report includes recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination. The Joint Report does not address potential reliability violations or an assessment of responsibility of the parties involved. APS continues to analyze business practices and procedures related to the September 8 events. APS cannot predict the timing, results or potential impacts of enforcement actions that may be brought against APS relating to the September 8 events, or any claims that may be made as a result of the outages. If violations of NERC Reliability Standards are ultimately determined to have occurred, FERC has the legal authority to assert a possible fine of up to $1 million per violation per day that a violation is found to have been in existence. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.35

## Clean Air Act Lawsuit On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the New Source Review provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss, which are pending. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and CCR. 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 final rulemaking imposing new requirements on Four Corners and Cholla and is currently awaiting a final rulemaking from EPA that could impose new requirements on the Navajo Plant. EPA and ADEQ will require these plants to install pollution control equipment that constitutes the best available retrofit technology to lessen the impacts of emissions on visibility surrounding the plants. Based on EPA’s final standards, APS’s share of its total costs for Four Corners (assuming the consummation of its purchase of SCE’s interest in Units 4 and 5 and subsequent shut down of Units 1-3) could be approximately $300 million. APS’s share of costs for upgrades at Navajo, based on EPA’s FIP proposal, could be up to approximately $158 million. APS has filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, will require installation of controls with a cost to APS of approximately $187 million. Mercury and Other Hazardous Air Pollutants.In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $124 million for Cholla Units 1-3. Estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3. SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules. Other future environmental rules that could involve material compliance costs include those related to cooling water intake structures, coal combustion waste, effluent limitations, ozone national ambient air quality, greenhouse gas emissions and other rules or matters involving the Clean Air Act, Endangered Species Act, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.36

## The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery. Regional Haze Rules – Cholla APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. The State of Arizona and three other utilities also filed similar petitions. On February 4, 2013, APS filed a Petition for Reconsideration and Stay of the final BART rule with EPA.

Financial Assurances APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2012, approximately $76 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. One of these letters of credit expires in 2015 and two expire in 2016. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 16 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire December 31, 2015, and totaled approximately $42 million at December 31, 2012. Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements including certain natural gas tolling contracts entered into with third parties. At December 31, 2012, $65 million of such letters of credit were outstanding that will expire in 2013 and 2015. We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
12.Asset Retirement Obligations APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. In the first quarter of 2011, a new decommissioning study with updated cash flow estimates was completed for Palo Verde. This study reflects the twenty-year license extension approved by the NRC on April 21, 2011, which extends the commencement of decommissioning to 2045. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.37

## 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. The Four Corners coal-fired power plant asset retirement obligation relates to final plant decommissioning, including ash pond closures. In the fourth quarter of 2012, a new study related to ash pond closure was completed which updated the total cost estimates and related cash flow estimates. 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 distribution and transmission assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites. The following schedule shows the change in our asset retirement obligations for 2012 and 2011 (dollars in millions):

2012 2011 Asset retirement obligations at the beginning of year $ 280 $ 329 Changes attributable to: Accretion expense 19 19 Estimated cash flow revisions 58 (68) Asset retirement obligations at the end of year $ 357 $ 280
In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 4.

13.Fair Value Measurements We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are: Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes exchange-traded equities, exchange-traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities. Level 2 – Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities. This category also includes investments in common and collective trusts and commingled funds that are redeemable and valued based on NAV. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

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### FERC FORM NO. 1 (ED. 12-88) Page 123.38

## Level 3 – Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable. Recurring Fair Value Measurements We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 8 for the fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets. Risk Management Activities – Derivative Instruments Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect 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 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 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

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### FERC FORM NO. 1 (ED. 12-88) Page 123.39

## accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points. Option contracts are primarily valued using a Black-Scholes option valuation model which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs. Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization. Investments Held in our Nuclear Decommissioning Trust The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued based on the concept of NAV, which is a value primarily derived from the quoted active market prices of the underlying equity securities. We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2. The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 index. Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities. We may transact in this commingled fund on a daily basis at the NAV. Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies including mortgage-backed instruments are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These instruments are classified as Level 2. Whenever possible multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities. Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services that utilize the valuation methodologies described to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.40

## obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. See Note 17 for additional discussion about our nuclear decommissioning trust.

Fair Value Tables The following table presents the fair value at December 31, 2012 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions): Quoted Prices

in Active Markets for

Identical

Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable

Inputs (a) (Level 3) Other Balance at December 31, 2012 Assets Cash equivalents $ 16 $ -- $ -- $ -- $ 16 Risk management activities – derivative instruments: Commodity Contracts -- 22 62 1 85 Nuclear decommissioning trust: U.S. commingled equity funds -- 204 -- -- 204 Fixed income securities: U.S. Treasury 104 -- -- -- 104 Cash and cash equivalent funds 6 13 -- (4) 15 Corporate debt -- 80 -- -- 80 Mortgage-backed securities -- 83 -- -- 83 Municipality bonds -- 74 -- -- 74 Other -- 11 -- -- 11 Subtotal nuclear decommissioning trust 110 465 -- (4) 571 Total $ 126 $ 487 $ 62 $ (3) $ 672

Liabilities Risk management activities – derivative instruments: Commodity contracts $ -- $ (96) $ (110) $ -- $ (206) 

## (a) Primarily consists of heat rate options and other long-dated electricity contracts. Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.41

## The following table presents the fair value at December 31, 2011 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions): Quoted Prices

in Active Markets for

Identical

Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable

Inputs (a) (Level 3) Other Balance at December 31, 2011 Assets Risk management activities-derivative instruments: Commodity contracts $ -- $ 70 $ 74 $ -- $ 144 Nuclear decommissioning trust: U.S. commingled equity funds -- 175 -- -- 175 Fixed income securities: U.S. Treasury 69 -- -- -- 69 Cash and cash equivalent funds -- 9 -- (1) 8 Corporate debt -- 73 -- -- 73 Mortgage-backed securities -- 78 -- -- 78 Municipality bonds -- 90 -- -- 90 Other -- 21 -- -- 21 Subtotal nuclear decommissioning trust 69 446 -- (1) 514 Total $ 69 $ 516 $ 74 $ (1) $ 658

Liabilities Risk management activities – derivative instruments: Commodity contracts $ -- $ (241) $ (125) $ -- $ (366) 

## (a) Primarily consists of heat rate options and other long-dated electricity contracts.

Fair Value Measurements Classified as Level 3 The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.42

## would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease. Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The significant unobservable inputs for these instruments include electricity prices, gas prices and implied volatilities. If electricity prices and electricity price implied volatilities increase we would expect the fair value of these options to increase, and if these valuation inputs decrease we would expect the fair value of these options to decrease. If natural gas prices and natural gas price implied volatilities increase we would expect the fair value of these options to decrease, and if these inputs decrease we would expect the fair value of the options to increase. The commodity prices and implied volatilities do not always move in corresponding directions. The options’ fair values are impacted by the net changes of these various inputs. Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements. The following table provides information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments:

December 31, 2012 Fair Value (millions) Commodity Contracts Assets Liabilities Valuation Technique Significant Unobservable Input Range WeightedAverage Electricity: Forward Contracts (a) $ 57 $ 82 Discounted cash flows Electricity forward price (per MWh) $23.06 - $64.20 $43.16 Option Contracts -- 27 Option model Electricity forward price (per MWh) $36.66 - $92.19 $60.97 Natural gas forward price (per mmbtu) $4.10 - $4.25 $4.20 Implied electricity price volatilities 15% - 66% 39% Implied natural gas price volatilities 17% - 36% 23% Natural Gas: Forward Contracts (a) 5 1 Discounted cash flows Natural gas forward price (per mmbtu) $3.25 - $4.44 $3.93 Total $ 62 $ 110 

## (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 Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.43

## that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2012 and 2011 (dollars in millions):

Commodity Contracts Year Ended December 31, 2012 2011 Net derivative balance at beginning of period $ (51) $ (38) Total net gains (losses) realized/unrealized: Included in earnings 2 2 Included in OCI (3) (5) Deferred as a regulatory asset or liability 7 (10) Settlements (5) 11 Transfers into Level 3 from Level 2 (2) (4) Transfers from Level 3 into Level 2 4 (7) Net derivative balance at end of period $ (48) $ (51)
Net unrealized gains included in earnings related to instruments still held at end of period $ -- $ 1 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 heat rate options and 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. For our long-term debt fair values see Note 7.
14.Stock-Based Compensation Pinnacle West grants long-term incentive awards under the 2012 long-term incentive plan (“2012 Plan”) in the form of Stock Grants, Restricted Stock Units and Performance Shares and may grant restricted stock, stock units, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan, effective May 16, 2012, provides 4,595,500 common shares to be available for grant to eligible employees and members of the Board of Directors. Awards made in 2012 were issued under the 2012 Plan, prior awards from 2007 to 2011 were issued under the 2007 long-term incentive plan (“2007 Plan”). Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.44

## Restricted Stock Unit Awards and Stock Grants Stock grants issued to non-officer members of the Board of Directors (“Directors”) in 2012, 2011 and 2010, provided Directors the option to elect to receive a stock grant, or to defer receipt until a later date and receive restricted stock units in lieu of the stock grant. Directors who elect to defer may elect to receive payment in either stock, or 50% in cash and 50% in stock. The Director may elect to receive payments either as of the last business day of the month following the month in which they separate from service on the Board, or as of a specified date, which must be after December 31 of the year in which the grant was received. The deferred restricted stock units accrue dividend rights equal to the amount of dividends the Director would have received had they directly owned stock equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, or 50% in cash and 50% in stock. Restricted stock units were granted to officers and key employees in each year since 2007. From 2007 through 2009, officers and key employees elected to receive payment in either cash or in fully transferable shares of stock, in exchange for each restricted stock unit on pre-established valuation dates. In 2010, 2011 and 2012, officers and key employees elected to receive payment in either stock, or 50% cash and 50% stock. Restricted stock unit awards vest and settle over a four-year period. In addition, officers and key employees accrue dividend rights on the vested restricted stock units, equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest for the 2007 through 2009 awards are paid in cash. The dividends and interest for the 2010, 2011 and 2012 awards are paid in the same form as the restricted stock unit payment election. Restricted stock unit awards are accounted for as a liability award, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately. On December 19, 2012, the Company granted a retention award of 50,617 restricted stock units to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West. The award will vest and will be paid in shares of common stock on December 31, 2016 provided that he remains employed with the Company until the vesting date. The award can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met. A grant of restricted stock unit awards was made to officers of the company on February 15, 2011, payable solely in shares of common stock upon the officer’s retirement or other separation of employment. This award will vest 50% on February 15, 2013, 25% on February 15, 2014 and 25% on February 15, 2015, provided that the officer remains employed on such date. The officers will also accrue notional dividends equal to the amount of dividends that an officer would have received if the officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held by the officer from the grant date to each dividend payment date. Each additional restricted stock unit will proportionally vest on the same remaining vesting schedule that applies to the original restricted stock unit.

The following table is a summary of granted restricted stock units and stock grants and the weighted-average Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.45

## fair value for the three years ended 2012, 2011 and 2010:

2012 2011 2010 Units granted 202,278 292,242 202,341 Grant date fair value (a) $49.31 $41.98 $37.47 (a) Weighted-average grant date fair value The following table is a summary of the status of restricted stock units and stock grants, as of December 31, 2012 and changes during the year. This table represents only the stock portion of restricted stock units, per the election on payment discussed in the paragraph above:

Nonvested shares Shares Weighted-Average Grant-Date Fair Value Nonvested at January 1, 2012 416,231 $ 39.61 Granted 202,278 49.31 Vested 126,959 39.76 Forfeited 10,797 42.63 Nonvested at December 31, 2012 480,753 43.58

The amount of cash required to settle the payments on restricted stock units is (dollars in millions):

Year 2012 2011 2010 2007 Grant $ -- $ 1.0 $ 0.9 2008 Grant 1.9 1.6 1.5 2009 Grant 1.7 1.5 1.4 2010 Grant 0.6 0.6 -- 2011 Grant 0.7 -- -- Performance Share Awards Performance share awards were granted to officers and key employees under the 2012 Plan in 2012 and under the 2007 Plan from 2008 to 2011. Performance share awards contain two performance element criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met. The 2012, 2011 and 2010 performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s total shareholder return at the end of the three-year performance period as compared with the total shareholder return of all relevant companies in a specified utility index and the other 50% based upon six non-financial separate performance metrics. The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

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### FERC FORM NO. 1 (ED. 12-88) Page 123.46

## Performance share awards are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately. Management also evaluates the probability of meeting the performance criteria at each balance sheet date. If the performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed. The following table is a summary of the performance shares granted and the weighted-average fair value for the three years ended 2012, 2011 and 2010:

2012 2011 2010 Units granted (a) 185,878 175,072 178,722 Grant date fair value (b) $47.40 $41.71 $37.57 (a) Reflects the target payout level. (b) Weighted-average grant date fair value. The following table is a summary of the status of performance shares, as of December 31, 2012 and changes during the year:

Nonvested shares (a) Shares Weighted-Average Grant-Date Fair Value Nonvested at January 1, 2012 347,946 $ 39.64 Granted 185,878 47.40 Increase in performance factor 87,037 37.57 Vested 257,127 37.57 Forfeited 16,044 42.53 Nonvested at December 31, 2012 347,690 44.67 (a) Nonvested shares are reflected at the target payout level. The increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests.

Retention Units The retention unit awards have fully vested and settled on January 4, 2010; for any employee that was eligible to retire before that date, the employee’s retention units vested by retirement date and the compensation expense was recognized by retirement eligibility. Retention unit awards were granted to key employees in 2006 and 2007. Each retention unit award represented the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. Each retention unit award vested and settled in equal annual installments over a four-year period. In addition, the employee received a cash payment equal to the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. As this award was accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, were remeasured at each balance sheet date, using Pinnacle West’s closing stock price. Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.47

## The amount of cash to settle the payment on the first business day of 2010 was $1.3 million. Stock Options The Company has not granted stock options since 2004. Outstanding stock option grant terms cannot be longer than 10 years and options cannot be repriced during their terms. The following table summarizes the option activity under prior equity incentive plans for the year ended December 31, 2012:

Options Shares Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term (Years) Aggregate Intrinsic Value (dollars in thousands) Outstanding at January 1, 2012 22,958 $ 34.75 Exercised 15,033 36.05 Forfeited or expired -- -- Outstanding at December 31, 2012 7,925 32.29 .21 $ 148 Exercisable at December 31, 2012 7,925 32.29 .21 $ 148 Cash received from options exercised under our share-based payment arrangements was $0.5 million for 2012, $1.8 million for 2011, and $4.6 million for 2010. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements were immaterial for all years. The intrinsic value of options exercised was immaterial for all years. As of December 31, 2012, there was $17 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 2.0 years. The total fair value of shares vested during 2012 was $19 million, 2011 was $14 million, and 2010 was $11 million. The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $32 million in 2012, $23 million in 2011, and $15 million in 2010. The compensation cost that Pinnacle West has capitalized is immaterial for all years. Pinnacle West’s total income tax benefit recognized in the Comparative Statements of Income for share-based compensation arrangements was $13 million in 2012, $9 million in 2011, and $6 million in 2010. APS’s share of compensation cost that has been charged against income was $32 million in 2012, $22 million in 2011, and $15 million in 2010. Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares except to satisfy tax withholding obligations upon the vesting of restricted stock units and performance shares. Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.48

## 15.Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Comparative Statements of Income, but does not impact our financial condition, net income or cash flows. On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow hedges. This discontinuation is due to changes in PSA recovery (see Note 4), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts. For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through OCI, but are deferred through the PSA. The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur. Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery. Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 13 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below. Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of OCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As cash flow hedge accounting has been discontinued for the significant majority of our contracts, effective June 1, 2012, effectiveness testing is no longer being performed for these contracts. Name of Respondent

Arizona Public Service Company 

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### FERC FORM NO. 1 (ED. 12-88) Page 123.49

## Prior to the Settlement Agreement, for its regulated operations, APS deferred for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Due to the Settlement Agreement, for its regulated operations, APS now defers for future rate treatment 100% of the unrealized gains and losses for delivery periods after June 30, 2012 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, 2012, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Commodity Quantity Power 8,045 gigawatt hours Gas 139 Bcfs (a) (a) “Bcf” is Billion Cubic Feet.

Gains and Losses from Derivative Instruments The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2012, 2011 and 2010 (dollars in thousands):

Year Ended December 31, Commodity Contracts Financial Statement Location 2012 2011 2010

Loss Recognized in OCI on Derivative Instruments (Effective Portion) Other comprehensive loss – derivative instruments $ (37,663) $ (94,660) $ (155,287) Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized) (a) Fuel and purchased power (99,007) (117,189) (122,740) Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) Fuel and purchased power 117 (211) 3,680 

## (a) During the year ended December 31, 2012, we had $1.8 million of losses reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges. There were no amounts reclassified in the 2011 and 2010 periods related to discontinued cash flow hedges. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.50

## During the next twelve months, we estimate that a net loss of $44 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings. The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2012, 2011 and 2010 (dollars in thousands):

Year Ended December 31, Commodity Contracts Financial Statement Location 2012 2011 2010 Net Gain (Loss) Recognized in Income Operating revenues $ 103 $ (27) $ 1,436

Net Loss Recognized in Income Fuel and purchased power (2,747) (52,113) (107,690) Total $ (2,644) $ (52,140) $ (106,254) 

## Fair Values of Derivative Instruments in the Comparative Balance Sheets The following table provides information about the fair value of our risk management activities reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the Comparative Balance Sheets. These amounts are located in the assets and liabilities from risk management activities lines of our Comparative Balance Sheets. Amounts are as of December 31, 2012 (dollars in thousands):

Commodity Contracts Designated as Hedging Instruments Not Designated as Hedging Instruments Margin and Collateral Provided to Counterparties Collateral Provided from Counterparties(a) Other (b) Total Current Assets $ -- $ 42,495 $ 49,361 $ -- $ 939 $ 92,795 Investments and Other Assets -- 41,563 -- -- -- 41,563 Total Assets -- 84,058 49,361 -- 939 134,358

Current Liabilities (1,147) (104,177) -- (25,463) -- (130,787) Deferred Credits and Other (4,332) (96,654) -- -- -- (100,986) Total Liabilities (5,479) (200,831) -- (25,463) -- (231,773) Total $ (5,479) $ (116,773) $ 49,361 $ (25,463) $ 939 $ (97,415) 

## (a) Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception. (b) Other represents derivative instrument netting, option premiums, and other risk management contracts. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.51

## The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2011 (dollars in thousands):

Commodity Contracts Designated as Hedging Instruments Not Designated as Hedging Instruments Margin and Collateral Provided to Counterparties Collateral Provided from Counterparties (a) Other (b) Total Current Assets $ 7,287 $ 76,162 $ 174,626 $ -- $ 1,681 $ 259,756 Investments and Other Assets 3,804 58,273 -- -- -- 62,077 Total Assets 11,091 134,435 174,626 -- 1,681 321,833

Current Liabilities (82,195) (124,028) -- (11,145) (325) (217,693) Deferred Credits and Other (68,137) (92,880) -- -- -- (161,017) Total Liabilities (150,332) (216,908) -- (11,145) (325) (378,710) Total Derivative Instruments $ (139,241) $ (82,473) $ 174,626 $ (11,145) $ 1,356 $ (56,877) 

## (a) Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception. (b) Other represents derivative instrument netting, option premiums, and other risk management contracts. Credit Risk and Credit Related Contingent Features We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 86% of APS’s $62 million of risk management assets as of December 31, 2012. This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.52

## The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2012 (dollars in millions): December 31, 2012 Aggregate Fair Value of Derivative Instruments in a Liability Position $ 206 Cash Collateral Posted 49 Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a) 120 (a) 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 $183 million if our debt credit ratings were to fall below investment grade.
16.Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will pay approximately $49 million per year for the years 2013 to 2015 related to these leases. APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2012, APS would have been required to pay the noncontrolling equity participants approximately $139 million and assume $66 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Comparative Balance Sheets.
17.Nuclear Decommissioning Trusts To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Comparative Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities

.

## The following table includes the unrealized gains and losses based on the original cost of the investment Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.53

## and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2012 and December 31, 2011 (dollars in millions):

Fair Value Total Unrealized Gains Total Unrealized

Losses December 31, 2012 Equity securities $ 204 $ 67 $ -- Fixed income securities 371 24 -- Net payables (a) (4) -- -- Total $ 571 $ 91 $ --

Fair Value Total Unrealized Gains Total Unrealized

Losses December 31, 2011 Equity securities $ 175 $ 44 $ (1) Fixed income securities 340 23 (1) Net payables (a) (1) -- -- Total $ 514 $ 67 $ (2)
(a) Net payables relate to pending securities sales and purchases. The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions): Year Ended December 31, 2012 2011 2010 Realized gains $ 7 $ 8 $ 17 Realized losses (4) (5) (4) Proceeds from the sale of securities (a) 418 498 560 (a) Proceeds are reinvested in the trust. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.54

## The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2012 is as follows (dollars in millions):

Fair Value Less than one year $ 14 1 year – 5 years 97 5 years – 10 years 109 Greater than 10 years 151 Total $ 371 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.55Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. 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.

Other Adjustments (e) Foreign Currency Hedges

(d) Minimum Pension Liability adjustment (net amount) (c) Unrealized Gains andLosses on Availablefor-Sale Securities (b) Item

(a)

( 35,960,956) Balance of Account 219 at Beginning of Preceding Year 1

2,935,457 Preceding Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 2

( 5,860,745) Preceding Quarter/Year to Date Changes in Fair Value 3

( 2,925,288) Total (lines 2 and 3) 4

( 38,886,244) Balance of Account 219 at End of Preceding Quarter/Year 5

( 38,886,244) Balance of Account 219 at Beginning of Current Year 6

3,479,957 Current Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 7

( 4,096,681) Current Quarter/Year to Date Changes in Fair Value 8

( 616,724) Total (lines 7 and 8) 9

( 39,502,968) Balance of Account 219 at End of Current Quarter/Year 10

FERC FORM NO. 1 (NEW 06-02) Page 122aOther Cash Flow Hedges [Specify] (g) Other Cash Flow Hedges Interest Rate Swaps (f) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Total Comprehensive Income

(j) Net Income (Carried Forward from Page 117, Line 78) (i) Totals for each category of items

recorded in Account 219 (h) ( 136,294,557) ( 100,333,601) 1 73,826,600 70,891,143 2 ( 63,123,216) ( 57,262,471) 3 336,250,221 346,953,605 10,703,384 13,628,672 4 ( 125,591,173) ( 86,704,929) 5 ( 125,591,173) ( 86,704,929) 6 63,367,481 59,887,524 7 ( 26,871,594) ( 22,774,913) 8 395,497,641 431,993,528 36,495,887 37,112,611 9 ( 89,095,286) ( 49,592,318) 10

FERC FORM NO. 1 (NEW 06-02) Page 122bName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (b) (a) Classification Electric (c) FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Total Company for the Current Year/Quarter Ended 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.

Utility Plant 1 In Service 2 14,398,115,244 14,398,115,244 Plant in Service (Classified) 3Property Under Capital Leases 4Plant Purchased or Sold 5 462,907,933 462,907,933 Completed Construction not Classified 6Experimental Plant Unclassified 7 14,861,023,177 14,861,023,177 Total (3 thru 7) 8Leased to Others 9 53,882,057 53,882,057 Held for Future Use 10 456,350,998 456,350,998 Construction Work in Progress 11 Acquisition Adjustments 12 15,371,256,232 15,371,256,232 Total Utility Plant (8 thru 12) 13 5,683,978,497 5,683,978,497 Accum Prov for Depr, Amort, & Depl 14 9,687,277,735 9,687,277,735 Net Utility Plant (13 less 14) 15Detail of Accum Prov for Depr, Amort & Depl 16In Service: 17 5,136,337,746 5,136,337,746 Depreciation 18Amort & Depl of Producing Nat Gas Land/Land Right 19Amort of Underground Storage Land/Land Rights 20 547,640,751 547,640,751 Amort of Other Utility Plant 21 5,683,978,497 5,683,978,497 Total In Service (18 thru 21) 22Leased to Others 23Depreciation 24Amortization and Depletion 25Total Leased to Others (24 & 25) 26Held for Future Use 27Depreciation 28Amortization 29Total Held for Future Use (28 & 29) 30Abandonment of Leases (Natural Gas) 31 Amort of Plant Acquisition Adj 32 5,683,978,497 5,683,978,497 Total Accum Prov (equals 14) (22,26,30,31,32) 33

FERC FORM NO. 1 (ED. 12-89) Page 200(g) Common (h) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. FOR DEPRECIATION. AMORTIZATION AND DEPLETION Gas Other (Specify) (d) (e) (f) Other (Specify) Other (Specify)

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 201Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description of item Balance (c) (b) (a) Changes during Year Beginning of Year Additions 

### 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.

Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) 1 Fabrication 36,691,948 25,695,669 2 Nuclear Materials 62,693,685 44,141,618 3Allowance for Funds Used during Construction 10,118,084 9,141,375 4 (Other Overhead Construction Costs, provide details in footnote) -155,307 2,643,390 5 SUBTOTAL (Total 2 thru 5) 109,348,410 6 Nuclear Fuel Materials and Assemblies 7 In Stock (120.2) 81,605,045 8 In Reactor (120.3) 231,473,149 81,605,046 9 SUBTOTAL (Total 8 & 9) 231,473,149 10 Spent Nuclear Fuel (120.4) 11 Nuclear Fuel Under Capital Leases (120.6) 12 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 113,374,710 13TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 227,446,849 14 Estimated net Salvage Value of Nuclear Materials in line 9 15 Estimated net Salvage Value of Nuclear Materials in line 11 16 Est Net Salvage Value of Nuclear Materials in Chemical Processing 17 Nuclear Materials held for Sale (157) 18 Uranium 19 Plutonium 20 Other (provide details in footnote): 21 TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21) 22

FERC FORM NO. 1 (ED. 12-89) Page 202Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Balance

(f) (e) (d) Changes during Year End of Year Amortization Other Reductions (Explain in a footnote)
1 2 31,431,934 30,955,683 3 40,051,369 66,783,934 4 7,478,351 11,781,108 5 2,643,390 -155,307 6 109,365,418 7 8 81,605,045 9 56,350,107 256,728,088 10 256,728,088 11 12 13 56,350,107 133,950,187 -76,925,584 14 232,143,319 15 16 17 18 19 20 21 22

FERC FORM NO. 1 (ED. 12-89) Page203

### Schedule Page: 202 Line No.: 2 Column: e Transfer of Fuel in Process to Fuel in Stock Schedule Page: 202 Line No.: 3 Column: e Transfer of Fuel in Process to Fuel in Stock Schedule Page: 202 Line No.: 4 Column: c Increase relates to AFUDC for material previously charged to FERC acct. 120.2 Schedule Page: 202 Line No.: 4 Column: e Transfer related to AFUDC cost from Fuel in Process to Fuel in Stock Schedule Page: 202 Line No.: 5 Column: e Transfer Use Tax Cost form Fuel in Process to Fuel in Stock Schedule Page: 202 Line No.: 8 Column: e Transfer of Fuel in Stock to Fuel in Reactor Schedule Page: 202 Line No.: 9 Column: e Retirement of Fuel in Reactor Schedule Page: 202 Line No.: 13 Column: d Amortization/Retirement of Fuel in Reactor Schedule Page: 202 Line No.: 13 Column: e Retirement of Fuel in Reactor Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account Balance Additions (c) (b) (a) Beginning of Year 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)

1. INTANGIBLE PLANT 1 (301) Organization 2 (302) Franchises and Consents 3,424,429 25,782 3 (303) Miscellaneous Intangible Plant 554,923,961 42,701,620 4TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 558,348,390 42,727,402 5 2. PRODUCTION PLANT 6A. Steam Production Plant 7 (310) Land and Land Rights 5,828,482 242 8 (311) Structures and Improvements 173,273,600 12,119,436 9 (312) Boiler Plant Equipment 1,126,640,886 32,746,276 10 (313) Engines and Engine-Driven Generators 11 (314) Turbogenerator Units 258,567,285 7,919,200 12 (315) Accessory Electric Equipment 162,018,051 2,633,782 13 (316) Misc. Power Plant Equipment 98,266,442 -15,463,182 14 (317) Asset Retirement Costs for Steam Production 12,975,896 59,472,962 15TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 1,837,570,642 99,428,716 16 B. Nuclear Production Plant 17 (320) Land and Land Rights 4,521,619 -30,278 18 (321) Structures and Improvements 736,048,948 22,649,048 19 (322) Reactor Plant Equipment 1,187,407,438 6,256,495 20 (323) Turbogenerator Units 367,460,220 9,322,995 21 (324) Accessory Electric Equipment 277,414,164 4,801,579 22 (325) Misc. Power Plant Equipment 148,509,967 15,687,726 23 (326) Asset Retirement Costs for Nuclear Production -28,495,803 1,401,365 24TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 2,692,866,553 60,088,930 25 C. Hydraulic Production Plant 26 (330) Land and Land Rights 27 (331) Structures and Improvements 28 (332) Reservoirs, Dams, and Waterways 29 (333) Water Wheels, Turbines, and Generators 30 (334) Accessory Electric Equipment 31 (335) Misc. Power PLant Equipment 32 (336) Roads, Railroads, and Bridges 33 (337) Asset Retirement Costs for Hydraulic Production 34TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 35 D. Other Production Plant 36 (340) Land and Land Rights 7,816,314 2,003,167 37 (341) Structures and Improvements 70,667,183 8,592,513 38 (342) Fuel Holders, Products, and Accessories 47,972,020 1,274,259 39 (343) Prime Movers 634,587,225 7,997,892 40 (344) Generators 818,689,790 136,967,336 41 (345) Accessory Electric Equipment 97,519,693 32,405,186 42 (346) Misc. Power Plant Equipment 18,105,008 1,478,289 43 (347) Asset Retirement Costs for Other Production 44TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 1,695,357,233 190,718,642 45TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 6,225,794,428 350,236,288 46

Page 204 FERC FORM NO. 1 (REV. 12-05)ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account Balance Additions (c) (b) (a) Beginning of Year

3. TRANSMISSION PLANT 47 (350) Land and Land Rights 144,692,883 9,757,471 48 (352) Structures and Improvements 82,475,618 2,581,037 49 (353) Station Equipment 868,416,763 41,990,869 50 (354) Towers and Fixtures 104,649,311 1,529,276 51 (355) Poles and Fixtures 413,144,379 11,856,096 52 (356) Overhead Conductors and Devices 348,635,832 16,367,766 53 (357) Underground Conduit 20,587,963 117,462 54 (358) Underground Conductors and Devices 31,290,877 1,393,375 55 (359) Roads and Trails 56 (359.1) Asset Retirement Costs for Transmission Plant 57TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 2,013,893,626 85,593,352 58 4. DISTRIBUTION PLANT 59 (360) Land and Land Rights 50,090,477 1,435,573 60 (361) Structures and Improvements 63,615,851 4,572,977 61 (362) Station Equipment 429,187,104 26,967,421 62 (363) Storage Battery Equipment 63 (364) Poles, Towers, and Fixtures 498,376,210 31,712,288 64 (365) Overhead Conductors and Devices 307,393,321 2,325,624 65 (366) Underground Conduit 630,386,957 15,312,905 66 (367) Underground Conductors and Devices 1,456,977,856 47,222,515 67 (368) Line Transformers 741,561,623 32,214,971 68 (369) Services 334,561,609 8,937,040 69 (370) Meters 218,674,402 48,608,646 70 (371) Installations on Customer Premises 40,629,555 1,114,019 71 (372) Leased Property on Customer Premises 72 (373) Street Lighting and Signal Systems 75,073,660 274,471 73 (374) Asset Retirement Costs for Distribution Plant 74TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 4,846,528,625 220,698,450 75 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76 (380) Land and Land Rights 77 (381) Structures and Improvements 78 (382) Computer Hardware 79 (383) Computer Software 80 (384) Communication Equipment 81 (385) Miscellaneous Regional Transmission and Market Operation Plant 82 (386) Asset Retirement Costs for Regional Transmission and Market Oper 83TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 84 6. GENERAL PLANT 85 (389) Land and Land Rights 14,636,876 26,421 86 (390) Structures and Improvements 166,553,207 5,119,987 87 (391) Office Furniture and Equipment 148,708,496 31,329,195 88 (392) Transportation Equipment 37,915,709 2,320,172 89 (393) Stores Equipment 256,764 90 (394) Tools, Shop and Garage Equipment 29,728,420 4,264,718 91 (395) Laboratory Equipment 1,077,783 92 (396) Power Operated Equipment 11,778,714 93 (397) Communication Equipment 169,945,091 23,385,468 94 (398) Miscellaneous Equipment 10,099,577 2,421,052 95 SUBTOTAL (Enter Total of lines 86 thru 95) 590,700,637 68,867,013 96 (399) Other Tangible Property 97 (399.1) Asset Retirement Costs for General Plant 98TOTAL General Plant (Enter Total of lines 96, 97 and 98) 590,700,637 68,867,013 99TOTAL (Accounts 101 and 106) 14,235,265,706 768,122,505 100 (102) Electric Plant Purchased (See Instr. 8) 101 (Less) (102) Electric Plant Sold (See Instr. 8) 102 (103) Experimental Plant Unclassified 103TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 14,235,265,706 768,122,505 104

Page 206 FERC FORM NO. 1 (REV. 12-05)(f) Transfers Balance at End of Year Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (g) Adjustments (e) Retirements (d) 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

1 2 3,443,953 6,258 3 585,363,661 117,109 12,379,029 4 588,807,614 117,109 12,385,287 5 6 7 5,794,738 -33,986 8 183,850,976 1,542,060 9 1,155,879,152 3,508,010 10 11 264,295,447 2,191,038 12 163,004,004 1,647,829 13 81,390,385 -515,489 897,386 14 72,448,858 15 1,926,663,560 -549,475 9,786,323 16 17 4,491,341 18 757,820,789 877,207 19 1,191,297,507 2,366,426 20 374,345,499 2,437,716 21 281,996,156 219,587 22 161,321,433 2,876,260 23 -29,611,101 -2,516,663 24 2,741,661,624 -2,516,663 8,777,196 25 26 27 28 29 30 31 32 33 34 35 36 9,972,096 152,615 37 78,146,364 -55,274 1,058,058 38 49,246,279 39 634,303,340 8,281,777 40 945,706,710 -899,467 9,050,949 41 129,630,131 -12,299 282,449 42 18,936,973 646,324 43 44 1,865,941,893 -814,425 19,319,557 45 6,534,267,077 -1,363,900 -2,516,663 37,883,076 46

Page 205 FERC FORM NO. 1 (REV. 12-05)(f) Transfers Balance at End of Year Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (g) Adjustments (e) Retirements (d) ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)

47 155,626,881 1,176,527 48 84,163,595 -589,539 303,521 49 905,821,922 986,587 5,572,297 50 106,177,975 612 51 424,256,770 743,705 52 364,222,052 781,546 53 20,656,837 48,588 54 32,684,252 55 56 57 2,093,610,284 1,573,575 7,450,269 58 59 51,509,531 -16,346 173 60 67,922,801 266,027 61 453,754,599 1,248,989 3,648,915 62 63 524,835,846 -292,324 35 4,960,363 64 307,072,324 9,281 2,655,902 65 642,942,198 2,082 413 2,760,159 66 1,494,652,901 36,067 9,583,537 67 767,214,769 -5,729 6,556,096 68 342,895,868 602,781 69 247,278,294 20,004,754 70 41,454,244 -37,841 251,489 71 72 75,023,612 10,562 335,081 73 74 5,016,556,987 954,741 448 51,625,277 75 76 77 78 79 80 81 82 83 84 85 14,645,315 -17,982 86 167,473,387 4,199,807 87 157,479,137 22,558,554 88 42,151,173 5,362,616 3,447,324 89 256,764 90 33,519,778 33,048 506,408 91 950,780 127,003 92 11,062,987 715,727 93 187,728,500 1,333 5,603,392 94 12,513,394 7,235 95 627,781,215 5,379,015 37,165,450 96 97 98 627,781,215 5,379,015 37,165,450 99 14,861,023,177 6,660,540 -2,516,215 146,509,359 100 101 102 103 14,861,023,177 6,660,540 -2,516,215 146,509,359 104

Page 207 FERC FORM NO. 1 (REV. 12-05)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC PLANT LEASED TO OTHERS (Account 104) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Lessee Description of (b) (a) (Designate associated companies with a double asterisk) Property Leased Commission Authorization (c) Expiration Date of Lease

(d) Balance at End of Year (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 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-95) Page213

47 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) Arizona Public Service Company X 04/10/2013 2012/Q4

Line Description and Location Date Originally Included Balance at End of Year (c) (b) (a) Of Property in This Account Date Expected to be used in Utility Service (d) No. 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.

Land and Rights: 1 12/31/1991 Roanoke Substation 282,772 12/31/2022 235th Ave. & Roanoke Ave., Phoenix, AZ 3 11/30/2005 Prescott Service Center Office 2,004,206 12/31/2017 4Prescott, AZ 5 12/31/1993 Madison Substation 592,651 12/31/2022 611th St. & Jackson St., Phoenix, AZ 7 10/31/2006 Paradise Substation 401,193 12/31/2022 815021 N. 33rd Place, Phoenix, AZ 9 5/31/2007 Palo Verde to Kyrene 500KV Line 4,024,859 12/31/2022 10Maricopa, AZ 11 12/31/2008 Sun Valley (TS5) to Trilby Wash (TS1) Transmission e 14,677,520 12/31/2015 12Township 040N 040W Sec 29; Maricopa, AZ 13 12/31/2008 Palm Valley (TS3) to Trilby Wash (TS1) Transmissione 16,510,753 12/31/2015 14Township 040N 020W Sec 20; Surprise, AZ 15 12/31/2008 Palo Verde to Sun Valley (TS5) 500KV Transmission Le 4,299,208 12/31/2016 16Township 030N 070W Sec 28; Maricopa, AZ 17 5/31/2008 Buckeye to Elianto (SV4) Transmission Line 653,352 12/31/2022 18Township 010N 030W Sec 7; Buckeye, AZ 19 20Other Property: 21 12/31/1999 Other General Parcels (2) 281,561 12/31/2022 22 23 12/31/1999 Other Transmission Parcels (2) 92,023 12/31/2022 24 25 12/31/1999 Other Distribution Parcels (4) 556,004 12/31/2022 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-96) Page214 47 Total 53,882,057Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) Arizona Public Service Company X 04/10/2013 2012/Q4

Line Description and Location Date Originally Included Balance at End of Year (c) (b) (a) Of Property in This Account Date Expected to be used in Utility Service (d) No. 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.

Land and Rights: 1 9/30/2008 Delaney Substation 1,074,847 12/31/2016 2Thomas & 451st Ave.; Maricopa, AZ 3 12/31/2008 Payson Substation 746,020 12/31/2015 4Township100N 100E Sec2; Payson, AZ 5 12/31/2008 Sun Valley (TS5) Substation 5,328,441 12/31/2016 6Township 04N 04E Sec29; Buckeye, AZ 7 10/31/2008 Via Dona (NE2) Substation 1,929,113 12/31/2022 8118th Place & Via Dona Rd; Scottsdale, AZ 9 5/1/2009 Citrus (WS4) Substation 427,534 12/31/2022 10Parcel 502-40-267 /T01NR02W.S10/ 2.633 acres 11 12 13 14 15 16 17 18 19 20Other Property: 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-96) Page214.1 47 Total 53,882,057Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description of Project Construction work in progress - (b) (a) Electric (Account 107) 1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts) 3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.

102,615,834 Palo Verde Nuclear Plant Improvements 1 3,974,643 Cholla Plant Improvements 2 8,109,350 Four Corners Plant Improvements 3 2,367,651 Navajo Plant Improvements 4 21,441,616 Gas & Oil Plant Improvements 5 100,696,004 Solar Additions 6 7 7,772,862 Transmission Land and Land Rights 8 21,190,915 Transmission Substations - Add/Improvements 9 46,735,549 500 KV Lines - Add/Improvements 10 14,630,564 115/230 KV Lines - Add/Improvements 11 16,596,622 69 KV Lines - Add/Improvements 12 1,607,040 ANPP 500 KV Transmission System 13 561,001 Navajo Southern Transmission System 14 797,249 PV/YUMA 500 KV Transmission System 15 331,021 Morgan - Pinnacle Peak Transmission System 16 2,360,975 Transmission Lines Relocates 17 Transmission Lines Replace 18 7,260,808 Transmission Reliability 19 20 3,831,844 Distribution Land and Land Rights 21 2,618,558 Distribution Substation - Add/Improvements 22 2,600,252 Overhead lines - Add/Improvements 23 3,921,317 Underground Lines - Add/Improvements 24 3,102,070 Distribution Relocates 25 11,790,078 Distribution Replace 26 7,261,255 Distribution Reliability 27 1,034,440 Other Distribution 28 29 41,745,542 General Computer/Communications 30 19,267,100 Buildings & Equip/Land & Land Rights 31 128,838 Research, Development, Technical Research 32 33 34 35 36 37 38 39 40 41 42

FERC FORM NO. 1 (ED. 12-87) Page216

43 TOTAL 456,350,998Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item Total (c) (b) (a) (d) Section A. Balances and Changes During Year (c+d+e) Electric Plant in Service Electric Plant Held for Future Use Electric Plant Leased to Others (e) 

### 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.

Balance Beginning of Year 1 4,952,911,448 4,952,911,448 Depreciation Provisions for Year, Charged to 2(403) Depreciation Expense 3 328,826,684 328,826,684 (403.1) Depreciation Expense for Asset Retirement Costs 4 6,495,644 6,495,644

(413) Exp. of Elec. Plt. Leas. to Others 5Transportation Expenses-Clearing 6 3,115,456 3,115,456 Other Clearing Accounts 7 460,272 460,272 Other Accounts (Specify, details in footnote): 8 9TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9) 10 338,898,056 338,898,056

Net Charges for Plant Retired: 11 Book Cost of Plant Retired 12 132,659,157 132,659,157 Cost of Removal 13 31,507,464 31,507,464 Salvage (Credit) 14 15,247,278 15,247,278 TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14) 15 148,919,343 148,919,343

Other Debit or Cr. Items (Describe, details in footnote): 16 -6,552,415 -6,552,415

17Book Cost or Asset Retirement Costs Retired 18Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18) 19 5,136,337,746 5,136,337,746

Steam Production 20 Section B. Balances at End of Year According to Functional Classification 1,094,613,696 1,094,613,696 Nuclear Production 21 1,471,531,350 1,471,531,350 Hydraulic Production-Conventional 22Hydraulic Production-Pumped Storage 23Other Production 24 483,075,786 483,075,786 Transmission 25 624,798,831 624,798,831 Distribution 26 1,318,599,421 1,318,599,421 Regional Transmission and Market Operation 27General 28 143,718,662 143,718,662 TOTAL (Enter Total of lines 20 thru 28) 29 5,136,337,746 5,136,337,746

Page 219 FERC FORM NO. 1 (REV. 12-05)

### Schedule Page: 219 Line No.: 16 Column: c 

## Palo Verde Decommissioning (16,251,180) Asset Retirement Obligation in Reg. Liability 4,907,856 Accelerated CIAC to Regulatory Assets (332,041) Childs Irving Decommissioning 441,067 Reserve Transfers-- Accounts 1110,1112, & 1220 & Other Entities4,681,883 (6,552,415) Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description of Investment Date Acquired (c) (b) (a) Amount of Investment at Beginning of Year Date Of Maturity (d) 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.

BIXCO INC. 1 1,000 Capital Stock, Common (10,000 Shares) 2 7,746 Equity 3 8,746 Subtotal BIXCO, Inc 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

FERC FORM NO. 1 (ED. 12-89) Page224

42Total Cost of Account 123.1 $ TOTAL 8,746 0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Equity in Subsidiary

Earnings of Year Revenues for Year Amount of Investment at End of Year Gain or Loss from Investment Disposed of (e) (f) (g) (h) 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

1 1,000 2 7,746 3 8,746 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

FERC FORM NO. 1 (ED. 12-89) Page 225 42 8,746Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
MATERIALS AND SUPPLIES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account Balance Balance
(c) (b) (a) Department or Departments which (d) Beginning of Year End of Year Use Material 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.

21,999,982 31,334,390

1 Fuel Stock (Account 151) 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 105,770,964 113,530,876 7 Production Plant (Estimated) 28,883,524 30,666,214 8 Transmission Plant (Estimated) 69,509,544 73,480,157 9 Distribution Plant (Estimated) 10 Regional Transmission and Market Operation Plant (Estimated) 222,716 418,420 11 Assigned to - Other (provide details in footnote) 204,386,748 218,095,667 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 19 226,386,730 249,430,057 20 TOTAL Materials and Supplies (Per Balance Sheet)

Page227 FERC FORM NO. 1 (REV. 12-05)

### 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. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Allowances (Accounts 158.1 and 158.2) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. SO2 Allowances Inventory Current Year (b) (a) (Account 158.1) No. Amt. (c) No. (d) Amt. (e) 

### 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. 2013

100,299.00 36,876.00 Balance-Beginning of Year 1 2 Acquired During Year: 3 Issued (Less Withheld Allow) 4 Returned by EPA 5 6 7 Purchases/Transfers: 8 9 10 11 12 13 14 Total 15 16 Relinquished During Year: 17 8,807.00 Charges to Account 509 18 Other: 19 20 Cost of Sales/Transfers: 21 22 23 24 25 26 27 Total 28 91,492.00 36,876.00 Balance-End of Year 29 30 Sales: 31 Net Sales Proceeds(Assoc. Co.) 32 Net Sales Proceeds (Other) 33 Gains 34 Losses 35 Allowances Withheld (Acct 158.2) 533.00 533.00 Balance-Beginning of Year 36 Add: Withheld by EPA 37 533.00 Deduct: Returned by EPA 38 Cost of Sales 39 533.00 Balance-End of Year 40 41 Sales: 42 Net Sales Proceeds (Assoc. Co.) 43 533.00 259 Net Sales Proceeds (Other) 44 259 Gains 45 Losses 46

FERC FORM NO. 1 (ED. 12-95) Page228aName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Allowances (Accounts 158.1 and 158.2) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (f) (j) No. Amt. (g) No. (h) Amt. (i) No. Amt. No. Amt. (k) (l) (m) Future Years Totals (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.

2014 2015

1 958,776.00 36,876.00 36,876.00 1,169,703.00 2 3 4 36,876.00 36,876.00 5 6 7 8 9 10 11 12 13 14 15 16 17 18 8,807.00 19 20 21 22 23 24 25 26 27 28 29 995,652.00 36,876.00 36,876.00 1,197,772.00 30 31 32 33 34 35

36 26,091.00 533.00 533.00 28,223.00 37 1,066.00 1,066.00 38 533.00 1,066.00 39 40 26,624.00 533.00 533.00 28,223.00 41 42 43 51 310 44 533.00 1,066.00 51 310 45 46

FERC FORM NO. 1 (ED. 12-95) Page229aName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Allowances (Accounts 158.1 and 158.2) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. NOx Allowances Inventory Current Year (b) (a) (Account 158.1) No. Amt. (c) No. (d) Amt. (e) 

### 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. 2013

Balance-Beginning of Year 1 2 Acquired During Year: 3 Issued (Less Withheld Allow) 4 Returned by EPA 5 6 7 Purchases/Transfers: 8 9 10 11 12 13 14 Total 15 16 Relinquished During Year: 17 Charges to Account 509 18 Other: 19 20 Cost of Sales/Transfers: 21 22 23 24 25 26 27 Total 28 Balance-End of Year 29 30 Sales: 31 Net Sales Proceeds(Assoc. Co.) 32 Net Sales Proceeds (Other) 33 Gains 34 Losses 35 Allowances Withheld (Acct 158.2) Balance-Beginning of Year 36 Add: Withheld by EPA 37 Deduct: Returned by EPA 38 Cost of Sales 39 Balance-End of Year 40 41 Sales: 42 Net Sales Proceeds (Assoc. Co.) 43 Net Sales Proceeds (Other) 44 Gains 45 Losses 46

FERC FORM NO. 1 (ED. 12-95) Page228bName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Allowances (Accounts 158.1 and 158.2) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (f) (j) No. Amt. (g) No. (h) Amt. (i) No. Amt. No. Amt. (k) (l) (m) Future Years Totals (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.

2014 2015

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) Page229bName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of EXTRAORDINARY PROPERTY LOSSES (Account 182.1) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (c) (b) (a) (d) 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).] Total Amount of Loss Losses Recognised During Year WRITTEN OFF DURING YEAR Account Charged Amount Balance at End of Year (f) (e) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

FERC FORM NO. 1 (ED. 12-88) Page 230a 20 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No.

(c) (b) (a) (d) Description of Unrecovered Plant Total Amount of Charges Costs Recognised During Year WRITTEN OFF DURING YEAR Account Charged Amount Balance at End of Year
(f) (e) 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)]

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

FERC FORM NO. 1 (ED. 12-88) Page 230b

49 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Transmission Service and Generation Interconnection Study Costs Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description Costs Incurred During (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) 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.

the Period

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 ( 1,783) SIS (W481834) 143 143 22 ( 202) Facilities Study (W484970) 143 143 23 ( 222) Facilities Study (W485732) 143 82,167 143 24 ( 4,595) SIS (W491430) 143 143 25 SMG SIS (W494782) 143 ( 3,426) 143 26 ( 380) SIS (W496400) 143 143 27 38,371 SMG SIS (W498627) 143 143 28 SIS (W498627) 143 143 29 SMG SIS (W498775) 143 ( 871) 143 30 SIS (W498775) 143 143 31 ( 646) Feasibility Study (W499627) 143 143 32 43 SIS (W501595) 143 143 33 38,909 SMG SIS (W501608) 143 143 34 SIS (W501608) 143 143 35 SMG SIS (W501609) 143 ( 2,435) 143 36 SIS (W501609) 143 143 37 SMG SIS (W501630) 143 ( 1,186) 143 38 SIS (W501630) 143 143 39 SIS (W502191) 143 143 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Transmission Service and Generation Interconnection Study Costs Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description Costs Incurred During (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 SMG SIS (W502192) 143 ( 1,496) 143 22 SIS (W502192) 143 143 23 SMG SIS (W502193) 143 6,268 143 24 SIS (W502193) 143 143 25 SMG SIS (W502227) 143 5,913 143 26 SIS (W502227) 143 143 27 SMG SIS (W502231) 143 387 143 28 SIS (W502231) 143 143 29 SMG SIS (W502232) 143 376 143 30 SIS (W502232) 143 143 31 ( 385) SIS (W502466) 143 143 32 SMG SIS (W502474) 143 2,888 143 33 SIS (W502474) 143 143 34 SMG SIS (W502842) 143 2,463 143 35 SIS (W502842) 143 143 36 ( 3) Facilities Study (WA103398) 143 ( 941) 143 37 226 Facilities Study (WA103399) 143 143 38 ( 57) SIS (WA105240) 143 143 39 2,799 SMG SISSTD 143 143 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Transmission Service and Generation Interconnection Study Costs Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description Costs Incurred During (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 34 SMG FACSTD (WA108732) 143 35,352 143 22 242 SMG FACSTD (WA122533) 143 143 23 34 SMG FACSTD (WA125613) 143 143 24 164 SMG SISSTD (WA127662) 143 143 25 1,971 SIS (WA127701) 143 138,333 143 26 88 SIS (WA12773) 143 143 27 3,094 SMG SISSTD (WA129301) 143 143 28 199 SMG SISSTD (WA129495) 143 143 29 1,163 Facilities Study (WA130324) 143 ( 781) 143 30 18,652 Facilities Study (WA131362) 143 143 31 28 SMG SIS (WA133988) 143 143 32 586 SMG FACSTD (WA135348) 143 143 33 480 SMG FACSTD (WA136886) 143 143 34 2,045 SIS (WA141334) 143 143 35 ( 2,300) SIS (WA141336) 143 143 36 SIS (WA14320) 143 2,248 143 37 161 Facilities Study (WA144239) 143 ( 25,000) 143 38 SMG SISSTD (WA149964) 143 ( 20,000) 143 39 ( 651) Facilities Study (WA1894) 143 143 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Transmission Service and Generation Interconnection Study Costs Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description Costs Incurred During (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 87 SIS (WA1896) 143 143 22 SIS (WA19661) 143 7,557 143 23 SIS (WA20194) 143 3,708 143 24 103 SMG FESSTD (WA20696) 143 143 25 ( 343) Feasibility Study (WA21556) 143 143 26 ( 248) Feasibility Study (WA21557) 143 143 27 ( 441) Facilities Study (WA32271) 143 143 28 ( 624) Facilities Study (WA32691) 143 143 29 ( 630) Facilities Study (WA32696) 143 143 30 ( 668) Facilities Study (WA32698) 143 143 31 278 Facilities Study (WA34675) 143 143 32 ( 569) Facilities Study (WA34677) 143 143 33 ( 1,436) Facilities Study (WA37362) 143 143 34 SIS (WA61589) 143 143 35 ( 259) Feasibility Study (WA61729) 143 143 36 ( 801) SIS (WA61729) 143 143 37 175 SIS (WA63058) 143 ( 87,758) 143 38 ( 505) SMG SISSTD (WA64474) 143 143 39 ( 398) Feasibility Study (WA67121) 143 143 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.3Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Transmission Service and Generation Interconnection Study Costs Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description Costs Incurred During (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 ( 813) SIS (WA67121) 143 143 22 360 Facilities Study (WA69759) 143 143 23 745 Facilities Study (WA69760) 143 143 24 SMG FESSTD (WA71338) 143 229 143 25 ( 129) Facilities Study (WA73845) 143 143 26 SMG SIS (WA74455) 143 ( 7,220) 143 27 465 SMG FACSTD (WA78073) 143 143 28 ( 21) Feasibility Study (WA78455) 143 3,949 143 29 148 SMG FACSTD (WA78524) 143 143 30 142 SMG SISSTD (WA81603) 143 143 31 ( 820) Facilities Study (WA82014) 143 143 32 Facilities Study (WA83613) 143 69,514 143 33 3,540 SIS (WA84273) 143 143 34 199 SIS (WA85636) 143 143 35 146 SMG SISSTD (WA86512) 143 143 36 240 SMG SIS (WA92157) 143 143 37 39 SMG SIS (WA92158) 143 143 38 66 SMG SIS (WA92165) 143 143 39 ( 398) SIS (WA92332) 143 143 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.4Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Transmission Service and Generation Interconnection Study Costs Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description Costs Incurred During (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 876 SIS (WA94821) 143 143 22 311 SIS (WA95638) 143 143 23 Facilities Study (WA98450) 143 6,534 143 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.5Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of OTHER REGULATORY ASSETS (Account 182.3) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description and Purpose of Debits CREDITS Written off During the Quarter/Year Account Charged (d) (c) (a) Balance at end of Current Quarter/Year

(e) Other Regulatory Assets Written off During the Period Amount (f) 

### 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.

Balance at Beginning of

Current Quarter/Year (b) 32,527,167 33,782,583 1,255,416 Deferred Compensation 1 2 12,700,564 12,368,524 332,040 108 Capital Contribution on Phoenix-Mead Transmission 3 U-1345-90-269 Amortize through 2050 4 5 84,407,966 95,917,858 3,161,586 283, 410.1 14,671,478 Income Taxes - AFUDC Equity 6 E-01345A-03-0437 Amortize through 2041 7 8 3,051,163 2,288,373 762,790 525 Palo Verde Rent Levelization 9 E-01345A-03-0437 Amortize through 2015 10 11 225,466 170,421 55,045 407 Decontamination 12 E-01345A-03-0437 Amortize through 2017 13 14 4,561 4,561 254 Deferred Loss on Sales of Property 15 16 13,590,960 10,646,032 2,944,928 190 Prior Flow Through of Tax Benefits 17 Amortize through 2019 18 19 27,549,088 72,692,309 71,572,891 Various 116,716,112 Deferred Fuel and Purchased Power 20 E-01345A-03-0437,E-01345A-05-0816,-0826,-0827 21 Amortize through 2013 22 23 77,349,681 39,978,423 37,371,258 547, 555 Deferred Fuel and Purchased Power Mark-to-Market 24 E-01345A-03-0437,E-01345A-05-0816,-0826,-0827 25 Amortize through 2016 26 27 344,655 344,655 Deferred Fuel and Purchased Power - Accr. Interest 28 E-01345A-08-0172 29 Amortize through 2013 30 31 30,456,014 26,043,002 4,413,012 501 Four Corners Coal Reclamation 32 E-01345A-05-0816,-0826,-0827 Amortize through 2016 33 34 6,094,221 5,676,331 417,890 501 Navajo Coal Reclamation 35 E-01345A-08-0172 Amortize through 2026 36 37 40,888,477 31,802,149 9,086,328 571 Transmission Vegetation Management 38 ER11-3468-000 Amortize through 2016 39 40 1,022,619,763 780,490,513 242,129,250 228.3, 926 Pension and Other Postretirement Benefits 41 E-01345A-08-0172 42 43

FERC FORM NO. 1/3-Q (REV. 02-04) Page 232

44 TOTAL 1,409,619,466 386,738,872 1,200,038,505 177,157,911Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of OTHER REGULATORY ASSETS (Account 182.3) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description and Purpose of Debits CREDITS Written off During the Quarter/Year Account Charged (d) (c) (a) Balance at end of Current Quarter/Year

(e) Other Regulatory Assets Written off During the Period Amount (f) 

### 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.

Balance at Beginning of

Current Quarter/Year (b) 11,921,933 21,187,507 4,237,500 926 13,503,074 Pension and Other Postretirement Benefits Deferral 1 E-01345A-08-0172 2 Amortize through 2015 3 4 7,987,072 7,987,072 254 Demand Side Management 5 E-01345A-03-0437,E-01345A-05-0816,-0826,-0827 6 Amortize through 2013 7 8 2,854,815 3,163,574 308,759 Income Taxes - Change in Rates 9 Amortize through 2041 10 11 19,973,631 18,438,637 1,534,994 283, 410.1 Income Taxes - Medicare Subsidy 12 Amortize through 2024 13 14 15,416,924 26,642,148 727,727 283, 410.1 11,952,951 Income Taxes - Investment Tax Credit Basis Adjust 15 Amortize through 2044 16 17 1,088,306 1,088,306 Property Tax Deferral 18 E-01345A-08-0172 19 20 7,346,000 7,346,000 Lost Fixed Cost Recovery 21 E-01345A-08-0172 22 Amortize through 2014 23 24 9,971,160 9,971,160 FERC Transmission True up 25 Amortize through 2014 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43

FERC FORM NO. 1/3-Q (REV. 02-04) Page 232.1

44 TOTAL 1,409,619,466 386,738,872 1,200,038,505 177,157,911

### Schedule Page: 232 Line No.: 20 Column: d 

## 411.8, 426.5, 555 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MISCELLANEOUS DEFFERED DEBITS (Account 186) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description of Miscellaneous Debits CREDITS Account (c) (b) (a) Balance at End of Year (d) Deferred Debits Amount (e) Balance at Beginning of Year (f) Charged 

### 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.

2,774,979 1,849,987 924,992 131 Rouse Promissory Note 1 2 75,428,499 80,045,780 4,617,281 Rouse Deferred Lease Payments 3 4 200,000 200,000 Redhawk Effluent Water 5 6 5,169,642 5,916,691 6,795,165 7,542,214 165 Information Sys Leases & Maint. 7 8 6,580,760 3,377,880 3,202,880 431,525 Unamortized Arrangement Fees 9 10 627,250 627,250232 Prepaid Training 11 12 1,012,352 889,551 122,801 165 Long-Term Prepaid Insurance 13 14 132,378,571 132,378,571 Income Tax Receivable 15 16 363,281 463,936 100,655 Preliminary Legal Expenses 17 18 16,097,319 4,406,560 11,690,759 565 Transmission Debits 19 20 820,250 820,250 920 License Fees 21 22 3,855,372 3,855,372 Banked Energy 23 24 294,601 294,601 Prepaid Payroll Agreements 25 26 3,983,647 5,946,517 1,962,870 Prepaid Water Supply Agreement 27 28 206,626 276,872 40,979 111,225Various Minor Items 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-94) Page 233 49 TOTAL 47 Misc. Work in Progress
48 Deferred Regulatory Comm. Expenses (See pages 350 - 351) 245,310,527 240,529,568Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES (Account 190) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description and Location Balance of Begining (c) (b) (a) Balance at End of Year of Year 

### 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.

Electric 1 81,515,171 145,086,840 Risk Management Activities 2 392,486,094 494,744,000 Pension and Other Post Retirement Liabilities 3 101,334,237 89,955,947 Regulated Liabilities - Asset Retirement Obligation 4 88,850,433 85,464,667 Regulated Liabilities - Other 5 52,440,837 106,668,296 Credit and Loss Carryforwards 6 178,267,795 157,077,508 Other 7 894,894,567 1,078,997,258 TOTAL Electric (Enter Total of lines 2 thru 7) 8 Gas 9 10 11 12 13 14 Other 15 TOTAL Gas (Enter Total of lines 10 thru 15 16 Other (Specify) 17 894,894,567 1,078,997,258 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18 Notes

FERC FORM NO. 1 (ED. 12-88) Page234Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CAPITAL STOCKS (Account 201 and 204) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Class and Series of Stock and Number of shares

(c) (b) (a) Call Price at End of Year Par or Stated Value per share (d) Name of Stock Series Authorized by Charter 

### 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.

2.50 100,000,000 Common Stock 1 2 100,000,000 Total Common Stock 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. 12-91) Page 250AS REACQUIRED STOCK (Account 217) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CAPITAL STOCKS (Account 201 and 204) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT IN SINKING AND OTHER FUNDS Shares

(g) Cost (h) Shares Shares Amount (Total amount outstanding without reduction for amounts held by respondent) Amount

(e) (f) (i) (j) 

### 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.

178,162,367 71,264,947 1 2 178,162,367 71,264,947 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 251Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line Item Amount (b) (a) OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)

No. 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.

1,505,626 Gain on Resale or Cancellation of Capital Stock - Account 210 1 Balance at Beginning of Year: $1,505,626 2 Credits 3 Debits 4 Balance at End of Year: $1,505,626 5 6 Misc Paid in Capital - Account 211 7 12,323,739 Transfer of Contract from Pinnacle West Marketing & Trading LLC 8 Balance at Beginning of Year: $12,323,739 9 Credit 10 Debit 11 Balance at End of Year: $12,323,739 12 13 4,571,000 El Dorado transfer of Aegis software to APS 14 Balance at Beginning of Year: $4,571,000 15 Credit 16 Debit 17 Balance at End of Year: $4,571,000 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39

FERC FORM NO. 1 (ED. 12-87) Page 253 40 TOTAL 18,400,365

### 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. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CAPITAL STOCK EXPENSE (Account 214) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Class and Series of Stock Balance at End of Year (b) (a) 

### 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.

37,461,284 Common Stock Expense 1 50,368 Shelf Registration 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

FERC FORM NO. 1 (ED. 12-87) Page 254b

22 TOTAL 37,511,652Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of LONG-TERM DEBT (Account 221, 222, 223 and 224) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Class and Series of Obligation, Coupon Rate (c) (b) (a) Total expense, Premium or Discount Principal Amount Of Debt issued (For new issue, give commission Authorization numbers and dates) 

### 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.

Pollution Control Bonds Account 221 1 1,062,971 49,400,000 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series A 2 1,314,677 65,750,000 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series B 3 776,159 31,500,000 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series C 4 1,055,827 32,650,000 Coconino County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 1994 Series A 5 538,817 16,870,000 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. Series 1998 6 416,334 12,850,000 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 7 653,379 26,710,000 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series B 8 585,000 90,000,000 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2002 Series A 9 763,172 38,150,000 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 10 351,144 32,000,000 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series B 11 351,144 32,000,000 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series C 12 351,144 32,000,000 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series D 13 351,144 32,000,000 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series E 14 357,088 35,975,000 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series A 15 526,071 32,000,000 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series B 16 317,633 32,000,000 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series C 17 317,633 32,000,000 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series D 18 317,631 32,000,000 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series E 19 10,406,968 655,855,000 Subtotal 20 21 Other Long Term Debt Account 224 22 2,547,180 375,000,000 6.500% Unsecured Senior Note 23 2,632,500 24 D 2,049,339 200,000,000 5.625% Unsecured Senior Note 25 2,288,000 26 D 2,529,839 300,000,000 4.650% Unsecured Senior Note 27 2,208,000 28 D 2,097,256 300,000,000 5.800% Unsecured Senior Note 29 810,000 30 D 2,362,692 250,000,000 5.500% Unsecured Senior Note 31 2,147,500 32 D

FERC FORM NO. 1 (ED. 12-96) Page 256

33 TOTAL 3,630,585,405 52,745,082Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of LONG-TERM DEBT (Account 221, 222, 223 and 224) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Class and Series of Obligation, Coupon Rate (c) (b) (a) Total expense, Premium or Discount Principal Amount Of Debt issued (For new issue, give commission Authorization numbers and dates) 

### 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.

1,659,703 250,000,000 6.250% Unsecured Senior Note 1 1,355,000 2 D 1,333,769 150,000,000 6.875% Unsecured Senior Note 3 226,500 4 D 4,301,413 500,000,000 8.750% Unsecured Senior Note 5 275,000 6 D 3,096,550 300,000,000 5.05% Unsecured Senior Note 7 2,022,000 8 D 3,321,373 325,000,000 4.50% Unsecured Senior Note 9 3,074,500 10 D 24,730,405 COLI LOANS (Option II Benefits) 11 12 42,338,114 2,974,730,405 Subtotal 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32

FERC FORM NO. 1 (ED. 12-96) Page 256.1

33 TOTAL 3,630,585,405 52,745,082Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Nominal Date

of Issue Date of Maturity AMORTIZATION PERIOD Date From Date To Outstanding (Total amount outstanding without

reduction for amounts held by respondent) Interest for Year Amount (d) (e) (f) (g) (h) (i) 

### 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.

1 49,400,000 2,321,800 5/01/24 5/25/94 5/01/24 5/25/94 2 65,750,000 3,090,250 9/01/24 9/14/94 9/01/24 9/14/94 3 31,500,000 905,625 9/01/24 9/14/94 9/01/24 9/14/94 4 32,650,000 1,183,563 10/01/29 10/12/94 10/01/29 10/12/94 5 16,870,000 225,369 11/01/33 11/16/98 11/01/33 11/16/98 6 12,850,000 706,750 6/01/34 5/28/09 6/01/34 5/28/09 7 26,710,000 401,263 4/01/38 9/22/09 4/01/38 9/22/09 8 3,934,238 5/01/29 11/01/02 5/01/29 11/01/02 9 38,150,000 1,924,400 6/01/34 5/28/09 6/01/34 5/28/09 10 32,000,000 1,760,000 6/01/34 5/28/09 6/01/34 5/28/09 11 32,000,000 1,760,000 6/01/34 5/28/09 6/01/34 5/28/09 12 32,000,000 1,840,000 6/01/34 5/28/09 6/01/34 5/28/09 13 32,000,000 1,840,000 6/01/34 5/28/09 6/01/34 5/28/09 14 35,975,000 2,158,500 5/01/29 6/26/09 5/01/29 6/26/09 15 32,000,000 774,871 5/01/29 6/26/09 5/01/29 6/26/09 16 32,000,000 1,840,000 5/01/29 6/26/09 5/01/29 6/26/09 17 32,000,000 1,920,000 5/01/29 6/26/09 5/01/29 6/26/09 18 32,000,000 1,920,000 5/01/29 6/26/09 5/01/29 6/26/09 19 565,855,000 30,506,629 20 21 22 4,062,500 3/01/12 3/01/02 3/01/12 3/01/02 23 24 200,000,000 11,250,000 5/15/33 5/07/03 5/15/33 5/07/03 25 26 300,000,000 13,950,000 5/15/15 5/07/03 5/15/15 5/07/03 27 28 300,000,000 17,400,000 6/30/2014 6/29/04 6/30/14 6/29/04 29 30 250,000,000 13,750,000 9/1/2035 8/22/05 9/01/35 08/22/05 31 32

FERC FORM NO. 1 (ED. 12-96) Page 257 33 3,165,585,406 189,852,046Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Nominal Date

of Issue Date of Maturity AMORTIZATION PERIOD Date From Date To Outstanding (Total amount outstanding without

reduction for amounts held by respondent) Interest for Year Amount (d) (e) (f) (g) (h) (i) 

### 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.

250,000,000 15,625,000 8/01/16 8/03/06 8/01/16 8/03/06 1 2 150,000,000 10,312,500 8/01/36 8/03/06 8/01/36 8/03/06 3 4 500,000,000 43,750,000 3/01/19 2/26/09 3/01/19 2/26/09 5 6 300,000,000 15,150,000 09/1/2041 8/25/11 09/1/2041 8/25/11 7 8 325,000,000 14,095,417 4/01/42 1/13/12 4/01/42 1/13/12 9 10 24,730,406 11 12 2,599,730,406 159,345,417 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32

FERC FORM NO. 1 (ED. 12-96) Page 257.1 33 3,165,585,406 189,852,046

### Schedule Page: 256 Line No.: 1 Column: a 

## Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On February 6, 2013, the ACC issued a financing order in which it, subject to specified parameters and procedures, (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017. Schedule Page: 256.1 Line No.: 11 Column: h 

## The change in the loan balance for the Coli Loan is as follows: Total outstanding balance @ 12/31/11 $ 23,177,038 2012 death repayments - 2012 net premiums 636,581 2012 net interest 916,787 Balance outstanding @ 12/31/12 $ 24,730,406 Schedule Page: 256.1 Line No.: 13 Column: i 

## The difference between the total column (i) and the total of Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies is as follows:

Total interest in 427 and 430 $ 191,200,337 Less: Navajo ROW – Past Obligation (1,077,376) Letter of Credit Fees (243,670) Other (27,246) Total long term interest $ 189,852,045 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES Arizona Public Service Company X 04/10/2013 2012/Q4

Particulars (Details) (b) (a) Amount Line No. 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.

395,497,641 Net Income for the Year (Page 117) 1 2 3Taxable Income Not Reported on Books 4 35,627,220 Contributions in Aid of Construction 5 -39,460,943 Tax Gain/Loss on Sale of Business Property 6 8,095,396 Other Taxable Income Not Reported on Books 7 8Deductions Recorded on Books Not Deducted for Return 9 487,478,924 Book Depreciation and Amortization 10 244,395,541 Income Tax Per Books 11 87,459,181 Pension and Other Post-Retirement Benefits 12 215,331,968 Other Deductions Recorded on Books Not Deducted for Return (see footn) 13Income Recorded on Books Not Included in Return 14 725,079 Book Gain/Loss on Sale of Business Property 15 -748,556 Mark-to-Market Adjustments 16 -1,187,854 Cash Surrender Value 17 -3,967,107 Other Income Recorded on Books Not Included in Return 18Deductions on Return Not Charged Against Book Income 19 -617,062,024 Tax Depreciation and Amortization 20 -227,843,649 Expenditures Capitalized for Book Not Tax 21 -354,459,367 Other Deductions on Return Not Charged Against Book Income (see footn) 22 23 24 25 26 229,881,451 Federal Tax Net Income 27Show Computation of Tax: 28 80,458,508 ($229,881,451) * 35% 29 30 -87,263,378 Tax Carryforward Attributes Utilized 31 32 -6,804,470 Net Federal Tax Expense 33 34 35 36 37 38 39 40 41 42 43 44

FERC FORM NO. 1 (ED. 12-96) Page 261

### 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 $ 99,700,461 Renewable Energy Incentives 37,063,779 Regulatory Accounting Adjustments 32,647,112 Other 45,920,617

Total $ 215,331,969
Schedule Page: 261 Line No.: 22 Column: b 

## Other Deductions on Return Not Charged Against Book Income consists of the following:

Pension and Other Post Retirement Benefits $ (110,124,463) Book Accrued Expenses - Beginning of Year (95,068,602) Regulatory Accounting Adjustments (51,067,684) Tax Loss Carryforwards Utilized (41,454,525) Contributions to Qualified Decomissioning Fund (17,248,943) State Taxes (13,956,289) Other (25,538,861)

Total $ (354,459,367) Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Kind of Tax (See instruction 5) BALANCE AT BEGINNING OF YEAR Taxes Accrued (Account 236) Prepaid Taxes (Include in Account 165) Taxes Charged

During Year Taxes Paid During Adjustments Year (a) (b) (c) (d) (e) (f) 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.

-6,845,720 -24,968,542 -6,804,870 -2,869,083 32,547,937 Federal Income 1 48,734,363 48,734,363 FICA 2 301,640 301,640 Unemployment 3 105,869 23,735 29,011 Heavy Vehicle Use 4 17,794 34,423 -27,388 Fuel Tax 5 42,313,946 -24,968,542 42,289,291 -2,869,083 32,549,560 Subtotal 6 7New Mexico: State and Local 8 8,734,624 8,499,160 4,727,251 Real and Personal Property 9 50 -3,863,225 612,025 3,251,250 Income 10 45,039 45,039 Unemployment 11 278,432 252,401 27,495 Sales 12 14,240 13,946 Use 13 9,072,385 -3,863,225 9,422,571 8,005,996 Subtotal 14 15Arizona: State and Local 16 148,236,321 155,686,496 70,617,703 Real and Personal Property 17 8,034,791 24,030,843 11,698,785 -27,694,837 Income 18Diesel Fuel 19 279,267,496 279,309,025 17,957,987 State and City Sales 20 26,611,147 26,369,228 1,355,713 State and City Use 21 137,492 -2,117,000 793,410 7,356,602 State and City Tax Reserve 22 638,726 638,726 Unemployment 23 462,925,973 21,913,843 474,495,670 69,593,168 Subtotal 24 25 96,492 128,563 32,210 NV Real and Personal 26Unemployment 27 96,492 128,563 32,210 Subtotal 28 29California: State and Local 30 28,310 27,907 14,356 Real and Personal Property 31 7,310 599,034 -3,417 -588,307 Income 32 -188 -188 Unemployement 33 35,432 599,034 24,302 -573,951 Subtotal 34 35 -135,930 Utah: State 36 -1 194 135,735 Income 37 -1 -135,930 194 135,735 Subtotal 38 39 40

-2,869,083

FERC FORM NO. 1 (ED. 12-96) Page 262 TOTAL 41 526,360,650 514,444,285 -9,256,873 121,338,952Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Kind of Tax (See instruction 5) BALANCE AT BEGINNING OF YEAR Taxes Accrued (Account 236) Prepaid Taxes (Include in Account 165) Taxes Charged

During Year Taxes Paid During Adjustments Year (a) (b) (c) (d) (e) (f) 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.

Texas: State 1 58 -72 59 71 Income 2Unemployment 3 58 -72 59 71 Subtotal 4 5Sales Tax - Palo Verde Lease 6Payroll - other 7 -2,801,981 11,596,163 Sales Tax - Unbilled Revenue 8 -2,801,981 11,596,163 Subtotal 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

-2,869,083

FERC FORM NO. 1 (ED. 12-96) Page 262.1 TOTAL 41 526,360,650 514,444,285 -9,256,873 121,338,952Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (Taxes accrued BALANCE AT END OF YEAR Prepaid Taxes Electric (Account 408.1, 409.1) Extraordinary Items (Account 409.3) Adjustments to Ret. Other Earnings (Account 439) (g) (h) (i) (j) (k) (l) Account 236) (Incl. in Account 165) DISTRIBUTION OF TAXES CHARGED 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.

-7,084,804 279,934 -4,926,917 9,678,080 1 23,057,824 25,676,539 2 301,640 3 23,735 -53,123 4 34,423 -10,759 5 16,332,818 25,956,473 -4,926,917 9,614,198 6 7 8 8,499,160 4,491,788 9 -24,937 636,962 4,254 10 45,039 11 252,401 1,464 12 13,946 -294 13 286,449 9,136,122 4,254 4,492,958 14 15 16 3,903,727 151,782,769 78,067,878 17 -678,069 12,376,854 4,333,637 18 19 279,309,025 17,999,516 20 26,369,228 1,113,794 21 702,765 -2,026,355 5,895,520 22 638,726 23 310,245,402 162,133,268 4,333,637 103,076,708 24 25 128,563 64,281 26 27 128,563 64,281 28 29 30 27,907 13,953 31 -656 -2,761 32 -188 33 -844 25,146 13,953 34 35 36 -5 199 37 -5 199 38 39 40

FERC FORM NO. 1 (ED. 12-96) Page 263 41 -589,026 197,379,830 326,863,820 126,056,280Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (Taxes accrued BALANCE AT END OF YEAR Prepaid Taxes Electric (Account 408.1, 409.1) Extraordinary Items (Account 409.3) Adjustments to Ret. Other Earnings (Account 439) (g) (h) (i) (j) (k) (l) Account 236) (Incl. in Account 165) DISTRIBUTION OF TAXES CHARGED 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.

1 59 2 3 59 4 5 6 7 8,794,182 8 8,794,182 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

FERC FORM NO. 1 (ED. 12-96) Page 263.1 41 -589,026 197,379,830 326,863,820 126,056,280Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account Balance at Beginning (c) (b) (a) of Year Subdivisions Adjustments Deferred for Year Allocations to Current Year's Income Account No. Amount Account No. Amount (d) (e) (f) (g) 

### 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.

Electric Utility 13% 24% 37% 410% 255 510,843 420 81,816 530% 255 57,729,498 44,396,673 420 2,736,106 6 7TOTAL 58,240,341 44,396,673 2,817,922 8Other (List separately and show 3%, 4%, 7%, 10% and TOTAL) 9

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 266Balance at End (i) (h) of Year Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. ADJUSTMENT EXPLANATION Average Period

of Allocation

to Income

1 2 3 4 429,027 5.2 years 5 99,390,065 28 years 6 7 99,819,092 8 9

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) Page267Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of OTHER DEFFERED CREDITS (Account 253) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description and Other DEBITS Credits Account (c) (b) (a) Balance at End of Year (d) Deferred Credits Amount (e) Balance at Beginning of Year Contra (f) 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.

9,946,238 Deferred Compensation 11,945,788 2,539,627 540,077 182.3 1 2 Palo Verde Unit II Rent 3 18,990,313 Levelization (1/2000 to 12/2015) 14,242,734 4,747,579 242,411.6 4 5 104,575,596 Coal Reclamation 104,266,121 309,475 232 6 7 13,320,586 Navajo Retiree Health Care Costs 14,593,687 1,273,101 8 9 4,122,653 Legal Reserves 10,639,898 6,517,245 10 11 4,596,902 Construction Advances 2,575,441 2,021,461 143 12 13 1,871,176 AMI Meters 477,613 477,613 1,871,176 586, 107 14 15 1,631,411 License Fees 617,338 1,014,073 930.2 16 17 289,004 Leasehold Improvements 248,273 40,731 131 18 19 45,633 Escheated Funds 44,064 5,344 6,913 131 20 21 3,914,360 Banked Energy 3,914,360 555 22 23 25,815,001 SCE Right of Way 26,536,962 721,961 24 25 Tolling Agreements 36,607,110 36,607,110 26 27 413,721 Minor Item 140,151 273,570 143 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-94) Page 269 47 TOTAL 48,142,001 14,739,415 222,935,180 189,532,594Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account

(a) (b) (c) (d) Balance at Beginning of Year CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 

### 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.

1Accelerated Amortization (Account 281) 2Electric 3Defense Facilities 4Pollution Control Facilities 5Other (provide details in footnote): 6 7 8TOTAL Electric (Enter Total of lines 3 thru 7) 9Gas 10Defense Facilities 11 Pollution Control Facilities 12Other (provide details in footnote): 13 14 15TOTAL Gas (Enter Total of lines 10 thru 14) 16 17TOTAL (Acct 281) (Total of 8, 15 and 16) 18Classification of TOTAL 19Federal Income Tax 20State Income Tax 21 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page272 NOTESName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. CHANGES DURING YEAR ADJUSTMENTS Balance at End of Year Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (i) 

### 3. Use footnotes as required.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

FERC FORM NO. 1 (ED. 12-96) Page 273 NOTES (Continued)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account

(a) (b) (c) (d) Balance at Beginning of Year CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 

### 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.

Account 282 1 Electric 2,300,125,503 398,712,558 252,007,093 2Gas 3 4TOTAL (Enter Total of lines 2 thru 4) 2,300,125,503 398,712,558 252,007,093 5 6 7UTP recorded in ADIT for FERC 128,171,723 -4,609,243 8TOTAL Account 282 (Enter Total of lines 5 thru 2,428,297,226 394,103,315 252,007,093 9Classification of TOTAL 10Federal Income Tax 2,002,131,063 324,859,363 208,215,106 11State Income Tax 426,166,163 69,243,952 43,791,987 12Local Income Tax 13

FERC FORM NO. 1 (ED. 12-96) Page 274 NOTESName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. CHANGES DURING YEAR ADJUSTMENTS Balance at End of Year Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (i) 

### 3. Use footnotes as required.

1 2,446,830,968 2 3 4 2,446,830,968 5 6 7 123,562,480 8 2,570,393,448 9 10 2,118,775,320 11 451,618,128 12 13

FERC FORM NO. 1 (ED. 12-96) Page 275 NOTES (Continued)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account (a) (b) (c) (d) Balance at Beginning of Year CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 

### 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.

Account 283 1 Electric 2 9,138,805 13,690,548 33,347,061 Reg. Assets - AFUDC 3 27,686,525 12,923,975 30,558,550 Reg Assets - Mark to Market 4 97,816,321 5,856,706 408,716,460 Reg Assets - Pension and Other 5 32,146,191 27,351,469 74,214,822 Reg Assets - Other 6 51,710,295 3,198,457 57,492,627 Mark to Market 7 43,273,970 62,162,669 15,647,069 Other 8 261,772,107 125,183,824 619,976,589 TOTAL Electric (Total of lines 3 thru 8) 9Gas 10 11 12 13 14 15 16TOTAL Gas (Total of lines 11 thru 16) 17 18 261,772,107 125,183,824 619,976,589 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19Classification of TOTAL 20 215,902,742 103,189,026 511,170,697 Federal Income Tax 21 45,869,365 21,994,798 108,805,892 State Income Tax 22Local Income Tax 23

FERC FORM NO. 1 (ED. 12-96) Page 276NOTESName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. CHANGES DURING YEAR ADJUSTMENTS Balance at End of Year Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (i) 

### 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.

1 2 37,898,804 3 15,796,000 4 316,756,845 5 69,420,100 6 33,212,000 24,231,211 219 7 34,535,768 8 507,619,517 24,231,211 9 10 11 12 13 14 15 16 17 18 507,619,517 24,231,211 19 20 418,430,768 19,973,787 21 89,188,749 4,257,424 22 23

FERC FORM NO. 1 (ED. 12-96) Page 277 NOTES (Continued)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of OTHER REGULATORY LIABILITIES (Account 254) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description and Purpose of DEBITS Credits Account (d)

(c) (a) Balance at End of Current Quarter/Year (e) Other Regulatory Liabilities Amount (f) Credited 

### 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.

Balance at Begining of Current Quarter/Year (b)

16,000,000 2,000,000 14,000,000 PacifiCorp CT Deferred Gain 456 1 U-1345-90-269 Amortize through 2019 2 3 225,017,542 19,228,660 256,466,218 50,677,336 Asset Retirement Obligation 230 4 FERC Order #552 5 6 48,916,373 4,616,988 45,668,861 1,369,476 Spent Nuclear Fuel Storage 518 7 E-01345A-03-0437,E-01345A-05-0816,-0826, 8 -0827 Amortize through 2047 9 10 366,624 366,624 Pinnacle West Energy Loan Interest 407.4 11 E-01345A-03-0437,E-01345A-05-0816,-0826, 12 -0827 Amortize through 2012 13 14 31,460,413 1,529,729 53,836,683 23,905,999 Income Taxes - Unamortized Investment Tax Credit 190 15 E-01345A-05-0816,-0826,-0827 16Amortize through 2044 17 18 7,241,400 8,850,600 1,609,200 Sundance Maintenance 19 E-01345A-05-0816,-0826,-0827 20 21 62,282,038 68,945,834 6,663,796 Income Tax - Change in Rates 22Amortize through 2041 23 24 6,161,929 6,161,929 Amonix Promissory Note 25 26 53,522,266 114,050,446 38,167,561 98,695,741 Renewable Energy Standard 549 27 E-01345A-03-0437,E-01345A-05-0816,-0826, 28 -0827 29 30 1,125,393 1,125,393 Star Center Patent Rights 31 E-01345A-09-0357 32 33 3,924,463 17,498,692 5,110,169 18,684,398 AZ Sun Program 440, 442 34 E-01345A-09-0338 35 36 13,590,960 2,944,928 10,646,032 Excess Deferred Taxes 190 37Amortize through 2019 38 39 69,030,889 4,016,118 73,047,007 Demand Side Management 440, 442 40

FERC FORM NO. 1/3-Q (REV 02-04) Page 278 41 TOTAL 274,752,727 231,767,095 513,088,229 470,102,597Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of OTHER REGULATORY LIABILITIES (Account 254) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description and Purpose of DEBITS Credits Account (d)

(c) (a) Balance at End of Current Quarter/Year (e) Other Regulatory Liabilities Amount (f) Credited 

### 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.

Balance at Begining of Current Quarter/Year (b) E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 1 Amortize through 2013 2 3 493,196 500,139 92,831 99,774 Minor Items 107, 182.3 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

FERC FORM NO. 1/3-Q (REV 02-04) Page 278.1 41 TOTAL 274,752,727 231,767,095 513,088,229 470,102,597Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC OPERATING REVENUES (Account 400) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Title of Account (c) (b) (a) Operating Revenues Year to Date Quarterly/Annual 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. Operating Revenues Previous year (no Quarterly) Sales of Electricity 1 1,543,136,337 (440) Residential Sales 1,585,395,614 2 (442) Commercial and Industrial Sales 3 1,265,970,898 Small (or Comm.) (See Instr. 4) 1,274,445,187 4 171,428,100 Large (or Ind.) (See Instr. 4) 174,856,673 5 20,665,695 (444) Public Street and Highway Lighting 20,613,057 6 204,903 (445) Other Sales to Public Authorities 183,950 7 (446) Sales to Railroads and Railways 8 (448) Interdepartmental Sales 9 3,001,405,933 TOTAL Sales to Ultimate Consumers 3,055,494,481 10 165,945,037 (447) Sales for Resale 178,534,117 11 3,167,350,970 TOTAL Sales of Electricity 3,234,028,598 12 9,414,000 (Less) (449.1) Provision for Rate Refunds -4,620,305 13 3,157,936,970 TOTAL Revenues Net of Prov. for Refunds 3,238,648,903 14Other Operating Revenues 15 9,143,930 (450) Forfeited Discounts 9,018,574 16 35,368,829 (451) Miscellaneous Service Revenues 24,986,765 17 (453) Sales of Water and Water Power 18 36,328,311 (454) Rent from Electric Property 9,160,288 19 (455) Interdepartmental Rents 20 4,676,926 (456) Other Electric Revenues 4,480,274 21 30,983,064 (456.1) Revenues from Transmission of Electricity of Others 31,636,457 22 (457.1) Regional Control Service Revenues 23 (457.2) Miscellaneous Revenues 24 25 116,501,060 TOTAL Other Operating Revenues 79,282,358 26 3,274,438,030 TOTAL Electric Operating Revenues 3,317,931,261 27

Page 300 FERC FORM NO. 1/3-Q (REV. 12-05)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC OPERATING REVENUES (Account 400) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MEGAWATT HOURS SOLD Previous Year (no Quarterly) Current Year (no Quarterly) AVG.NO. CUSTOMERS PER MONTH Year to Date Quarterly/Annual Amount Previous year (no Quarterly) (d) (e) (f) (g) 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.

1 13,290,230 994,244 1,005,074 13,256,456 2 3 12,588,782 121,116 122,360 12,531,865 4 2,188,600 3,744 3,721 2,222,623 5 139,231 971 981 140,121 6 3,483 161 160 3,071 7 8 9 28,210,326 1,120,236 1,132,296 28,154,136 10 3,433,100 46 49 4,342,927 11 31,643,426 1,120,282 1,132,345 32,497,063 12 13 31,643,426 1,120,282 1,132,345 32,497,063 14

Page 301 Line 12, column (b) includes $ of unbilled revenues. Line 12, column (d) includes MWH relating to unbilled revenues -31,118,496

-321,992

FERC FORM NO. 1/3-Q (REV. 12-05)

### Schedule Page: 300 Line No.: 4 Column: b 

## Basis of classification for small or large commercial and industrial sales is customer's NAICS code. Includes unmetered sales such as traffic lights, bus stop lighting, and public irrigation systems. Schedule Page: 300 Line No.: 4 Column: c 

## Basis of classification for small or large commercial and industrial sales is customer's NAICS code. Includes unmetered sales such as traffic lights, bus stop lighting, and public irrigation systems. Schedule Page: 300 Line No.: 5 Column: b 

## Basis of classification for small or large commercial and industrial sales is customer's NAICS code. Schedule Page: 300 Line No.: 5 Column: c 

## Basis of classification for small or large commercial and industrial sales is customer's NAICS code. Schedule Page: 300 Line No.: 17 Column: b 

## Schedule 3 Service Revenue $ 14,878,132 Connection Charges 9,970,052 Other 138,581 Total $ 24,986,765
Schedule Page: 300 Line No.: 17 Column: c 

## Schedule 3 Service Revenue $ 25,345,145 Connection Charges 9,968,204 Other 55,480 Total $ 35,368,829
Schedule Page: 300 Line No.: 21 Column: b 

## PCS Project $ 2,371,976 PacifiCorp CT Deferred Gain Amortization 2,000,000 Facility Charges 984,488 Fuel Loading 879,551 Management/Administration Fees 1,190,029 Participant Station Power Revenue 148,808 Installation of Photovoltaic Facilities 299,852 Surepay and Autopay Discount (1,379,400) Risk Management (2,251,029) Other 235,999 Total $ 4,480,274 Schedule Page: 300 Line No.: 21 Column: c 

## PCS Project $ 2,123,491 PacifiCorp CT Deferred Gain Amortization 2,000,000 Facility Charges 1,112,633 Fuel Loading 874,203 Management/Administration Fees 747,917 Participant Station Power Revenue 378,673 Installation of Photovoltaic Facilities 319,733 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

## Surepay and Autopay Discount (1,292,123) Risk Management (1,922,720) Other 335,119 Total $ 4,676,926 Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description of Service (a) 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.

Balance at End of (c) (b) Balance at End of Quarter 1 Quarter 2 Balance at End of Quarter 3 (d) (e) Balance at End of Year

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

FERC FORM NO. 1/3-Q (NEW. 12-05) Page 302 46 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
SALES OF ELECTRICITY BY RATE SCHEDULES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number and Title of Rate schedule MWh Sold (b) (a) Revenue (c) Average Number of Customers (d) KWh of Sales Per Customer (e) Revenue Per KWh Sold (f) 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.

1440 Residential 3,576,341 434,491 8,231 0.1346 481,258,688 2E-12 3,123,661 182,851 17,083 0.1182 369,200,219 3ET-1 3,202,570 207,404 15,441 0.1212 388,181,720 4ET-2 1,571,617 63,467 24,763 0.1053 165,469,997 5ECT-2 970,561 35,176 27,592 0.1048 101,670,794 6ECT-1R 336,107 38,332 8,768 0.0952 31,996,332 7E-12 Low Income 144,024 9,614 14,981 0.0985 14,185,708 8ET-1 Low Income 289,136 18,417 15,699 0.0991 28,640,884 9ET-2 Low Income 65,588 3,048 21,518 0.0918 6,018,242 10ECT-2 Low Income 13,542 662 20,456 0.0927 1,255,627 11ECT-1R Low Income 8,204 533 15,392 0.1132 928,932 12ET-SP 1,510 84 17,976 0.1058 159,689 13EPR-2 87,386 10,980 7,959 0.1079 9,429,835 14EPR-6 296 15 19,733 0.1099 32,542 15ET-EV 1,747 0.3039 530,969 16E-47 92,495 17Solar/Green Power 13,392,290 1,005,074 13,325 0.1194 1,599,052,673 18Total Residential 19 20442 Commercial 43,408 407 106,654 0.1171 5,081,702 21E-20 5,268 4,340 1,214 0.2428 1,278,973 22E-30 1,401,087 81,485 17,194 0.1320 184,913,967 23E-32 XS 2,523,528 29,078 86,785 0.1323 333,754,301 24E-32 S 3,088,701 3,879 796,262 0.0979 302,523,796 25E-32 M 2,935,447 805 3,646,518 0.0829 243,377,649 26E-32 L 3,852 80 48,150 0.1118 430,549 27E-32 TOU XS 38,021 226 168,235 0.1120 4,259,245 28E-32 TOU S 74,018 68 1,088,500 0.0945 6,997,485 29E-32 TOU M 225,962 43 5,254,930 0.0782 17,676,441 30E-32 TOU L 11,809 10 1,180,900 0.1098 1,296,970 31SCHOOL TOU RATE M 10,743 7 1,534,714 0.0995 1,069,254 32SCHOOL TOU RATE L 527,776 19 27,777,684 0.0744 39,265,500 33E-34 819,050 22 37,229,545 0.0663 54,284,523 34E-35 1,498 1 1,498,000 0.1006 150,725 35E-36 M 1 798 36E-40 20,763 0.3863 8,021,561 37E-47 793 1 793,000 0.5850 463,891 38E-56 339,840 1,354 250,990 0.0916 31,115,796 39E-221 9,839 25 393,560 0.0924 909,515 40EPR-2

28,154,136 3,060,114,786 1,132,296 24,865 0.1087 -321,992 -31,118,496 4,862 -66,226 0.0966 28,476,128 3,091,233,282 1,127,434 25,257 0.1086

FERC FORM NO. 1 (ED. 12-95) Page 304

41 TOTAL Billed 42 Total Unbilled Rev.(See Instr. 6) 43 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
SALES OF ELECTRICITY BY RATE SCHEDULES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number and Title of Rate schedule MWh Sold (b) (a) Revenue (c) Average Number of Customers (d) KWh of Sales Per Customer (e) Revenue Per KWh Sold (f) 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.

279,078 491 568,387 0.1023 28,562,245 1EPR-6 394,908 2Solar/Green Power 330,155 18 18,341,944 0.0711 23,458,607 3SC-S 12,690,636 122,360 103,716 0.1016 1,289,288,401 4Total Commercial 5 6442 Industrial and Irrigation 59 69 855 0.2906 17,143 7E-30 46,610 2,201 21,177 0.1626 7,577,186 8E-32 XS 83,950 785 106,943 0.1336 11,211,528 9E-32 S 188,931 274 689,529 0.1114 21,044,573 10E-32 M 390,787 95 4,113,547 0.0881 34,428,613 11E-32 L 50 2 25,000 0.1820 9,102 12E-32 TOU XS 492 4 123,000 0.1441 70,890 13E-32 TOU S 4,694 4 1,173,500 0.0961 451,010 14E-32 TOU M 68,092 8 8,511,500 0.0788 5,368,307 15E-32 TOU L 192,154 8 24,019,250 0.0776 14,918,969 16E-34 484,340 13 37,256,923 0.0711 34,446,094 17E-35 39,299 4 9,824,750 0.1010 3,970,073 18E-36 759 129 5,884 0.2299 174,480 19E-47 12,417 106 117,142 0.0911 1,130,588 20E-221 13,562 12 1,130,167 0.1068 1,448,435 21EPR-6 722,113 7 103,159,000 0.0567 40,928,190 22Special Contracts 2,248,309 3,721 604,222 0.0788 177,195,181 23Total Industrial & Irrigation 24 141,880 981 144,628 0.1473 20,892,416 25444 Public Street Lighting 141,880 981 144,628 0.1473 20,892,416 26Total Public Street Lighting 27 3,013 160 18,831 0.0612 184,306 28445 Other Public Authorities 3,013 160 18,831 0.0612 184,306 29Total Other Public Authorities 30 31Unbilled MWh & Revenue -135,834 0.1005 -13,657,059 32Residential Unbilled -158,771 0.0935 -14,843,214 33Commercial Unbilled -25,686 0.0910 -2,338,508 34Ind & Irrig. Unbilled -1,701 0.1644 -279,715 35Public Str Lighting Unbilled 36Other Public Auth Unbilled -321,992 0.0966 -31,118,496 37Total Unbilled Mwh & Revenue 38 39449.1 Provision for Rate Refunds 1,917,000 40Residential PRR

28,154,136 3,060,114,786 1,132,296 24,865 0.1087 -321,992 -31,118,496 4,862 -66,226 0.0966 28,476,128 3,091,233,282 1,127,434 25,257 0.1086

FERC FORM NO. 1 (ED. 12-95) Page 304.1

41 TOTAL Billed 42 Total Unbilled Rev.(See Instr. 6) 43 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
SALES OF ELECTRICITY BY RATE SCHEDULES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number and Title of Rate schedule MWh Sold (b) (a) Revenue (c) Average Number of Customers (d) KWh of Sales Per Customer (e) Revenue Per KWh Sold (f) 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.

1,763,000 1Commercial PRR 364,000 2Industrial & Irrigation PRR 3Public Street Lighting PRR 576,305 4Sales For Resale - Traditional 5Other Public Authorities PRR 4,620,305 6Total Provision for Rate Refunds 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

28,154,136 3,060,114,786 1,132,296 24,865 0.1087 -321,992 -31,118,496 4,862 -66,226 0.0966 28,476,128 3,091,233,282 1,127,434 25,257 0.1086

FERC FORM NO. 1 (ED. 12-95) Page 304.2

41 TOTAL Billed 42 Total Unbilled Rev.(See Instr. 6) 43 TOTAL

### Schedule Page: 304 Line No.: 16 Column: f 

## APS does not bill for these service by kWh used, therefore these figures do not represent an accurate reflection of actual revenue per kWh sold. Schedule Page: 304 Line No.: 17 Column: f 

## APS does not bill for these service by kWh used, therefore these figures do not represent an accurate reflection of actual revenue per kWh sold. Schedule Page: 304 Line No.: 36 Column: f 

## APS does not bill for these service by kWh used, therefore these figures do not represent an accurate reflection of actual revenue per kWh sold. Schedule Page: 304 Line No.: 37 Column: f 

## APS does not bill for these service by kWh used, therefore these figures do not represent an accurate reflection of actual revenue per kWh sold. Schedule Page: 304.1 Line No.: 2 Column: f 

## APS does not bill for these service by kWh used, therefore these figures do not represent an accurate reflection of actual revenue per kWh sold. Schedule Page: 304.1 Line No.: 19 Column: f 

## APS does not bill for these service by kWh used, therefore these figures do not represent an accurate reflection of actual revenue per kWh sold. Schedule Page: 304.1 Line No.: 25 Column: f 

## APS does not bill for these service by kWh used, therefore these figures do not represent an accurate reflection of actual revenue per kWh sold. Schedule Page: 304.1 Line No.: 26 Column: f 

## APS does not bill for these service by kWh used, therefore these figures do not represent an accurate reflection of actual revenue per kWh sold. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 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.

Aguila Irrigation District 1.380 1.380 2.071 86308 RQ 1 Buckeye Irrigation District 0.484 0.485 0.582 86306 RQ 2 City of Williams 4.102 5.311 5.311 MRT Vol 1 RQ 3 Electrical District No. 3 83.556 90.176 90.176 89695 RQ 4 Electrical District No. 6 0.007 0.007 0.043 86307 RQ 5 Electrical District No. 7 0.000 0.000 0.000 86304 RQ 6 Electrical District No. 8 9.438 9.439 14.158 86310 RQ 7 Harquahala Valley Irrigation District 4.078 4.079 4.450 86309 RQ 8 Maricopa County Municipal Water Conser 0.043 0.043 0.255 86058 RQ 9 McMullen Valley Irrigiation District 2.069 2.069 4.139 86311 RQ 10 Roosevelt Irrigation District 0.826 0.827 1.102 86305 RQ 11 Tohono O'Odham Utility Authority 6.798 8.255 8.255 87975 RQ 12Tonopah Irrigation District 0.938 0.938 1.250 86312 RQ 13Town of Wickenburg 0.815 0.816 1.644 85726 RQ 14

FERC FORM NO. 1 (ED. 12-90) Page 310 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 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.

Citigroup Energy Inc. MRT Vol 3 IF 1 Valley Electric Association WSPP IF 2Arizona Electric Power Cooperative WSPP SF 3 Barclays Bank PLC MRT Vol 3 SF 4 BP Energy Company WSPP SF 5 California Independent Systems Operator MRT Vol 3 SF 6 Cargill Power Markets, LLC WSPP SF 7 Central Arizona Water Conservation Dist MRT Vol 3 SF 8 Citigroup Energy Inc. MRT Vol 3 SF 9 Constellation Energy Commodities Group WSPP SF 10 DB Energy Trading LLC WSPP SF 11 EDF Trading North America LLC WSPP SF 12 El Paso Electric Company WSPP SF 13 Gila River Power, L.P. MRT Vol 3 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.1 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 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.

IBERDROLA Renewables, Inc. MRT Vol 3 SF 1 Idaho Power Company WSPP SF 2 Imperial Irrigation District WSPP SF 3J. Aron & Company WSPP SF 4JP Morgan Ventures Energy Corporation WSPP SF 5 Los Alamos County WSPP SF 6 Los Angeles Dept of Water and Power WSPP SF 7 Macquarie Energy LLC MRT Vol 3 SF 8 Morgan Stanley Capital Group, Inc. MRT Vol 3 SF 9 Nevada Power Company WSPP SF 10 PacifiCorp MRT Vol 3 SF 11 Powerex Corp. WSPP SF 12 PPL Energy Plus, LLC WSPP SF 13 Public Service Co of Colorado WSPP SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.2 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 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.

Public Service Co of New Mexico WSPP SF 1 Rainbow Energy Marketing Corporation WSPP SF 2 Salt River Project WSPP SF 3 Sempra Generation WSPP SF 4 Shell Energy North America (US), L.P. MRT Vol 3 SF 5 Sierra Pacific Power Co. WSPP SF 6 Southern California Edison Company WSPP SF 7 Southwestern Public Service Company WSPP SF 8Tenaska Power Services Company WSPP SF 9TransAlta Energy Marketing, US, Inc. WSPP SF 10Tri-State Generation and Transmission WSPP SF 11 Tucson Electric Power Co. WSPP SF 12Twin Eagle Resource Management, LLC WSPP SF 13 UNS Electric, Inc. WSPP SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.3 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 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.

WAPA, Colorado River Storage Project WSPP SF 1 WAPA, Desert Southwest Region WSPP SF 2Arizona Electric Power Cooperative WSPP OS 3 Central Arizona Water Conservation Dist MRT Vol 3 OS 4 Los Angeles Dept of Water & Power WSPP OS 5 Nevada Power Company WSPP OS 6 PacifiCorp MRT Vol 3 OS 7 PacifiCorp Supplemental Coal RS # 182 OS 8 PacifiCorp Supplemental Other RS # 182 OS 9 Public Service Co of New Mexico WSPP OS 10 Salt River Project WSPP OS 11 Southwest Reserve Sharing Group SRSG1 OS 12Tenaska Power Services Company WSPP OS 13Tri-State Generation and Transmission WSPP OS 14

FERC FORM NO. 1 (ED. 12-90) Page 310.4 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 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.

Tucson Electric Power Co. WSPP OS 1 WAPA, Desert Southwest Region WSPP OS 2 Change in Estimate AD 3 4 5 6 7 8 9 10 11 12 13 14

FERC FORM NO. 1 (ED. 12-90) Page 310.5 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### 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.

422,077 165,431 316,919 904,427 12,073 1 143,326 58,298 229,280 430,904 4,256 2 683,327 851,858 39,600 1,574,785 32,539 3 40,554,163 4,312,217 44,866,380 500,037 4 2,071 863 26,762 29,696 63 5 383,803 383,803 6 2,952,241 1,128,095 1,514,607 5,594,943 82,566 7 1,250,605 488,810 627,084 2,366,499 35,690 8 11,639 5,141 380,195 396,975 370 9 646,142 247,466 540,158 1,433,766 18,007 10 236,752 99,647 361,782 698,181 7,275 11 3,881,398 450,679 4,332,077 45,589 12 300,334 117,757 175,644 593,735 8,601 13 252,226 197,949 159,960 610,135 7,098 14

FERC FORM NO. 1 (ED. 12-90) Page 311 51,336,301 109,494,035 160,830,336 754,164 3,588,763 4,342,927 9,518,690 64,216,306 4,823,776 14,342,466 114,317,811 178,534,117 3,361,315 0 3,361,315Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### 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.

9,222,279 9,222,279 122,800 1 4,502,346 4,502,346 61,677 2 655,514 655,514 26,549 3 336,100 336,100 11,520 4 808,200 808,200 27,200 5 15,871,840 15,871,840 599,231 6 3,915,748 3,915,748 119,149 7 968,712 968,712 38,976 8 7,976,501 7,976,501 269,212 9 3,731,220 3,731,220 122,200 10 1,544,800 1,544,800 55,625 11 1,199,729 1,199,729 50,239 12 909,530 909,530 29,510 13 3,155,849 3,155,849 105,946 14

FERC FORM NO. 1 (ED. 12-90) Page 311.1 51,336,301 109,494,035 160,830,336 754,164 3,588,763 4,342,927 9,518,690 64,216,306 4,823,776 14,342,466 114,317,811 178,534,117 3,361,315 0 3,361,315Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### 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.

2,070,740 2,070,740 70,975 1 307,211 307,211 12,347 2 3,692,144 3,692,144 112,078 3 954,650 954,650 29,200 4 396,794 396,794 14,246 5 225,906 225,906 7,632 6 2,190,877 2,190,877 70,917 7 2,290,139 2,290,139 79,917 8 2,636,945 2,636,945 126,562 9 266,305 266,305 10,250 10 4,508,721 4,508,721 147,066 11 1,157,476 1,157,476 39,043 12 120,463 120,463 4,053 13 13,600 13,600 400 14

FERC FORM NO. 1 (ED. 12-90) Page 311.2 51,336,301 109,494,035 160,830,336 754,164 3,588,763 4,342,927 9,518,690 64,216,306 4,823,776 14,342,466 114,317,811 178,534,117 3,361,315 0 3,361,315Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### 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.

5,484,239 5,484,239 181,771 1 53,852 53,852 3,642 2 4,292,683 4,292,683 160,475 3 1,141,718 1,141,718 40,890 4 3,051,029 3,051,029 90,585 5 14,966 14,966 429 6 2,301,233 2,301,233 85,875 7 83,550 83,550 2,950 8 57,593 57,593 1,534 9 3,154,604 3,154,604 116,867 10 2,051,389 2,051,389 81,938 11 7,121,986 7,121,986 266,015 12 671,733 671,733 23,620 13 2,369,280 2,369,280 88,337 14

FERC FORM NO. 1 (ED. 12-90) Page 311.3 51,336,301 109,494,035 160,830,336 754,164 3,588,763 4,342,927 9,518,690 64,216,306 4,823,776 14,342,466 114,317,811 178,534,117 3,361,315 0 3,361,315Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### 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.

98,985 98,985 2,670 1 9,668 9,668 403 2 2,200 2,200 72 3 50,640 50,640 2,240 4 1,500 1,500 100 5 1,200 1,200 100 6 10,850 10,850 350 7 289,847 289,847 11,000 8 1,367,919 1,367,919 49,856 9 163,528 163,528 7,600 10 7,500 7,500 255 11 4,000,046 4,000,046 4,226 12 338 338 13 13 650 650 13 14

FERC FORM NO. 1 (ED. 12-90) Page 311.4 51,336,301 109,494,035 160,830,336 754,164 3,588,763 4,342,927 9,518,690 64,216,306 4,823,776 14,342,466 114,317,811 178,534,117 3,361,315 0 3,361,315Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### 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.

8,766 8,766 416 1 250 250 1 2 823,730 823,730 3 4 5 6 7 8 9 10 11 12 13 14

FERC FORM NO. 1 (ED. 12-90) Page 311.5 51,336,301 109,494,035 160,830,336 754,164 3,588,763 4,342,927 9,518,690 64,216,306 4,823,776 14,342,466 114,317,811 178,534,117 3,361,315 0 3,361,315

### Schedule Page: 310 Line No.: 1 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 2 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 3 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 4 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 5 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 6 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 7 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 8 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 9 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 10 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 11 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 12 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 13 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310 Line No.: 14 Column: j 

## Customer Charges and Actual Transmission Pass-Thru Charges Schedule Page: 310.4 Line No.: 3 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 4 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 5 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 6 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 7 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 8 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 9 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 10 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 11 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 12 Column: b Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

## Represents NonFirm Schedule Page: 310.4 Line No.: 12 Column: c 

## Rates are set per the Southwest Reserve Sharing Group participation agreement. Schedule Page: 310.4 Line No.: 12 Column: j 

## Tucson Electric Power Option Premium and SRSG Emergency Assist Exempt Schedule Page: 310.4 Line No.: 13 Column: b 

## Represents NonFirm Schedule Page: 310.4 Line No.: 14 Column: b 

## Represents NonFirm Schedule Page: 310.5 Line No.: 1 Column: b 

## Represents NonFirm Schedule Page: 310.5 Line No.: 2 Column: b 

## Represents NonFirm Schedule Page: 310.5 Line No.: 3 Column: a 

## The amounts shown on pages 310 and 311are actual amounts sold to companies during the reporting period. The change in estimate amount represents various timing differences between the accrued amounts for sales for resale compared to the actual amount. Schedule Page: 310.5 Line No.: 3 Column: b 

## The amounts shown on pages 310 and 311are actual amounts sold to companies during the reporting period. The change in estimate amount represents various timing differences between the accrued amounts for sales for resale compared to the actual amount. Schedule Page: 310.5 Line No.: 3 Column: j 

## Change in estimate between accrual and actual. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2ELECTRIC OPERATION AND MAINTENANCE EXPENSES Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

1. POWER PRODUCTION EXPENSES 1 A. Steam Power Generation 2 Operation 3 (500) Operation Supervision and Engineering 4 7,525,334 8,974,658 (501) Fuel 5 251,582,097 242,031,514 (502) Steam Expenses 6 25,631,368 24,977,443 (503) Steam from Other Sources 7 (Less) (504) Steam Transferred-Cr. 8 (505) Electric Expenses 9 4,881,737 5,142,368 (506) Miscellaneous Steam Power Expenses 10 13,119,031 14,508,293 (507) Rents 11 656,702 618,665 (509) Allowances 12TOTAL Operation (Enter Total of Lines 4 thru 12) 13 303,396,269 296,252,941 Maintenance 14 (510) Maintenance Supervision and Engineering 15 7,625,136 7,890,924 (511) Maintenance of Structures 16 2,339,567 2,316,545 (512) Maintenance of Boiler Plant 17 41,038,446 33,504,590 (513) Maintenance of Electric Plant 18 9,702,765 9,456,739 (514) Maintenance of Miscellaneous Steam Plant 19 8,131,801 12,020,766 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 68,837,715 65,189,564 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 372,233,984 361,442,505 B. Nuclear Power Generation 22 Operation 23 (517) Operation Supervision and Engineering 24 23,549,422 25,295,808 (518) Fuel 25 82,380,419 87,024,312 (519) Coolants and Water 26 10,795,943 10,992,861 (520) Steam Expenses 27 10,657,036 9,814,961 (521) Steam from Other Sources 28 (Less) (522) Steam Transferred-Cr. 29 (523) Electric Expenses 30 6,753,419 8,906,115 (524) Miscellaneous Nuclear Power Expenses 31 37,109,388 32,916,930 (525) Rents 32 46,780,731 45,667,235 TOTAL Operation (Enter Total of lines 24 thru 32) 33 218,026,358 220,618,222 Maintenance 34 (528) Maintenance Supervision and Engineering 35 9,205,764 7,609,265 (529) Maintenance of Structures 36 3,051,702 2,033,706 (530) Maintenance of Reactor Plant Equipment 37 13,727,332 11,754,828 (531) Maintenance of Electric Plant 38 15,470,279 15,016,499 (532) Maintenance of Miscellaneous Nuclear Plant 39 5,116,888 4,289,993 TOTAL Maintenance (Enter Total of lines 35 thru 39) 40 46,571,965 40,704,291 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41 264,598,323 261,322,513 C. Hydraulic Power Generation 42 Operation 43 (535) Operation Supervision and Engineering 44 (536) Water for Power 45 (537) Hydraulic Expenses 46 (538) Electric Expenses 47 (539) Miscellaneous Hydraulic Power Generation Expenses 48 (540) Rents 49TOTAL Operation (Enter Total of Lines 44 thru 49) 50 C. Hydraulic Power Generation (Continued) 51 Maintenance 52 (541) Mainentance Supervision and Engineering 53 (542) Maintenance of Structures 54 (543) Maintenance of Reservoirs, Dams, and Waterways 55 (544) Maintenance of Electric Plant 56 (545) Maintenance of Miscellaneous Hydraulic Plant 57TOTAL Maintenance (Enter Total of lines 53 thru 57) 58TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59

FERC FORM NO. 1 (ED. 12-93) Page320ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

D. Other Power Generation 60 Operation 61 (546) Operation Supervision and Engineering 62 4,733,454 4,848,425 (547) Fuel 63 485,651,374 430,876,882 (548) Generation Expenses 64 9,859,505 8,391,866 (549) Miscellaneous Other Power Generation Expenses 65 87,569,173 59,310,396 (550) Rents 66TOTAL Operation (Enter Total of lines 62 thru 66) 67 587,813,506 503,427,569 Maintenance 68 (551) Maintenance Supervision and Engineering 69 527,323 431,641 (552) Maintenance of Structures 70 1,048,716 989,042 (553) Maintenance of Generating and Electric Plant 71 25,171,219 26,198,820 (554) Maintenance of Miscellaneous Other Power Generation Plant 72 11,974,087 5,227,218 TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 38,721,345 32,846,721 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 626,534,851 536,274,290 E. Other Power Supply Expenses 75 (555) Purchased Power 76 209,835,470 240,316,470 (556) System Control and Load Dispatching 77 -933,031 -1,917,184 (557) Other Expenses 78 3,482,412 3,282,363 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 212,384,851 241,681,649 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 1,475,752,009 1,400,720,957 2. TRANSMISSION EXPENSES 81 Operation 82 (560) Operation Supervision and Engineering 83 899,743 2,388,542 84 (561.1) Load Dispatch-Reliability 85 1,684,637 2,103,063 (561.2) Load Dispatch-Monitor and Operate Transmission System 86 1,948,197 2,341,566 (561.3) Load Dispatch-Transmission Service and Scheduling 87 871,968 736,610 (561.4) Scheduling, System Control and Dispatch Services 88 1,881,904 1,797,643 (561.5) Reliability, Planning and Standards Development 89 674,513 618,834 (561.6) Transmission Service Studies 90 205,233 305,832 (561.7) Generation Interconnection Studies 91 206,181 303,583 (561.8) Reliability, Planning and Standards Development Services 92 1,479,241 (562) Station Expenses 93 970,761 1,005,496 (563) Overhead Lines Expenses 94 2,468,793 2,600,189 (564) Underground Lines Expenses 95 36,604 33,037 (565) Transmission of Electricity by Others 96 17,009,889 18,827,481 (566) Miscellaneous Transmission Expenses 97 6,699,447 5,302,721 (567) Rents 98 33,198,800 6,614,513 TOTAL Operation (Enter Total of lines 83 thru 98) 99 68,756,670 46,458,351 Maintenance 100 (568) Maintenance Supervision and Engineering 101 220,054 508,136 (569) Maintenance of Structures 102 1,123,572 715,754 (569.1) Maintenance of Computer Hardware 103 (569.2) Maintenance of Computer Software 104 (569.3) Maintenance of Communication Equipment 105 109,469 127,583 (569.4) Maintenance of Miscellaneous Regional Transmission Plant 106 (570) Maintenance of Station Equipment 107 4,975,659 5,270,412 (571) Maintenance of Overhead Lines 108 9,685,381 13,876,015 (572) Maintenance of Underground Lines 109 98,238 116,932 (573) Maintenance of Miscellaneous Transmission Plant 110 899,659 173,362 TOTAL Maintenance (Total of lines 101 thru 110) 111 17,112,032 20,788,194 TOTAL Transmission Expenses (Total of lines 99 and 111) 112 85,868,702 67,246,545

FERC FORM NO. 1 (ED. 12-93) Page321ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

3. REGIONAL MARKET EXPENSES 113 Operation 114 (575.1) Operation Supervision 115 (575.2) Day-Ahead and Real-Time Market Facilitation 116 (575.3) Transmission Rights Market Facilitation 117 (575.4) Capacity Market Facilitation 118 (575.5) Ancillary Services Market Facilitation 119 (575.6) Market Monitoring and Compliance 120 (575.7) Market Facilitation, Monitoring and Compliance Services 121 (575.8) Rents 122Total Operation (Lines 115 thru 122) 123 Maintenance 124 (576.1) Maintenance of Structures and Improvements 125 (576.2) Maintenance of Computer Hardware 126 (576.3) Maintenance of Computer Software 127 (576.4) Maintenance of Communication Equipment 128 (576.5) Maintenance of Miscellaneous Market Operation Plant 129Total Maintenance (Lines 125 thru 129) 130TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131 4. DISTRIBUTION EXPENSES 132 Operation 133 (580) Operation Supervision and Engineering 134 3,966,769 4,172,189 (581) Load Dispatching 135 1,177,206 1,187,005 (582) Station Expenses 136 1,014,006 1,204,328 (583) Overhead Line Expenses 137 2,700,977 1,940,611 (584) Underground Line Expenses 138 3,267,249 2,304,862 (585) Street Lighting and Signal System Expenses 139 254,831 121,925 (586) Meter Expenses 140 3,670,762 6,569,888 (587) Customer Installations Expenses 141 -596,934 -162,663 (588) Miscellaneous Expenses 142 33,791,179 35,911,273 (589) Rents 143 554,148 511,744 TOTAL Operation (Enter Total of lines 134 thru 143) 144 49,800,193 53,761,162 Maintenance 145 (590) Maintenance Supervision and Engineering 146 1,089,840 2,156,951 (591) Maintenance of Structures 147 793,279 480,095 (592) Maintenance of Station Equipment 148 1,779,004 2,036,021 (593) Maintenance of Overhead Lines 149 14,128,113 16,194,307 (594) Maintenance of Underground Lines 150 7,979,839 10,141,361 (595) Maintenance of Line Transformers 151 3,117,327 2,904,087 (596) Maintenance of Street Lighting and Signal Systems 152 342,884 196,255 (597) Maintenance of Meters 153 -972 (598) Maintenance of Miscellaneous Distribution Plant 154 4,235,725 4,102,146 TOTAL Maintenance (Total of lines 146 thru 154) 155 33,465,039 38,211,223 TOTAL Distribution Expenses (Total of lines 144 and 155) 156 83,265,232 91,972,385 5. CUSTOMER ACCOUNTS EXPENSES 157 Operation 158 (901) Supervision 159 2,652,510 2,430,710 (902) Meter Reading Expenses 160 9,023,911 6,645,446 (903) Customer Records and Collection Expenses 161 37,859,669 37,977,436 (904) Uncollectible Accounts 162 5,751,502 5,290,371 (905) Miscellaneous Customer Accounts Expenses 163 796,111 492,420 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 56,083,703 52,836,383

FERC FORM NO. 1 (ED. 12-93) Page322ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165 Operation 166 (907) Supervision 167 1,909,536 825,644 (908) Customer Assistance Expenses 168 69,636,634 74,898,452 (909) Informational and Instructional Expenses 169 458,287 430,897 (910) Miscellaneous Customer Service and Informational Expenses 170 1,398,510 1,012,463 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 73,402,967 77,167,456 7. SALES EXPENSES 172 Operation 173 (911) Supervision 174 118 (912) Demonstrating and Selling Expenses 175 4,116,856 5,007,605 (913) Advertising Expenses 176 140,612 100,000 (916) Miscellaneous Sales Expenses 177 4,571,381 4,351,664 TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178 8,828,967 9,459,269 8. ADMINISTRATIVE AND GENERAL EXPENSES 179 Operation 180 (920) Administrative and General Salaries 181 82,438,082 96,475,201 (921) Office Supplies and Expenses 182 21,307,992 24,365,845 (Less) (922) Administrative Expenses Transferred-Credit 183 24,567,258 24,303,198 (923) Outside Services Employed 184 13,319,392 18,840,236 (924) Property Insurance 185 6,252,520 5,723,043 (925) Injuries and Damages 186 8,347,123 8,427,023 (926) Employee Pensions and Benefits 187 85,901,784 101,437,381 (927) Franchise Requirements 188 (928) Regulatory Commission Expenses 189 18,863,617 16,886,150 (929) (Less) Duplicate Charges-Cr. 190 (930.1) General Advertising Expenses 191 2,198,723 2,759,086 (930.2) Miscellaneous General Expenses 192 -49,184,536 -56,055,295 (931) Rents 193 7,656,082 9,711,342 TOTAL Operation (Enter Total of lines 181 thru 193) 194 172,533,521 204,266,814 Maintenance 195 (935) Maintenance of General Plant 196 5,972,727 8,219,115 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 178,506,248 212,485,929 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 1,961,707,828 1,911,888,924

FERC FORM NO. 1 (ED. 12-93) Page323Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 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.

277,944 Dynegy Arlington - Tolling Agreement RQ 1 191,940 Gila River Power - Tolling Agreement RQ 2 11,652 Salt River Project RQ 3 N/A N/A N/A CE Turbo LLC LF 4 N/A N/A N/A Morgan Stanley Capital Group, Inc. LF 5 N/A N/A N/A Ajo Improvement Co. (Phelps Dodge) LF 6 N/A N/A N/A Co-Generation LF 7 N/A N/A N/A Electrical District #5 LF 8 N/A N/A N/A Net Inadvertant LF 9 N/A N/A N/A Citigroup Energy Inc. IF 10 N/A N/A N/A Macquarie Energy LLC IF 11 N/A N/A N/A Morgan Stanley Capital Group, Inc. IF 12 N/A N/A N/A Shell Energy North American (US), L.P IF 13 N/A N/A N/A WAPA, Desert Southwest Region IF 14

FERC FORM NO. 1 (ED. 12-90) Page 326 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 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.

N/A N/A N/A AG-1 Contracts SF 1 N/A N/A N/A Arizona Electric Power Cooperative SF 2 N/A N/A N/A California Independent System Operator SF 3 N/A N/A N/A Cagrill Power Markets, LLC SF 4 N/A N/A N/A Catalyst Paper Snowflake Inc. SF 5 N/A N/A N/A Central Arizona Water Conservation Dis SF 6 N/A N/A N/A Citigroup Energy Inc. SF 7 N/A N/A N/A Constellation Energy Commodities Group SF 8 N/A N/A N/A DB Energy Trading LLC SF 9 N/A N/A N/A EDF Trading North America LLC SF 10 N/A N/A N/A El Paso Electric Company SF 11 N/A N/A N/A Gila River Power, LLC SF 12 N/A N/A N/A IBERDROLA Renewables, Inc. SF 13 N/A N/A N/A Idaho Power Company SF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.1 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 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.

N/A N/A N/A Imperial Irrigation District SF 1 N/A N/A N/A JP Morgan Ventrues Energy Corporation SF 2 N/A N/A N/A Los Angeles Dept of Water & Power SF 3 N/A N/A N/A Macquarie Energy LLC SF 4 N/A N/A N/A Morgan Stanely Capital Group Inc. SF 5 N/A N/A N/A Nevada Power Company SF 6 N/A N/A N/A PacifiCorp SF 7 N/A N/A N/A Powerex Corp. SF 8 N/A N/A N/A PPL Energy Plus, LLC SF 9 N/A N/A N/A Public Service Co of Colorado SF 10 N/A N/A N/A Public Serivce Co of New Mexico SF 11 N/A N/A N/A Rainbow Energy Marketing Corporation SF 12 N/A N/A N/A Salt River Project SF 13 N/A N/A N/A Sempra Generation SF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.2 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 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.

N/A N/A N/A Shell Energy North America (US), Inc. SF 1 N/A N/A N/A Sierra Pacific Power Co. SF 2 N/A N/A N/A Southern California Edison SF 3 N/A N/A N/A Southwestern Public Service SF 4 N/A N/A N/A TransAlta Energy Marketing, US, Inc. SF 5 N/A N/A N/A Tri-State Generation and Transmission SF 6 N/A N/A N/A Tucson Electric Power Company SF 7 N/A N/A N/A Twin Eagle Resource Management, LLC SF 8 N/A N/A N/A UNS Electric, Inc. SF 9 N/A N/A N/A Valley Electric Association, Inc. SF 10 N/A N/A N/A WAPA, Desert Southwest Region SF 11 N/A N/A N/A Aragonne Wind, LLC LU 12 N/A N/A N/A Glendale Energy LLC LU 13 N/A N/A N/A High Lonesome Wind Ranch, LLC LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326.3 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 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.

N/A N/A N/A Perrin Ranch Wind LLC LU 1 N/A N/A N/A RE Ajo 1 LLC LU 2 N/A N/A N/A RE Bagdad Solar 1 LLC LU 3 N/A N/A N/A Snowflake Power, LLC LU 4 N/A N/A N/A SunE AZ 1 LLC LU 5 N/A N/A N/A SunE AZ 2 LLC LU 6 N/A N/A N/A Waste Management Renewable Energy, LLC LU 7 N/A N/A N/A Aguila Irrigation District 141 EX 8 N/A N/A N/A Buckeye Water Conservation & Drainage 155 EX 9 N/A N/A N/A City of Azusa Exchange EX 10 N/A N/A N/A Electric District #6 126 EX 11 N/A N/A N/A Electric District #7 128 EX 12 N/A N/A N/A Electric District #8 140 EX 13 N/A N/A N/A Harqualhala Valley Power District 153 EX 14

FERC FORM NO. 1 (ED. 12-90) Page 326.4 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 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.

N/A N/A N/A Maricopa City Municipal Water Conservt 168 EX 1 N/A N/A N/A McMullen Valley Water Conservt Dist 142 EX 2 N/A N/A N/A PafifiCorp Exchange 182 EX 3 N/A N/A N/A Roosevelt Irrigation District 158 EX 4 N/A N/A N/A Tonopah Irrigation District 143 EX 5 N/A N/A N/A AG-1 Contracts OS 6 N/A N/A N/A Banked Energy OS 7 N/A N/A N/A California Independent System Operator OS 8 N/A N/A N/A Cargill Power Markets, LLC OS 9 N/A N/A N/A Catalyst Paper Snowflake Inc. OS 10 N/A N/A N/A Central Arizona Water Conservation Dis OS 11 N/A N/A N/A Constellation Energy Commodities Group OS 12 N/A N/A N/A EDF Trading North America LLC OS 13 N/A N/A N/A Gila River Power, LLC OS 14

FERC FORM NO. 1 (ED. 12-90) Page 326.5 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 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.

N/A N/A N/A JP Morgan Ventures Energy Corporation OS 1 N/A N/A N/A Los Angeles Dept of Water & Power OS 2 N/A N/A N/A Options and Hedges OS 3 N/A N/A N/A PacifiCorp OS 4 N/A N/A N/A Power Supply Adjustor OS 5 N/A N/A N/A Powerex Corp. OS 6 N/A N/A N/A Public Service Co of New Mexico OS 7 N/A N/A N/A Salt River Project OS 8 N/A N/A N/A SFAS 133 OS 9 N/A N/A N/A Shell Energy North America (US), L.P. OS 10 N/A N/A N/A Southwest Reserve Sharing Group OS 11 N/A N/A N/A Tri-State Generation and Transmission OS 12 N/A N/A N/A Twin Eagle Resource Management, LLC OS 13 N/A N/A N/A WAPA, Desert Southwest Region OS 14

FERC FORM NO. 1 (ED. 12-90) Page 326.6 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 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.

N/A N/A N/A Change in Estimate AD 1 N/A N/A N/A Prior Years Adjustment AD 2 3 4 5 6 7 8 9 10 11 12 13 14

FERC FORM NO. 1 (ED. 12-90) Page 326.7 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours
(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### 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.

59,089,200 2,510,948 61,600,148 1 1,667,663 37,819,038 3,684,614 41,503,652 2 2,303,284 1,800,000 5,418,358 1,408,780 8,627,138 3 188,506 4,301,759 4,301,759 4 65,969 1,564,806 1,564,806 5 27,600 6

27 7 217 8 80 9 46,743 33,427,812 33,427,812 10 471,883 4,054,277 4,054,277 11 61,662 6,109,300 6,109,300 12 122,800 5,164,679 5,164,679 13 174,701 434,200 434,200 14

12

FERC FORM NO. 1 (ED. 12-90) Page 327 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours
(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### 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.

2,413,082 2,413,082 1 75,264 8,001 8,001 2

271 2,431,916 3,390,916 5,822,832 3 122,280 448,141 448,141 4 27,032 10,588 10,588 5

193 12,838 12,838 6 438 3,286,844 3,286,844 7 97,219 3,771 3,771 8

203 2,852 2,852 9 124 475,984 475,984 10 21,202 59,452 59,452 11 2,645 164,684 164,684 12 5,463 1,200 1,200 13

80 2,126,373 2,126,373 14 109,168

FERC FORM NO. 1 (ED. 12-90) Page 327.1 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours
(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### 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.

84,719 84,719 1 2,980 126,015 126,015 2 3,667 95,320 95,320 3 2,294 61,956 61,956 4 2,244 174,806 174,806 5 4,980 504,200 504,200 6 14,950 757,518 757,518 7 29,330 652,996 652,996 8 19,274 171,548 171,548 9 12,088 1,245 1,245 10

19 413,313 413,313 11 13,756 573,474 573,474 12 50,096 364,225 364,225 13 10,237 2,229,970 2,229,970 14 63,225

FERC FORM NO. 1 (ED. 12-90) Page 327.2 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours
(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### 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.

11,808 11,808 1 998 5,635 5,635 2 161 27,960 27,960 3 1,459 5,553 5,553 4 182 235,499 235,499 5 10,597 24,518 24,518 6

898 125,958 125,958 7 5,103 8,968 8,968 8 553 1,557 1,557 9 68 1,825 1,825 10 25 11 1 16,686,558 16,686,558 12 278,448 1,294,000 1,294,000 13 16,535 14,246,176 14,246,176 14 286,692

FERC FORM NO. 1 (ED. 12-90) Page 327.3 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours
(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### 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.

16,743,705 16,743,705 1 199,444 1,242,550 1,242,550 2 10,362 4,856,760 4,856,760 3 35,976 9,390,896 9,390,896 4 112,019 2,864,150 2,864,150 5 27,469 91,251 91,251 6 1,502 642,823 642,823 7 8,208 541 3,373 8 439 9 213,563 171,396 -1,109,134 -1,109,134 10 608 1,039 11 2,754 2,655 12 6,910 6,910 13 1,770 14

FERC FORM NO. 1 (ED. 12-90) Page 327.4 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours
(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### 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.

4,591 4,416 1 1,079 3,880 2 576,642 571,391 -1,458,123 -1,458,123 3 466 466 4 87 135 5 17,903 17,903 6 1,158 -4,283,780 -4,283,780 7 38,756 584,893 623,649 8 1,250 2,504 2,504 9

51 8,584 8,584 10 881 44,995 44,995 11 1,865 12,500 12,500 12 400 640,376 640,376 13 22,943 45,043 45,043 14 1,423

FERC FORM NO. 1 (ED. 12-90) Page 327.5 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours
(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### 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.

13,280 13,280 1 410 49,200 49,200 2 1,200 28,302,133 28,302,133 3 2,250 2,250 4 75 -46,262,616 -46,262,616 5 192,800 192,800 6 5,800 141,578 141,578 7 6,800 67,278 67,278 8 2,132 1,874,032 1,874,032 9 9,139 9,139 10 426 76,420 76,420 11 977 7,350 7,350 12 30 7,280 7,280 13 525 4,616,483 4,616,483 14 154,628

FERC FORM NO. 1 (ED. 12-90) Page 327.6 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. MegaWatt Hours
(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### 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.

331,115 331,115 1 363 363 2 3 4 5 6 7 8 9 10 11 12 13 14

FERC FORM NO. 1 (ED. 12-90) Page 327.7 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470

### Schedule Page: 326 Line No.: 1 Column: l 

## Administrative Costs Schedule Page: 326 Line No.: 2 Column: l 

## Administrative Costs Schedule Page: 326 Line No.: 3 Column: a 

## Eastern Area Schedule Page: 326 Line No.: 3 Column: l 

## Transmission Costs Schedule Page: 326.1 Line No.: 3 Column: l 

## Control Area Charges such as Imbalance, Scheduling, System Control and Dispatch, and Other Fees. Schedule Page: 326.5 Line No.: 6 Column: a 

## Physical Energy Schedule Page: 326.5 Line No.: 6 Column: b 

## Represents nonfirm Schedule Page: 326.5 Line No.: 7 Column: b 

## Represents nonfirm Schedule Page: 326.5 Line No.: 7 Column: l 

## Value of Energy owed to other utilities. Schedule Page: 326.5 Line No.: 8 Column: b 

## Represents nonfirm Schedule Page: 326.5 Line No.: 8 Column: l 

## Change in accrual Schedule Page: 326.5 Line No.: 9 Column: b 

## Represents nonfirm Schedule Page: 326.5 Line No.: 10 Column: b 

## Represents nonfirm Schedule Page: 326.5 Line No.: 11 Column: b 

## Represents nonfirm Schedule Page: 326.5 Line No.: 12 Column: b 

## Represents nonfirm Schedule Page: 326.5 Line No.: 13 Column: b 

## Represents nonfirm Schedule Page: 326.5 Line No.: 14 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 1 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 2 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 3 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 3 Column: l 

## Power financial hedges and options Schedule Page: 326.6 Line No.: 4 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 5 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 5 Column: l Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

## Arizona Corporation Commission approved Power Supply Adjustor Schedule Page: 326.6 Line No.: 6 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 7 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 8 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 9 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 9 Column: l 

## SFAS 133 mark-to-market adjustment Schedule Page: 326.6 Line No.: 10 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 11 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 11 Column: l 

## Purchased Power to ensure reserve requirements are met. Schedule Page: 326.6 Line No.: 12 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 13 Column: b 

## Represents nonfirm Schedule Page: 326.6 Line No.: 14 Column: b 

## Represents nonfirm Schedule Page: 326.7 Line No.: 1 Column: a 

## The amounts shown on pages 326 and 327 are actual amounts purchased from counterparties during the reporting period. The change in estimate amount represents various timing differences between the accrued amounts for purchased power compared to the actual amount. Schedule Page: 326.7 Line No.: 1 Column: b 

## The amounts shown on pages 326 and 327 are actual amounts purchased from counterparties during the reporting period. The change in estimate amount represents various timing differences between the accrued amounts for purchased power compared to the actual amount. Schedule Page: 326.7 Line No.: 1 Column: l 

## Change in estimate between accrual and actual. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Payment By

(c) (b) (a) (d) Statistical

cation Classifi- (Footnote Affiliation) (Including transactions referred to as 'wheeling')

(Company of Public Authority) (Footnote Affiliation) (Company of Public Authority) (Footnote Affiliation) (Company of Public Authority) Energy Received From Energy Delivered To 

### 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.

Ajo Improvement Arizona Public Service Co Ajo Improvement FNO 1 Central Arizona Project Salt River Project Central Arizona Project FNO 2 Navajo Tribal Utility Authority Tucson Electric Power Navajo Tribal Utility Authority FNO 3 Public Service of New Mexico Various Various FNO 4 Southwest Transmission Cooperative Various Various FNO 5Arizona Public Service Various Various FNS 6Arizona Public Service Pinnacle West Capital Corporation Arizona Public Service Company FNS 7Arizona Public Service Arizona Public Service Company Arizona Public Service Company FNS 8Arizona Public Service Various Arizona Public Service Company FNS 9AkChin DOE WAPA Upper AkChin LFP 10 PacifiCorp Not Available Not Available LFP 11 Public Service of New Mexico Not Available Not Available LFP 12 Salt River Project Not Available Not Available LFP 13 Shell Energy North America Not Available Not Available LFP 14 Snowflake White Mountain Power Not Available Not Available LFP 15 Electrical District No. 2 DOE WAPA Lower Electrical District No. 2 OLF 16 Luke AFB Main Base DOE WAPA Upper Luke Air Force Base OLF 17 Marine Corp DOE WAPA Lower Marine Corps Air Station OLF 18 PacifiCorp Not Available Not Available OLF 19 Public Service of New Mexico Public Service of New Mexico Public Service of New Mexico OLF 20 Salt River Project Fringe Salt River Project Salt River Project OLF 21 San Carlos Indian Irrigation San Carlos Indian Irrigation San Carlos Indian Irrigation OLF 22Tucson Electric Power Company Tucson Electric Power Tucson Electric Power OLF 23 Unit B Irrigation & Drain Arizona Power Authority Unit B Irrigation District OLF 24Yuma Cogeneration - Firm Yuma Cogeneration Association San Diego Gas and Electric OLF 25Yuma Irrigation District DOE WAPA Lower Yuma Irrigation District OLF 26Yuma-Mesa DOE WAPA Lower Yuma-Mesa Irrigation District OLF 27AZPS for APS Merchant P-T-P Not Available Not Available SFP 28 Brookfield Energy Marketing L.P. Not Available Not Available SFP 29 Citigroup Energy, Inc. Not Available Not Available SFP 30 Central Arizona Water Conservation Dist. Not Available Not Available SFP 31 EDF Trading North America, LLC Not Available Not Available SFP 32 El Paso Electric Company Not Available Not Available SFP 33 Florida Power & Light (FPL) Not Available Not Available SFP 34

FERC FORM NO. 1 (ED. 12-90) Page 328 TOTALTRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Payment By

(c) (b) (a) (d) Statistical

cation Classifi- (Footnote Affiliation) (Including transactions referred to as 'wheeling')

(Company of Public Authority) (Footnote Affiliation) (Company of Public Authority) (Footnote Affiliation) (Company of Public Authority) Energy Received From Energy Delivered To 

### 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.

Gila River Power Not Available Not Available SFP 1 JP Morgan Ventures Energy Corp. Not Available Not Available SFP 2 Macquarie Cook Power Inc. Not Available Not Available SFP 3 Morgan Stanley Not Available Not Available SFP 4 PacifiCorp Not Available Not Available SFP 5 PacifiCorp Power Marketing (Iberdrola) Not Available Not Available SFP 6 Panda Gila River Not Available Not Available SFP 7 Powerex Not Available Not Available SFP 8 Public Service of New Mexico Not Available Not Available SFP 9 Salt River Project Not Available Not Available SFP 10 Shell Energy North America Not Available Not Available SFP 11 Southern California Edison Co. Not Available Not Available SFP 12 Sun Devil Power Holdings, LLC (Wheelback) Not Available Not Available SFP 13TransAlta Energy Marketing Not Available Not Available SFP 14Tri-State G & T(was Plains G&T) Not Available Not Available SFP 15Tucson Electric Power Company Not Available Not Available SFP 16Western Area Power Admin. (CRSP) Not Available Not Available SFP 17AZPS for APS Merchant P-T-P Not Available Not Available NF 18 Cargill-Alliant, LLC Not Available Not Available NF 19 Central Arizona Water Conservation Dist Not Available Not Available NF 20 Citigroup Energy, Inc. Not Available Not Available NF 21 EDF Trading North America, LLC Not Available Not Available NF 22 El Paso Electric Company Not Available Not Available NF 23 Florida Power & Light Not Available Not Available NF 24JP Morgan Ventures Energy Corp. Not Available Not Available NF 25 Macquarie Cook Power, L.P. Not Available Not Available NF 26 Morgan Stanley Not Available Not Available NF 27 Nevada Power Company Not Available Not Available NF 28 Noble Americas Gas & Power Corp. Not Available Not Available NF 29 Open Access Technology Int'l Not Available Not Available NF 30 PacifiCorp Not Available Not Available NF 31 PacifiCorp Power Marketing (Iberdrola) Not Available Not Available NF 32 Panda Gila River Not Available Not Available NF 33 Powerex Not Available Not Available NF 34

FERC FORM NO. 1 (ED. 12-90) Page 328.1 TOTALTRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Payment By

(c) (b) (a) (d) Statistical

cation Classifi- (Footnote Affiliation) (Including transactions referred to as 'wheeling')

(Company of Public Authority) (Footnote Affiliation) (Company of Public Authority) (Footnote Affiliation) (Company of Public Authority) Energy Received From Energy Delivered To 

### 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.

Public Service of New Mexico Not Available Not Available NF 1 Salt River Project Merchant Not Available Not Available NF 2 Sempra Trading Corp Not Available Not Available NF 3 Shell Energy North America Not Available Not Available NF 4 Southern California Edison Co. Not Available Not Available NF 5Tenaska Power Services Co. Not Available Not Available NF 6TransAlta Energy Marketing Not Available Not Available NF 7Tri-State G & T(was Plains G&T) Not Available Not Available NF 8Tucson Electric Power Company Not Available Not Available NF 9Western Area Power Admin. (CRSP) Not Available Not Available NF 10Yuma Cogeneration Association Yuma Cogeneration Association San Diego Gas and Electric NF 11 Imperial Irrigation District Not Available Not Available OS 12 Salt River Project Schedule Q Pinnacle Peak Ocotillo 230 OS 13 Other Not Available Not Available AD 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

FERC FORM NO. 1 (ED. 12-90) Page 328.2 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (Including transactions reffered to as 'wheeling')

FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other (g) Billing Demand

(MW)

(h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Delivered (j) MegaWatt Hours Designation) 

### 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.

Cholla OATT Ajo Customers 13,708 13,365 1 West Wing Substation OATT Various 330,329 322,071 2 Saguaro OATT Various 42,282 42,159 3 Various OATT Various 353,517 344,679 4 Various OATT Various 24,196 23,591 5 Various OATT Various 6 Various OATT Various 28,100,857 28,100,858 7 Various OATT Various 793,791 742,561 8 Various OATT Various 9 Maricopa Substation OATT AkChin Customer 35,880 32,184 10 Various OATT Various 7 11 Various OATT Various 160 12 Various OATT Various 771 1,771,651 1,734,554 13 Various OATT Various 135 14 Various OATT Various 14 15 Coolidge Substation 245 Casa Grande 8 8 16 Pinnacle Peak Sub 162 Luke Substation 5 18,779 18,234 17 Gila Substation 166 Marine Corps Air Stn 2 10,409 9,992 18 Various 180/183 Various 380 2,714,767 2,714,768 19 Palo Verde 73 Four Corners 130 1,025,590 1,025,590 20 West Phoenix Sub 3 West Phoenix Sub 8,066 7,324 21 Coolidge Substation 202 Westwing Substation 59 54 22 Four Corners 32 Saguaro Plant 100 568,810 568,810 23 Gila Substation 181 District Customer 23 22 24 Riverside Substation 198 North Gila Sub 51 84,206 83,364 25 Gila Substation 39 District Pumps 6,180 5,579 26 Gila Substation 31 Yuma Mesa Load 198 178 27 Various OATT Various 240,448 240,448 28 Various OATT Various 2,249 2,249 29 Various OATT Various 1,187 1,187 30 Various OATT Various 1,276 1,276 31 Various OATT Various 3,938 3,938 32 Various OATT Various 2,172 2,172 33 Various OATT Various 2,214 2,214 34

FERC FORM NO. 1 (ED. 12-90) Page 329 1,755 37,339,290 37,225,864Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (Including transactions reffered to as 'wheeling')

FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other (g) Billing Demand

(MW)

(h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Delivered (j) MegaWatt Hours Designation) 

### 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.

Various OATT Various 2,039 2,039 1 Various OATT Various 605 605 2 Various OATT Various 1,807 1,807 3 Various OATT Various 1,920 1,920 4 Various OATT Various 8,877 8,877 5 Various OATT Various 26 26 6 Various OATT Various 10,998 10,998 7 Various OATT Various 13,584 13,584 8 Various OATT Various 4,381 4,381 9 Various OATT Various 566,802 566,802 10 Various OATT Various 301 301 11 Various OATT Various 5,854 5,854 12 Various OATT Various 1,474 1,474 13 Various OATT Various 666 666 14 Various OATT Various 200 200 15 Various OATT Various 30,487 30,487 16 Various OATT Various 256 256 17 Various OATT Various 797 797 18 Various OATT Various 1,303 1,303 19 Various OATT Various 59 59 20 Various OATT Various 1,419 1,419 21 Various OATT Various 905 905 22 Various OATT Various 3,615 3,615 23 Various OATT Various 453 453 24 Various OATT Various 658 658 25 Various OATT Various 811 811 26 Various OATT Various 11,340 11,340 27 Various OATT Various 275 275 28 Various OATT Various 256 256 29 Various WCRT Various 2,345 2,345 30 Various OATT Various 75,567 75,567 31 Various OATT Various 1,541 1,541 32 Various OATT Various 5,375 5,375 33 Various OATT Various 12,192 12,192 34

FERC FORM NO. 1 (ED. 12-90) Page 329.1 1,755 37,339,290 37,225,864Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (Including transactions reffered to as 'wheeling')

FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other (g) Billing Demand

(MW)

(h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Delivered (j) MegaWatt Hours Designation) 

### 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.

Various OATT Various 4,750 4,750 1 Various OATT Various 260,564 260,564 2 Various OATT Various 150 150 3 Various OATT Various 162 162 4 Various OATT Various 5,002 5,002 5 Various OATT Various 175 175 6 Various OATT Various 22,905 22,905 7 Various OATT Various 12,198 12,198 8 Various OATT Various 100,623 100,623 9 Various OATT Various 310 310 10 Riverside Substation 198 North Gila Sub 6,473 6,408 11 Various OATT Various 12 Pinnacle Peak 3 Ocotillo 230 13 Various OATT Various 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

FERC FORM NO. 1 (ED. 12-90) Page 329.2 1,755 37,339,290 37,225,864Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 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.

127,942 127,942 1 888,442 888,442 2 121,182 121,182 3 1,625,131 1,625,131 4 218,344 218,344 5 11,606,095 11,606,095 6 -11,606,095 -11,606,095 7 -219,062,329 -219,062,329 8 219,062,329 219,062,329 9 -100,439 -100,439 10 217,079 217,079 11 310,113 310,113 12 12,081,683 12,085,051 3,368 13 3,101,133 3,101,133 14 434,159 434,159 15 16 174,005 174,005 17 77,652 77,652 18 547,200 547,200 19 1,415,030 1,416,890 1,860 20 14,595 14,595 21 2,160 2,160 22 1,824,000 1,824,000 23

540 540 24 927,504 927,504 25 26 4,500 4,500 27 2,174,531 2,174,531 28 9,937 9,937 29 6,490 6,490 30 7,756 7,756 31 1,705 28,449 26,744 32 18,009 18,009 33 8,307 8,307 34

FERC FORM NO. 1 (ED. 12-90) Page 330 21,360,890 31,636,457 1,282,324 8,993,243Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 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.

18,201 18,201 1 4,227 4,227 2 7,555 7,555 3 9,928 9,928 4 57,451 57,451 5 267 267 6 59,348 114,626 55,278 7 76,418 76,418 8 31,695 31,695 9 668,623 668,623 10 1,285 1,285 11 31,831 31,831 12 13,343 13,343 13 2,692 2,692 14 15,387 16,115 728 15 9,552 190,156 180,604 16 1,669 1,669 17 4,689 4,689 18 8,191 8,191 19 385 385 20 7,578 7,578 21 4,980 4,980 22 14,728 14,728 23 2,262 2,262 24 3,878 3,878 25 3,782 3,782 26 18,258 78,703 60,445 27 1,770 1,770 28 947 947 29 8,456 8,456 30 365,782 365,782 31 8,903 8,903 32 32,057 32,057 33 67,923 67,923 34

FERC FORM NO. 1 (ED. 12-90) Page 330.1 21,360,890 31,636,457 1,282,324 8,993,243Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 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.

27,529 27,529 1 108,478 1,354,025 1,245,547 2 978 978 3 1,019 1,019 4 29,009 29,009 5 1,054 1,054 6 128,466 128,466 7 5,217 78,598 73,381 8 26,187 591,563 565,376 9 2,021 2,021 10 13,341 13,341 11 52,997 52,997 12 772,910 772,910 13 451,189 451,189 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

FERC FORM NO. 1 (ED. 12-90) Page 330.2 21,360,890 31,636,457 1,282,324 8,993,243

### Schedule Page: 328 Line No.: 6 Column: a 

## APS Merchant Network Integration Services Schedule Page: 328 Line No.: 6 Column: m 

## Intracompany Transmission Schedule Page: 328 Line No.: 7 Column: a 

## APS Merchant Network Integration Services Schedule Page: 328 Line No.: 7 Column: m 

## Intracompany Transmission Schedule Page: 328 Line No.: 8 Column: a 

## Retail Network Integration Services Schedule Page: 328 Line No.: 8 Column: m 

## Intracompany Transmission Schedule Page: 328 Line No.: 9 Column: a 

## Retail Network Integration Services Schedule Page: 328 Line No.: 9 Column: m 

## Intracompany Transmission Schedule Page: 328 Line No.: 10 Column: d 

## Termination date - Not yet determined when this control area will be transferred. Once determined, APS will provide written notice to the transmission customer. Schedule Page: 328 Line No.: 11 Column: d 

## Termination date 7/15/2041 Schedule Page: 328 Line No.: 12 Column: d 

## Can renew annually Schedule Page: 328 Line No.: 13 Column: d 

## Termination date - Not yet determined when this control area will be transferred. Once determined, APS will provide written notice to the transmission customer. Schedule Page: 328 Line No.: 14 Column: d 

## Termination date 10/31/2021 Schedule Page: 328 Line No.: 15 Column: d 

## Termination date 1/1/2028 Schedule Page: 328 Line No.: 16 Column: d 

## Termination date - Indefinite term subject to a three year termination notice by either party. Schedule Page: 328 Line No.: 16 Column: n 

## APS has a Reciprocal Transmission agreement with Electrical District Number Two for power and energy. Any exchange or payback is done in energy, not dollars. Schedule Page: 328 Line No.: 17 Column: d 

## Termination date 10 years or longer with a three year termination notice by either party. Schedule Page: 328 Line No.: 18 Column: d 

## Termination date - Indefinite term subject to a one year termination notice by either party. Schedule Page: 328 Line No.: 19 Column: d 

## Termination date 7/15/2041 Schedule Page: 328 Line No.: 20 Column: d 

## Termination date - Good until terminated with thirty days advance written notice if no service schedule is in effect or scheduled to become effective. Schedule Page: 328 Line No.: 20 Column: m 

## Overrun Schedule Page: 328 Line No.: 21 Column: d Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

## Termination date - Good until terminated with a three year advance written notice. Schedule Page: 328 Line No.: 22 Column: d 

## Termination date - Indefinite term subject to a 90 day termination notice by either party. Schedule Page: 328 Line No.: 23 Column: d 

## Termination date - Goon until terminated by May 31st of any year with three years advance written notice. Schedule Page: 328 Line No.: 24 Column: d 

## Termination date - Indefinite term subject to three year termination notice by either party. Schedule Page: 328 Line No.: 25 Column: d 

## Termination date 12/31/2024 Schedule Page: 328 Line No.: 26 Column: d 

## This contract is effective until the customer notifies APS in writing that service is no longer required. Schedule Page: 328 Line No.: 26 Column: n 

## Yuma Irrigation District is a grandfathered exchange. APS received some assets in exchange for transmission. Schedule Page: 328 Line No.: 27 Column: d 

## Termination date 2/03/1997 - Automatic five year renewal subject to a three year termination notice by either party. Schedule Page: 328 Line No.: 28 Column: a 

## APS Merchant is an affiliate of Arizona Public Service Company Schedule Page: 328.1 Line No.: 18 Column: a 

## APS Merchant is an affiliate of Arizona PUblic Service Company Schedule Page: 328.2 Line No.: 12 Column: d 

## Facility charges Schedule Page: 328.2 Line No.: 12 Column: m 

## Facility charge Schedule Page: 328.2 Line No.: 13 Column: d 

## Schedule Q is for transmission but the cost is based on the plant investment of Pinnacle Peak-Ocotillo 230kV lines and not the current transmission rates. Schedule Page: 328.2 Line No.: 13 Column: m 

## Investment and district annual charge. Schedule Page: 328.2 Line No.: 14 Column: d 

## FERC rate true up, change in estimate, and timing difference. Schedule Page: 328.2 Line No.: 14 Column: m 

## FERC rate true up, change in estimate, and timing difference. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
TRANSMISSION OF ELECTRICITY BY ISO/RTOs Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Payment Received by Statistical (b) (a) (Transmission Owner Name) Classification FERC Rate Schedule or Tariff Number (c) Total Revenue by Rate Schedule or Tarirff (d) Total Revenue (e) 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).

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

Page331

40 TOTAL

FERC FORM NO. 1/3-Q (REV 03-07)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public (d) (c) (a) Authority (Footnote Affiliations) TRANSFER OF ENERGY Magawatt-

hours Received MagawattDelivered

hours EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Charges

($) (e) Energy Charges

(f) ($) Other Charges

($) (g) ($) Total Cost of Transmission (h) (Including transactions referred to as "wheeling") 

### 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data.

Statistical Classification (b) Delivered to Wheeler 1 OS 2,179,220 2,179,220 Arizona Public Service 2 OLF 663,923 663,923 184,649 190,188 Salt River Project 3 OLF 578,332 578,332 160,844 165,670 Salt River Project 4 OLF 257,750 257,750 1,175,113 1,199,790 Salt River Project 5 OLF 242,949 2,389 240,560 112,012 114,365 Salt River Project 6 OLF 143,258 2,904 140,354 38,086 38,886 Salt River Project 7 LFP 1,743,879 221,038 1,522,841 492,474 502,816 Salt River Project 8 OLF 1,817,464 1,835,637 Salt River Project 9 OS 53,500 53,500 Department of Energy 10 OLF 4,939,212 289,303 4,649,909 2,115,862 2,200,495 Department of Energy 11 NF 11,919 698 11,221 5,106 5,310 Department of Energy 12 OLF 7,796 6,096 1,453 247 59 68 San Carlos IIP 13 LFP 1,961,867 203,500 1,758,367 134,675 134,675 Department of Energy 14 LFP 1,104,155 140,980 145,924 817,251 217,019 221,576 Salt River Project 15 LFP 190,083 199,056 Salt River Project 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332 7,195,535 7,014,705 8,597,972 9,339,869 889,640 18,827,481 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public (d) (c) (a) Authority (Footnote Affiliations) TRANSFER OF ENERGY Magawatt-

hours Received MagawattDelivered

hours EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Charges

($) (e) Energy Charges

(f) ($) Other Charges

($) (g) ($) Total Cost of Transmission (h) (Including transactions referred to as "wheeling") 

### 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data.

Statistical Classification (b) Delivered to Wheeler 1 SFP 530 530 Southwest Trans Coop 2 3Received from Wheeler 4 OS 3,595 3,979 Salt River Project 5 LFP 152,359 2,156 150,203 20,277 21,259 Southern Cal Edison 6 OLF 252 270 Electrical District #2 7 OS 122,843 122,843 3,477 3,477 Electrical District #3 8 OLF 16,567 16,567 493 543 Electrical District #4 9 OLF 128,969 58 127,541 1,370 1,272 1,378 Electrical District #5 10 11 Other Charges 12 OS 122,080 9,577 547 111,956 99 99 Bureau of Indian Affair 13 OS 63,980 63,980 Department of Energy 14 11,125 2,721 8,404 1,289 1,289 Tuscon Electric Power 15 SFP 250,637 68,354 182,283 72,623 72,623 Salt River Project 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1 7,195,535 7,014,705 8,597,972 9,339,869 889,640 18,827,481 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Company or Public (d) (c) (a) Authority (Footnote Affiliations) TRANSFER OF ENERGY Magawatt-

hours Received MagawattDelivered

hours EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Charges

($) (e) Energy Charges

(f) ($) Other Charges

($) (g) ($) Total Cost of Transmission (h) (Including transactions referred to as "wheeling") 

### 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data.

Statistical Classification (b) Other Charges 1 OS 25,412 2,207 23,205 3,632 3,632 Public Service of NM 2 OS 133,185 41,217 91,968 Department of Energy 3 OS 1,445,925 1,445,925 Department of Energy 4 OS 417,681 417,681 19,661 19,661 Department of Energy 5 OS 2,048,958 2,048,958 244,059 258,263 Department of Energy 6 7 8 9 10 11 12 13 14 15 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2 7,195,535 7,014,705 8,597,972 9,339,869 889,640 18,827,481 TOTAL

### Schedule Page: 332 Line No.: 2 Column: a 

## Intracompany Transmission Schedule Page: 332 Line No.: 2 Column: b 

## Intracompany Transmission Schedule Page: 332 Line No.: 3 Column: a 

## Chandler Substation Schedule Page: 332 Line No.: 4 Column: a 

## Gilbert Substation Schedule Page: 332 Line No.: 5 Column: a 

## Liberty Substation Schedule Page: 332 Line No.: 6 Column: a 

## Papago Buttes Substation Schedule Page: 332 Line No.: 6 Column: g 

## Facility Charge Schedule Page: 332 Line No.: 7 Column: a 

## Bonneybrook Substation Schedule Page: 332 Line No.: 7 Column: g 

## Facility Charge Schedule Page: 332 Line No.: 8 Column: a 

## Alexander Substation Schedule Page: 332 Line No.: 8 Column: b 

## Termination date - Five years advance written notice, but not prior to 2015 Schedule Page: 332 Line No.: 9 Column: a 

## Westwing Valley Substation Schedule Page: 332 Line No.: 10 Column: a 

## Florence Substation Schedule Page: 332 Line No.: 10 Column: g 

## Impact Study and application fee Schedule Page: 332 Line No.: 11 Column: a 

## Parker/Davis Substation Schedule Page: 332 Line No.: 11 Column: g 

## Ancilliary services/Network Integration Transmission Service Schedule Page: 332 Line No.: 12 Column: a 

## Parker/Davis Substation Schedule Page: 332 Line No.: 12 Column: g 

## Ancilliary services/Network Integration Transmission Service Schedule Page: 332 Line No.: 13 Column: g 

## Facility Charge Schedule Page: 332 Line No.: 14 Column: a 

## Parker/Davis - Sundance Substation Schedule Page: 332 Line No.: 14 Column: g 

## Transmission Request Application Fee / Deposit Schedule Page: 332 Line No.: 15 Column: a 

## Sugarloaf Substation Schedule Page: 332 Line No.: 15 Column: g 

## Facility Charge Schedule Page: 332 Line No.: 16 Column: a Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

## Eastern Mining Area Schedule Page: 332.1 Line No.: 2 Column: a 

## Southwest Transmission Cooperative, Inc. Schedule Page: 332.1 Line No.: 5 Column: b 

## Type of service Transmission Schedule Page: 332.1 Line No.: 6 Column: b 

## Termination date - Indefinite term subject to 3 years written notice by Arizona Public Service or 10 years written notice by Southern California Edison Schedule Page: 332.1 Line No.: 6 Column: g 

## Facility Charge Schedule Page: 332.1 Line No.: 8 Column: b 

## Type of service Transmission Schedule Page: 332.1 Line No.: 10 Column: g 

## Ancillary Services Schedule Page: 332.1 Line No.: 13 Column: b 

## Type of service Transmission Schedule Page: 332.1 Line No.: 13 Column: g 

## Communication Charge Schedule Page: 332.1 Line No.: 14 Column: a 

## Yuma Substation Schedule Page: 332.1 Line No.: 14 Column: b 

## Type of service Transmission Schedule Page: 332.1 Line No.: 14 Column: g 

## Transmission Services Deposit Schedule Page: 332.1 Line No.: 16 Column: g 

## Facility Charge Schedule Page: 332.2 Line No.: 2 Column: a 

## Public Service of New Mexico Schedule Page: 332.2 Line No.: 2 Column: b 

## Type of service Transmission Schedule Page: 332.2 Line No.: 2 Column: g 

## Facility Charge Schedule Page: 332.2 Line No.: 3 Column: a 

## Prescott Substation Schedule Page: 332.2 Line No.: 3 Column: b 

## Type of service Transmission Schedule Page: 332.2 Line No.: 3 Column: g 

## Facility Charge Schedule Page: 332.2 Line No.: 4 Column: a 

## OASIS Schedule Page: 332.2 Line No.: 4 Column: b 

## Type of service Transmission Schedule Page: 332.2 Line No.: 5 Column: a 

## Mead Phoenix Losses Schedule Page: 332.2 Line No.: 5 Column: b 

## Type of service Transmission Schedule Page: 332.2 Line No.: 6 Column: a 

## Salt Lake Power System Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2

### Schedule Page: 332.2 Line No.: 6 Column: b 

## Type of service Transmission Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.3Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC) Arizona Public Service Company X 04/10/2013 2012/Q4

Line Description Amount (b) (a) No. 1,545,370 Industry Association Dues 1 Nuclear Power Research Expenses 2 299,591 Other Experimental and General Research Expenses 3 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4 -150,764 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5 9,036,560 Allocation of Parent Company Costs 6 511,180 Bank Fees 7 -67,719,234 Billed to Others-Services Performed 8 43,132 Communication Service 9 178,539 Materials & Supplies 10 -515,454 Miscellaneous Payroll 11 648,405 Outside Services 12 20,808 Rents/Leases 13 27,547 Transportation Expense 14 19,025 Travel 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

-56,055,295

FERC FORM NO. 1 (ED. 12-94) Page 335

46 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Functional Classification Depreciation (d) (b) (a) Amortization of Total (Except amortization of aquisition adjustments)

A. Summary of Depreciation and Amortization Charges

Expense (Account 403) Limited Term Electric Plant Amortization of Other Electric Plant (Acc 405) (e) (f) 

### 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.

(Account 404) (c) Depreciation Expense for Asset Retirement Costs (Account 403.1) 49,960,802 49,960,802 1Intangible Plant 54,158,882 44,058,222 2,135 2Steam Production Plant 10,098,525 62,057,118 56,948,171 8,711,828 3Nuclear Production Plant -3,602,881 -441,067 -441,067 4Hydraulic Production Plant-Conventional 5Hydraulic Production Plant-Pumped Storage 50,699,038 50,699,038 6Other Production Plant 40,629,643 38,077,426 2,552,217 7Transmission Plant 112,180,707 111,501,398 679,309 8Distribution Plant 9Regional Transmission and Market Operation 34,523,507 27,983,496 6,540,011 10General Plant 11Common Plant-Electric 403,768,630 328,826,684 68,446,302 12TOTAL 6,495,644

RATES Franchises 302 4.00% Software 303 10.00% - 50.00% Misc. Intangibles 303.020.00% Limited Term Land Rights 310 / 350 / 360 / 389 1.67% - 50.00% Office Equipment & Furniture, Small Tools, Garage Equipment, Misc. Equipment 391 / 391.2 / 393 / 394 / 395 / 398 4.17% - 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 B. Basis for Amortization ChargesName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Account No. (c) (b) (a) (d) (e) C. Factors Used in Estimating Depreciation Charges Depreciable Plant Base (In Thousands) Estimated Avg. Service Life Net Salvage (Percent) Applied Depr. rates Mortality Curve Type Average Remaining Life (f) (g) (Percent)

12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50

FERC FORM NO. 1 (REV. 12-03) Page 337Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
REGULATORY COMMISSION EXPENSES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description Assessed by

(c) (b) (a) Total Expense for Expenses of (d) (Furnish name of regulatory commission or body the Regulatory docket or case number and a description of the case) Commission Utility Current Year (b) + (c) Deferred in Account 182.3 at Beginning of Year (e) 

### 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.

ACC/RUCO Expenses 1 Annual Assessment by Arizona Corporation 2Commission (ACC) and Annual Assessment by 3Residential Utility Consumer Office (RUCO) 6,601,264 6,601,264 4Legal and Filing Fees 50,450 50,450 5Consulting Fees 125,859 125,859 6Payroll and Employee Expense 1,986,354 1,986,354 7Est. ACC and RUCO Assessments on Unbilled Rev -62,551 -62,551 8Other 8,348 8,348 9 10FERC Expenses 11 Regulatory Assessment by FERC 2,409,330 2,409,330 12Legal and Filing Fees 973,937 973,937 13Consulting Fees 89,652 89,652 14Payroll and Employee Expenses 184,575 184,575 15Other 10,594 10,594 16 17NRC Expenses 18NRC License Fees 4,508,338 4,508,338 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

FERC FORM NO. 1 (ED. 12-96) Page 350 46TOTAL 13,456,381 3,429,769 16,886,150Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of REGULATORY COMMISSION EXPENSES (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (j) (i) (f) (k) (l) EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR CURRENTLY CHARGED TO Department Account No. (g) Amount (h) Deferred to Account 182.3 Contra Account Amount Deferred in Account 182.3

End of Year 

### 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.

1 2 3 Electric 4 6,601,264 928 Electric 5 50,450 928 Electric 6 125,859 928 Electric 7 1,986,354 928 Electric 8 -62,551 928 Electric 9 8,348 928 10 11 Electric 12 2,409,330 928 Electric 13 973,937 928 Electric 14 89,652 928 Electric 15 184,575 928 Electric 16 10,594 928 17 18 Electric 19 4,508,338 928 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

FERC FORM NO. 1 (ED. 12-96) Page 351 46 16,886,150Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description (b) (a) Classification 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: a. Overhead (1) Generation b. Underground a. hydroelectric (3) Distribution i. Recreation fish and wildlife (4) Regional Transmission and Market Operation ii Other hydroelectric (5) Environment (other than equipment) b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.) c. Internal combustion or gas turbine (7) Total Cost Incurred d. Nuclear B. Electric, R, D & D Performed Externally: e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric f. Siting and heat rejection Power Research Institute (2) Transmission

RENEWABLES A(1)e 1 HPS A(1)e 2 TECH TRANSFER A(1)e 3 4Total 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38

FERC FORM NO. 1 (ED. 12-87) Page 352Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. AMOUNTS CHARGED IN CURRENT YEAR (e) (c) Costs Incurred Internally Current Year Costs Incurred Externally Current Year (d) Account Amount (f) Unamortized Accumulation (g) (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.

12,405 1 573,845 5490 586,250 56,949 2 8,746 5880 65,695 4,947 3 644 9302 5,591 4 74,301 5 583,235 657,536 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38

FERC FORM NO. 1 (ED. 12-87) Page 353Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
DISTRIBUTION OF SALARIES AND WAGES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Classification (c) (b) (a) Direct Payroll Allocation of Total (d) Distribution Payroll charged for Clearing Accounts 

### 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.

Electric 1 Operation 2 119,544,671 Production 3 13,918,391 Transmission 4 Regional Market 5 37,947,924 Distribution 6 29,154,033 Customer Accounts 7 2,738,306 Customer Service and Informational 8 5,281,179 Sales 9 90,491,342 Administrative and General 10 299,075,846 TOTAL Operation (Enter Total of lines 3 thru 10) 11 Maintenance 12 44,638,221 Production 13 3,382,723 Transmission 14 Regional Market 15 25,151,804 Distribution 16 3,413,180 Administrative and General 17 76,585,928 TOTAL Maintenance (Total of lines 13 thru 17) 18 Total Operation and Maintenance 19 164,182,892 Production (Enter Total of lines 3 and 13) 20 17,301,114 Transmission (Enter Total of lines 4 and 14) 21 Regional Market (Enter Total of Lines 5 and 15) 22 63,099,728 Distribution (Enter Total of lines 6 and 16) 23 29,154,033 Customer Accounts (Transcribe from line 7) 24 2,738,306 Customer Service and Informational (Transcribe from line 8) 25 5,281,179 Sales (Transcribe from line 9) 26 93,904,522 Administrative and General (Enter Total of lines 10 and 17) 27 375,661,774 375,661,774 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28 Gas 29 Operation 30 Production-Manufactured Gas 31 Production-Nat. Gas (Including Expl. and Dev.) 32 Other Gas Supply 33 Storage, LNG Terminaling and Processing 34 Transmission 35 Distribution 36 Customer Accounts 37 Customer Service and Informational 38 Sales 39 Administrative and General 40 TOTAL Operation (Enter Total of lines 31 thru 40) 41 Maintenance 42 Production-Manufactured Gas 43 Production-Natural Gas (Including Exploration and Development) 44 Other Gas Supply 45 Storage, LNG Terminaling and Processing 46 Transmission 47

FERC FORM NO. 1 (ED. 12-88) Page 354Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Classification (c) (b) (a) Direct Payroll Allocation of Total (d) Distribution Payroll charged for Clearing Accounts DISTRIBUTION OF SALARIES AND WAGES (Continued)

Distribution 48 Administrative and General 49 TOTAL Maint. (Enter Total of lines 43 thru 49) 50 Total Operation and Maintenance 51 Production-Manufactured Gas (Enter Total of lines 31 and 43) 52 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53 Other Gas Supply (Enter Total of lines 33 and 45) 54 Storage, LNG Terminaling and Processing (Total of lines 31 thru 55 Transmission (Lines 35 and 47) 56 Distribution (Lines 36 and 48) 57 Customer Accounts (Line 37) 58 Customer Service and Informational (Line 38) 59 Sales (Line 39) 60 Administrative and General (Lines 40 and 49) 61 TOTAL Operation and Maint. (Total of lines 52 thru 61) 62 Other Utility Departments 63 Operation and Maintenance 64 375,661,774 375,661,774 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65 Utility Plant 66 Construction (By Utility Departments) 67 134,566,080 134,566,080 Electric Plant 68 Gas Plant 69 Other (provide details in footnote): 70 134,566,080 134,566,080 TOTAL Construction (Total of lines 68 thru 70) 71 Plant Removal (By Utility Departments) 72 Electric Plant 73 Gas Plant 74 Other (provide details in footnote): 75 TOTAL Plant Removal (Total of lines 73 thru 75) 76 Other Accounts (Specify, provide details in footnote): 77 235,582 235,582 Inventory 78 226,810 226,810 Deferred Debits 79 60,237 60,237 Other Revenue 80 2,999,313 2,999,313 Miscellaneous Income Deductions 81 204,601,975 204,601,975 Palo Verde Generating Station 82 28,214,887 28,214,887 Four Corners 83 9,342,440 9,342,440 Cholla-Pacificorp 84 1,874,719 1,874,719 Yucca 85 629,602 629,602 Morgan Pinnacle Peak 86 258,637 258,637 Hoodoo NU 87 653,335 653,335 Panda NU 88 741,324 741,324 Cedar NU 89 1,145,070 1,145,070 Navajo STS 500 KV Line 90 891,290 891,290 All Other Billed to Participants 91 132,474 132,474 Studies 92 584,388 584,388 Street Lights 93 1,480,156 1,480,156 Miscellaneous Billings 94 254,072,239 254,072,239 TOTAL Other Accounts 95 764,300,093 764,300,093 TOTAL SALARIES AND WAGES 96

FERC FORM NO. 1 (ED. 12-88) Page 355

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report

End of

COMMON UTILITY PLANT AND EXPENSES 

### Arizona Public Service Company 

### X 04/10/2013 2012/Q4

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 356Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description of Item(s) Balance at End of (c) (b) (a) Balance at End of AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS

Quarter 1 Quarter 2 Balance at End of Quarter 3 (d) (e) 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.

Balance at End of Year Energy 1Net Purchases (Account 555) 2 5,861,588 611,091 1,433,022 5,115,282 Net Sales (Account 447) 3 ( 15,871,841) ( 4,446,866) ( 6,900,815) ( 12,211,993) Transmission Rights 4Ancillary Services 5Other Items (list separately) 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

( 10,010,253) ( 3,835,775) ( 5,467,793) ( 7,096,711) FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397 46 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
PURCHASES AND SALES OF ANCILLARY SERVICES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Type of Ancillary Service (a) 

### 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.

Number of Units Unit of Measure Dollars (b) (c) (d) Number of Units Unit of Measure Dollars (e) (f) (g) Usage - Related Billing Determinant Usage - Related Billing Determinant Amount Purchased for the Year Amount Sold for the Year

2,063,701 mWh 16,465,626 1,839,819 mWh 15,279,690 Scheduling, System Control and Dispatch 1Reactive Supply and Voltage 2 6,963,348 mWh 15,038,445 6,957,180 mWh 15,038,445 Regulation and Frequency Response 3 -163,501 mWh -4,067 Energy Imbalance 4 16,098,362 mWh 15,038,445 16,091,429 mWh 15,038,445 Operating Reserve - Spinning 5 2,035,315 mWh 15,038,445 2,035,102 mWh 15,038,445 Operating Reserve - Supplement 6Other 7 26,997,225 61,576,894 26,923,530 60,395,025 Total (Lines 1 thru 7) 8

FERC FORM NO. 1 (New 2-04) Page 398Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MONTHLY TRANSMISSION SYSTEM PEAK LOAD Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Monthly Peak MW - Total

(c) (b) (a) Month NAME OF SYSTEM: Day of Monthly

Peak (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.

(d) Hour of Monthly Peak (e) Firm Network Service for Self
(f) Firm Network Service for

Others (g) Long-Term Firm

Point-to-point Reservations (h)Other LongTerm Firm

Service (i) Short-Term Firm

Point-to-point Reservation (j) Other Service

160 350 451 107 4,149 800 13 5,227 January 1 160 281 451 101 3,863 800 15 4,866 February 2 160 50 451 100 3,609 800 8 4,380 March 3 480 681 1,353 308 11,621 14,473 Total for Quarter 1 4 160 213 451 101 4,959 1700 22 5,893 April 5 160 191 455 107 5,978 1700 31 6,901 May 6 160 75 455 112 6,834 1700 27 7,646 June 7 480 479 1,361 320 17,771 20,440 Total for Quarter 2 8 1,268 100 845 116 6,799 1700 10 9,137 July 9 318 102 845 108 7,333 1700 8 8,716 August 10 318 2 459 102 6,143 1600 2 7,030 September 11 1,904 204 2,149 326 20,275 24,883 Total for Quarter 3 12 318 261 457 105 5,430 1700 1 6,579 October 13 318 351 455 58 3,723 1900 5 4,915 November 14 318 280 455 108 4,054 800 20 5,226 December 15 954 892 1,367 271 13,207 16,720 Total for Quarter 4 16

3,818 2,256 6,230 1,225 62,874 76,516 Total Year to Date/Year 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Monthly Peak MW - Total

(c) (b) (a) Month NAME OF SYSTEM: Day of Monthly

Peak (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).

(d) Hour of Monthly Peak (e) Imports into ISO/RTO
(f) Exports from

ISO/RTO
(g) Through and Out Service
(h) Network Service Usage
(i) Point-to-Point Service Usage
(j) Total Usage

January 1 February 2March 3Total for Quarter 1 4April 5May 6June 7Total for Quarter 2 8July 9August 10September 11Total for Quarter 3 12October 13November 14December 15Total for Quarter 4 16Total Year to Date/Year 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400aName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
ELECTRIC ENERGY ACCOUNT Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (a) (b) (a) (b) Line No. MegaWatt Hours Item MegaWatt Hours Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.

SOURCES OF ENERGY 1Generation (Excluding Station Use): 2 10,947,566

Steam 3 9,292,770

Nuclear 4Hydro-Conventional 5Hydro-Pumped Storage 6 7,395,396

Other 7Less Energy for Pumping 8 27,635,732

Net Generation (Enter Total of lines 3 through 8) 9

7,021,543

Purchases 10Power Exchanges: 11 767,870 Received 12 807,241 Delivered 13 -39,371 Net Exchanges (Line 12 minus line 13) 14Transmission For Other (Wheeling) 15 37,339,290 Received 16 37,225,864 Delivered 17 113,426 Net Transmission for Other (Line 16 minus line 17) 18

-1,538 Transmission By Others Losses 19 34,729,792 TOTAL (Enter Total of lines 9, 10, 14, 18 and 19) 20 DISPOSITION OF ENERGY 21 28,154,136 Sales to Ultimate Consumers (Including Interdepartmental Sales) 22

754,164 Requirements Sales for Resale (See instruction 4, page 311.) 23

3,588,763 Non-Requirements Sales for Resale (See instruction 4, page 311.) 24

Energy Furnished Without Charge 25 60,706 Energy Used by the Company (Electric Dept Only, Excluding Station Use) 26

2,172,023 Total Energy Losses 27 34,729,792 TOTAL (Enter Total of Lines 22 Through 27) (MUST EQUAL LINE 20) 28

FERC FORM NO. 1 (ED. 12-90) Page 401a(d) Day of Month Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MONTHLY PEAKS AND OUTPUT Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Total Monthly Energy Megawatts (c) (b) (a) Hour (e) MONTHLY PEAK Month NAME OF SYSTEM: Monthly Non-Requirments Sales for Resale & Associated Losses (See Instr. 4) 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).

(f) January 29 13 4,113 295,381 800 2,612,017 February 30 15 3,813 391,498 800 2,416,865 March 31 8 3,582 284,960 800 2,291,498 April 32 22 4,912 171,831 1700 2,219,452 May 33 31 5,897 339,279 1700 2,773,771 June 34 27 6,750 229,531 1700 3,095,058 July 35 10 6,696 329,520 1700 3,301,772 August 36 8 7,207 333,550 1700 3,467,365 September 37 2 6,036 531,567 1600 3,175,259 October 38 1 5,339 475,133 1700 3,558,190 November 39 5 3,680 211,111 1900 2,749,584 December 40 20 4,005 230,967 800 3,068,961

FERC FORM NO. 1 (ED. 12-90) Page 401b 41 TOTAL 34,729,792 3,824,328

### Schedule Page: 401 Line No.: 34 Column: d 

## Revised due to NSTS and SCE losses correction Schedule Page: 401 Line No.: 35 Column: d 

## Revised due to NSTS and SCE losses correction Schedule Page: 401 Line No.: 36 Column: d 

## Revised due to NSTS and SCE losses correction Schedule Page: 401 Line No.: 37 Column: d 

## Revised due to NSTS and SCE losses correction Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Cholla 1 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Steam

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Over 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1962 3Year Originally Constructed 1981 4Year Last Unit was Installed 0.00 113.60 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 120 6Net Peak Demand on Plant - MW (60 minutes) 0 8441 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 0 116 9When Not Limited by Condenser Water 0 116 10When Limited by Condenser Water 0 52 11 Average Number of Employees 0 830109058 12Net Generation, Exclusive of Plant Use - KWh 0 895453 13Cost of Plant: Land and Land Rights 0 13307829 14Structures and Improvements 0 131165663 15Equipment Costs 0 0 16Asset Retirement Costs 0 145368945 17Total Cost 0 1279.6562 18Cost per KW of Installed Capacity (line 17/5) Including 0 1288140 19Production Expenses: Oper, Supv, & Engr 0 17812415 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 2648737 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 538923 25Electric Expenses 0 1049070 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 1262098 29Maintenance Supervision and Engineering 0 416384 30Maintenance of Structures 0 1974906 31 Maintenance of Boiler (or reactor) Plant 0 200680 32Maintenance of Electric Plant 0 834292 33Maintenance of Misc Steam (or Nuclear) Plant 0 28025645 34Total Production Expenses 0.0000 0.0338 35Expenses per Net KWh Coal Oil Gas Total 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Tons Bbls MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 470500 0 4241 00 0 38Quantity (Units) of Fuel Burned 9238 0 843693 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 36.935 0.000 5.727 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 37.801 0.000 6.783 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 2.046 0.000 8.039 2.048 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.021 0.000 0.084 0.021 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 10475.908 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402Four Corners 1 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Steam

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Over 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1963 3Year Originally Constructed 1970 4Year Last Unit was Installed 190.10 0.00 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 174 0 6Net Peak Demand on Plant - MW (60 minutes) 7147 0 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 170 0 9When Not Limited by Condenser Water 170 0 10When Limited by Condenser Water 52 0 11 Average Number of Employees 1062437484 0 12Net Generation, Exclusive of Plant Use - KWh 12746 0 13Cost of Plant: Land and Land Rights 19711280 0 14Structures and Improvements 94828727 0 15Equipment Costs 20640912 0 16Asset Retirement Costs 135193665 0 17Total Cost 711.1713 0 18Cost per KW of Installed Capacity (line 17/5) Including 488042 0 19Production Expenses: Oper, Supv, & Engr 23560355 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 2791988 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 459202 0 25Electric Expenses 2210675 0 26Misc Steam (or Nuclear) Power Expenses 127366 0 27Rents 0 0 28Allowances 546090 0 29Maintenance Supervision and Engineering 222221 0 30Maintenance of Structures 2851388 0 31 Maintenance of Boiler (or reactor) Plant 194891 0 32Maintenance of Electric Plant 1230884 0 33Maintenance of Misc Steam (or Nuclear) Plant 34683102 0 34Total Production Expenses 0.0326 0.0000 35Expenses per Net KWh total Coal Gas Total 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Tons MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 675960 90700 0 38Quantity (Units) of Fuel Burned 00 0 8751 1008732 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 32.800 5.563 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 33.947 6.767 0.000 41 Average Cost of Fuel per Unit Burned 2.031 0.000 0.000 1.940 6.708 1.976 42Average Cost of Fuel Burned per Million BTU 0.021 0.000 0.000 0.022 0.075 0.022 43Average Cost of Fuel Burned per KWh Net Gen 10423.891 0.000 0.000 0.000 0.000 11221.209 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.1Ocotillo 1 Four Corners 5 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Steam Steam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Over 50% Outdoor Over 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1960 1969 3Year Originally Constructed 1960 1970 4Year Last Unit was Installed 113.60 122.72 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 104 119 6Net Peak Demand on Plant - MW (60 minutes) 834 7306 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 110 116 9When Not Limited by Condenser Water 110 116 10When Limited by Condenser Water 10 21 11 Average Number of Employees 40416000 712468716 12Net Generation, Exclusive of Plant Use - KWh 154669 10042 13Cost of Plant: Land and Land Rights 2403680 6322010 14Structures and Improvements 31073748 93604943 15Equipment Costs 0 1281645 16Asset Retirement Costs 33632097 101218640 17Total Cost 296.0572 824.7934 18Cost per KW of Installed Capacity (line 17/5) Including 0 163233 19Production Expenses: Oper, Supv, & Engr 1741104 14297959 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 132822 1554745 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 786324 106330 25Electric Expenses 221813 538284 26Misc Steam (or Nuclear) Power Expenses 0 75695 27Rents 0 0 28Allowances 0 187790 29Maintenance Supervision and Engineering 228100 97031 30Maintenance of Structures 122780 2201115 31 Maintenance of Boiler (or reactor) Plant 388448 586049 32Maintenance of Electric Plant 197962 683118 33Maintenance of Misc Steam (or Nuclear) Plant 3819353 20491349 34Total Production Expenses 0.0945 0.0288 35Expenses per Net KWh Coal Gas Total Gas Total 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Tons MCF MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 404970 15380 0 477510 0 0 38Quantity (Units) of Fuel Burned 9155 1009558 0 1021082 0 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 33.859 5.908 0.000 2.997 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 35.033 7.188 0.000 3.646 0.000 0.000 41 Average Cost of Fuel per Unit Burned 1.913 7.120 1.924 3.571 3.571 0.000 42Average Cost of Fuel Burned per Million BTU 0.020 0.074 0.020 0.043 0.043 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 10429.785 0.000 12063.960 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.2Yucca 1 Navajo Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Comb. Turbine Steam Units 1,2,3 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Over 50% Outdoor Over 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1971 1974 3Year Originally Constructed 2008 1976 4Year Last Unit was Installed 23.60 337.34 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 21 319 6Net Peak Demand on Plant - MW (60 minutes) 279 8784 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 19 315 9When Not Limited by Condenser Water 0 315 10When Limited by Condenser Water 1 0 11 Average Number of Employees 3602000 1637996004 12Net Generation, Exclusive of Plant Use - KWh 0 25111 13Cost of Plant: Land and Land Rights 214413 30481164 14Structures and Improvements 2843435 235774584 15Equipment Costs 0 1865912 16Asset Retirement Costs 3057848 268146771 17Total Cost 129.5698 794.8858 18Cost per KW of Installed Capacity (line 17/5) Including 29887 3058704 19Production Expenses: Oper, Supv, & Engr 372523 39486174 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 1946285 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 42494 550354 25Electric Expenses 23227 2584999 26Misc Steam (or Nuclear) Power Expenses 0 85176 27Rents 0 0 28Allowances 0 1211907 29Maintenance Supervision and Engineering 365 243128 30Maintenance of Structures 0 5139557 31 Maintenance of Boiler (or reactor) Plant 100732 1151156 32Maintenance of Electric Plant 164 716227 33Maintenance of Misc Steam (or Nuclear) Plant 569392 56173667 34Total Production Expenses 0.1581 0.0343 35Expenses per Net KWh Coal Oil Total Oil Gas Total 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Tons Bbls Bbls MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 783043 2902 0 0 59200 0 38Quantity (Units) of Fuel Burned 10763 137147 0 0 1018209 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 49.310 135.158 0.000 0.000 2.933 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 49.693 198.048 0.000 0.000 6.293 0.000 41 Average Cost of Fuel per Unit Burned 2.309 34.382 2.340 0.000 6.180 6.180 42Average Cost of Fuel Burned per Million BTU 0.024 0.354 0.024 0.000 0.103 0.103 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 10300.449 0.000 0.000 16734.592 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.3Yucca 6 Yucca 5 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Comb. Turbine Comb. Turbine 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Over 50% Outdoor Over 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 2007 2007 3Year Originally Constructed 2008 2008 4Year Last Unit was Installed 60.50 60.50 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 48 48 6Net Peak Demand on Plant - MW (60 minutes) 1668 1550 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 48 48 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 2 3 11 Average Number of Employees 59993000 54593000 12Net Generation, Exclusive of Plant Use - KWh 0 0 13Cost of Plant: Land and Land Rights 862522 869473 14Structures and Improvements 35568803 35986928 15Equipment Costs 0 0 16Asset Retirement Costs 36431325 36856401 17Total Cost 602.1707 609.1967 18Cost per KW of Installed Capacity (line 17/5) Including 0 1645167 19Production Expenses: Oper, Supv, & Engr 3851379 3567452 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 23520 23897 25Electric Expenses 285483 112551 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 39 29Maintenance Supervision and Engineering 6078 5531 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 172965 571645 32Maintenance of Electric Plant 112061 197670 33Maintenance of Misc Steam (or Nuclear) Plant 4451486 6123952 34Total Production Expenses 0.0742 0.1122 35Expenses per Net KWh Oil Gas Total Oil Gas Total 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Bbls MCF Bbls MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 0 561420 0 0 609530 0 38Quantity (Units) of Fuel Burned 0 1015477 0 0 1015750 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 2.962 0.000 0.000 2.945 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 6.354 0.000 0.000 6.319 0.000 41 Average Cost of Fuel per Unit Burned 0.000 6.257 6.257 0.000 6.221 6.221 42Average Cost of Fuel Burned per Million BTU 0.000 0.065 0.065 0.000 0.064 0.064 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 10442.896 0.000 0.000 10320.037 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.4Ocotillo 1 Saguaro 3 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Comb. Turbine Comb. Turbine 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Over 50% Outdoor Over 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1972 2002 3Year Originally Constructed 1973 2002 4Year Last Unit was Installed 53.10 78.30 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 55 83 6Net Peak Demand on Plant - MW (60 minutes) 97 307 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 55 79 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 2 0 11 Average Number of Employees 2357000 14574000 12Net Generation, Exclusive of Plant Use - KWh 0 0 13Cost of Plant: Land and Land Rights 194358 560621 14Structures and Improvements 10124086 28973193 15Equipment Costs 0 0 16Asset Retirement Costs 10318444 29533814 17Total Cost 194.3210 377.1879 18Cost per KW of Installed Capacity (line 17/5) Including 0 0 19Production Expenses: Oper, Supv, & Engr 278340 1173821 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 187741 0 25Electric Expenses 42218 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 28277 18331 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 1044217 251022 32Maintenance of Electric Plant 8430 540 33Maintenance of Misc Steam (or Nuclear) Plant 1589223 1443714 34Total Production Expenses 0.6743 0.0991 35Expenses per Net KWh Gas Total Gas Total 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) MCF MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 185190 0 0 46490 0 0 38Quantity (Units) of Fuel Burned 1033290 0 0 1019337 0 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 2.954 0.000 0.000 2.791 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 6.338 0.000 0.000 5.987 0.000 0.000 41 Average Cost of Fuel per Unit Burned 6.134 6.134 0.000 5.874 5.874 0.000 42Average Cost of Fuel Burned per Million BTU 0.081 0.081 0.000 0.118 0.118 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 13129.889 0.000 0.000 20105.643 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.5West Phoenix 1 Sundance Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Combined Cycle Comb. Turbine 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Over 50% Outdoor Over 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1976 2002 3Year Originally Constructed 2003 2002 4Year Last Unit was Installed 132.00 605.00 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 170 443 6Net Peak Demand on Plant - MW (60 minutes) 1745 1399 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 88 420 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 2 17 11 Average Number of Employees 76032120 134675000 12Net Generation, Exclusive of Plant Use - KWh 3885 681252 13Cost of Plant: Land and Land Rights 2558391 12686199 14Structures and Improvements 43256969 264063531 15Equipment Costs 0 0 16Asset Retirement Costs 45819245 277430982 17Total Cost 347.1155 458.5636 18Cost per KW of Installed Capacity (line 17/5) Including 83929 537 19Production Expenses: Oper, Supv, & Engr 6122691 8212742 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 1641630 25Electric Expenses 0 1413326 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 484 0 29Maintenance Supervision and Engineering 6936 253995 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 1400847 2436535 32Maintenance of Electric Plant 123081 28566 33Maintenance of Misc Steam (or Nuclear) Plant 7737968 13987331 34Total Production Expenses 0.1018 0.1039 35Expenses per Net KWh Gas Total Gas Total 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) MCF MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 1370040 0 0 843760 0 0 38Quantity (Units) of Fuel Burned 1011435 0 0 1018997 0 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 2.794 0.000 0.000 3.382 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 5.995 0.000 0.000 7.256 0.000 0.000 41 Average Cost of Fuel per Unit Burned 5.927 5.927 0.000 7.121 7.121 0.000 42Average Cost of Fuel Burned per Million BTU 0.061 0.061 0.000 0.081 0.081 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 10289.259 0.000 0.000 11308.234 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.6Redhawk 1 West Phoenix 5 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Combined Cycle Combined Cycle 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Over 50% Outdoor Over 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 2002 2003 3Year Originally Constructed 2002 2003 4Year Last Unit was Installed 573.10 569.60 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 546 536 6Net Peak Demand on Plant - MW (60 minutes) 6856 6155 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 492 506 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 19 35 11 Average Number of Employees 2244065000 1963239000 12Net Generation, Exclusive of Plant Use - KWh 1107373 18896 13Cost of Plant: Land and Land Rights 12102894 13538246 14Structures and Improvements 251963343 262222835 15Equipment Costs 0 0 16Asset Retirement Costs 265173610 275779977 17Total Cost 462.7004 484.1643 18Cost per KW of Installed Capacity (line 17/5) Including 0 2167141 19Production Expenses: Oper, Supv, & Engr 101618301 89388355 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 1800377 2234916 25Electric Expenses 2614505 2910613 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 212783 5044 29Maintenance Supervision and Engineering 156406 225973 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 4429149 5482408 32Maintenance of Electric Plant 1495314 725473 33Maintenance of Misc Steam (or Nuclear) Plant 112326835 103139923 34Total Production Expenses 0.0501 0.0525 35Expenses per Net KWh Gas Total Gas Total 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) MCF MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 14790940 0 0 16153590 0 0 38Quantity (Units) of Fuel Burned 1018191 0 0 1017351 0 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 3.945 0.000 0.000 2.932 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 8.463 0.000 0.000 6.291 0.000 0.000 41 Average Cost of Fuel per Unit Burned 8.311 8.311 0.000 6.184 6.184 0.000 42Average Cost of Fuel Burned per Million BTU 0.064 0.064 0.000 0.045 0.045 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 7668.909 0.000 0.000 7325.597 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.7Palo Verde 3 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

Nuclear

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Under 50% Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1988 3Year Originally Constructed 1988 4Year Last Unit was Installed 0.00 408.33 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 398 6Net Peak Demand on Plant - MW (60 minutes) 0 7798 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 0 382 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 211 11 Average Number of Employees 0 2937257125 12Net Generation, Exclusive of Plant Use - KWh 0 1642236 13Cost of Plant: Land and Land Rights 0 290284551 14Structures and Improvements 0 732644411 15Equipment Costs 0 -8312963 16Asset Retirement Costs 0 1016258235 17Total Cost 0 2488.8160 18Cost per KW of Installed Capacity (line 17/5) Including 0 8352554 19Production Expenses: Oper, Supv, & Engr 0 26210259 20Fuel 0 3654858 21 Coolants and Water (Nuclear Plants Only) 0 3890274 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 3111482 25Electric Expenses 0 11168026 26Misc Steam (or Nuclear) Power Expenses 0 15222412 27Rents 0 0 28Allowances 0 3733107 29Maintenance Supervision and Engineering 0 716136 30Maintenance of Structures 0 4640017 31 Maintenance of Boiler (or reactor) Plant 0 5722578 32Maintenance of Electric Plant 0 1574827 33Maintenance of Misc Steam (or Nuclear) Plant 0 87996530 34Total Production Expenses 0.0000 0.0300 35Expenses per Net KWh Nuclear 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Kg Uranium 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 456 0 0 00 0 38Quantity (Units) of Fuel Burned 66707 0 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 2937.399 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 57453.439 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.861 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.009 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 10359.961 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.8Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: 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.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6Net Peak Demand on Plant - MW (60 minutes) 0 0 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12Net Generation, Exclusive of Plant Use - KWh 0 0 13Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0 0 18Cost per KW of Installed Capacity (line 17/5) Including 0 0 19Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.99. 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.

Cholla 3 Cholla 2 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

Steam Steam 1 Over 50% Outdoor Over 50% Outdoor 2 1980 1978 3 1981 1981 4 312.30 288.90 0.00 5 275 272 0 6 7542 8468 0 7 0 0 0 8 271 260 0 9 271 260 0 10 56 60 0 11 1638310135 1812482722 0 12 2488397 1964889 0 13 34728979 25793191 0 14 366822956 291280738 0 15 0 0 0 16 404040332 319038818 0 17 1293.7571 1104.3227 0 18 1340357 1383012 0 19 34686565 40078919 0 20 0 0 0 21 4074320 4572444 0 22 0 0 0 23 0 0 0 24 429753 458600 0 25 1454167 1430071 0 26 0 0 0 27 0 0 0 28 1533628 1571931 0 29 217035 376989 0 30 5812222 4007070 0 31 3695382 396614 0 32 3004376 1110577 0 33 56247805 55386227 0 34 0.0343 0.0306 0.0000 35 Coal Oil Gas Coal Oil Gas Total 36 Tons Bbls MCF Tons Bbls MCF 37 1075015 1343 0 926089 1542 0 0 0 0 38 9220 130770 0 9215 159034 0 0 0 0 39 36.389 112.675 0.000 36.555 153.294 0.000 0.000 0.000 0.000 40 37.133 141.820 0.000 37.192 186.236 0.000 0.000 0.000 0.000 41 2.014 25.822 0.000 2.018 27.882 0.000 2.021 0.000 0.000 42 0.022 0.283 0.000 0.021 0.291 0.000 0.022 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 10941.575 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page4039. 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.

Four Corners 4 Four Corners 3 Four Corners 2 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

Steam Steam Steam 1 Over 50% Outdoor Over 50% Outdoor Over 50% Outdoor 2 1969 1963 1964 3 1970 1970 1970 4 122.72 190.10 253.40 5 119 175 225 6 7566 6907 7193 7 0 0 0 8 116 170 220 9 116 170 220 10 29 61 50 11 696659764 1071680867 1415151700 12 8057 15265 17936 13 8443688 17719039 18719696 14 71483054 123532875 144754360 15 1274468 20640912 26745008 16 81209267 161908091 190237000 17 661.7444 851.6996 750.7380 18 197266 287744 715113 19 13966000 23569867 31620793 20 0 0 0 21 1571846 2790384 2795760 22 0 0 0 23 0 0 0 24 106330 459040 459161 25 570778 2073094 2009602 26 75695 127366 127366 27 0 0 0 28 172854 640541 761635 29 68676 202557 223836 30 1620021 4532374 5020985 31 324717 1175837 876630 32 572786 1609083 1733293 33 19246969 37467887 46344174 34 0.0276 0.0350 0.0327 35 Coal Gas Total Coal Gas Total Coal Gas Total 36 Tons MCF Tons MCF Tons MCF 37 678280 68350 0 398200 23160 0 869040 115760 0 38 8748 1009305 0 9202 1008895 0 8752 1011757 0 39 32.913 5.657 0.000 33.607 5.652 0.000 34.467 6.314 0.000 40 34.056 6.882 0.000 34.673 6.876 0.000 35.363 7.681 0.000 41 1.947 6.818 1.975 1.884 6.815 1.900 2.020 7.592 2.063 42 0.022 0.076 0.022 0.020 0.072 0.020 0.022 0.082 0.022 43 0.000 0.000 11137.570 0.000 0.000 10553.374 0.000 0.000 10831.602 44

FERC FORM NO. 1 (REV. 12-03) Page403.19. 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. Saguaro 2 Saguaro 1 Ocotillo 2 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

Steam Steam Steam 1 Over 50% Outdoor Over 50% Outdoor Over 50% Outdoor 2 1955 1960 1954 3 1955 1960 1955 4 125.00 113.60 125.00 5 0 108 0 6 0 608 0 7 0 0 0 8 100 110 110 9 100 110 110 10 0 10 1 11 0 29854000 0 12 44461 136915 7886 13 2015847 2388266 1816308 14 27179540 27135560 25932243 15 0 0 0 16 29239848 29660741 27756437 17 233.9188 261.0981 222.0515 18 26524 0 26524 19 0 1211197 162 20 0 0 0 21 0 98111 0 22 0 0 0 23 0 0 0 24 1016 786319 1016 25 0 163846 201894 26 0 0 0 27 0 0 0 28 1225 0 1225 29 10295 0 10295 30 35623 150925 35623 31 12788 441152 12394 32 70875 146228 111065 33 158346 2997778 400198 34 0.0000 0.1004 0.0000 35 Gas Total Gas Total Gas Total 36 MCF 37 362520 0 0 000 0 0 0 38 1020700 0 0 000 0 0 0 39 2.746 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 3.341 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 3.273 3.273 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.041 0.041 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 12394.453 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.29. 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.

Yucca 4 Yucca 3 Yucca 2 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

Comb. Turbine Comb. Turbine Comb. Turbine 1 Over 50% Outdoor Over 50% Outdoor Over 50% Outdoor 2 1974 1971 1973 3 2008 2008 2008 4 72.40 23.60 72.40 5 50 21 52 6 40 272 875 7 0 0 0 8 54 19 55 9 0 0 0 10 1 0 1 11 612000 3480000 27260000 12 0 0 0 13 172109 85001 254014 14 7627523 2484030 11072328 15 0 0 0 16 7799632 2569031 11326342 17 107.7297 108.8572 156.4412 18 0 0 29887 19 0 370260 3299047 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 954 1241 17829 25 0 13575 22356 26 0 0 0 27 0 0 0 28 0 0 0 29 62 353 2762 30 0 0 0 31 23865 23459 167235 32 0 949 12319 33 24881 409837 3551435 34 0.0407 0.1178 0.1303 35 Oil Gas Total Oil Gas Total Oil Gas Total 36 Bbls MCF Bbls MCF Bbls MCF 37 0 56510 0 2217 0 0 443 419850 0 38 0 1018032 0 138221 0 0 138260 1016403 0 39 0.000 3.054 0.000 70.163 0.000 0.000 70.163 3.220 0.000 40 0.000 6.552 0.000 149.939 0.000 0.000 149.939 6.908 0.000 41 0.000 6.436 6.436 25.828 0.000 25.828 25.821 6.796 6.910 42 0.000 0.106 0.106 0.543 0.000 0.543 0.407 0.107 0.109 43 0.000 0.000 16531.322 0.000 0.000 21029.867 0.000 0.000 15748.696 44

FERC FORM NO. 1 (REV. 12-03) Page403.39. 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. Saguaro 2 Saguaro 1 Douglas Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

Comb. Turbine Comb. Turbine Comb. Turbine 1 Over 50% Outdoor Over 50% Outdoor Over 50% Outdoor 2 1973 1972 1972 3 2002 1972 2002 4 53.10 26.10 53.10 5 50 17 54 6 51 11 50 7 0 0 0 8 55 16 55 9 0 0 0 10 0 0 0 11 1382000 131000 651000 12 0 9557 0 13 1039357 103679 713925 14 9669073 2177814 8619612 15 0 0 0 16 10708430 2291050 9333537 17 201.6653 87.7797 175.7728 18 0 0 0 19 247619 54233 33043 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 62 0 25 67056 858 67056 26 0 0 0 27 0 0 0 28 0 0 0 29 1738 0 819 30 0 0 0 31 1324015 28246 50378 32 183 16095 139429 33 1640611 99494 290725 34 1.1871 0.7595 0.4466 35 Oil Total Gas Total Gas Total 36 Bbls MCF MCF 37 704 0 0 26680 0 0 18980 0 0 38 138602 0 0 1034445 0 0 1028451 0 0 39 56.805 0.000 0.000 4.326 0.000 0.000 0.811 0.000 0.000 40 77.036 0.000 0.000 9.281 0.000 0.000 1.741 0.000 0.000 41 13.234 13.234 0.000 8.972 8.972 0.000 1.693 1.693 0.000 42 0.414 0.414 0.000 0.179 0.179 0.000 0.051 0.051 0.000 43 0.000 31283.847 0.000 0.000 19970.333 0.000 0.000 29984.639 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.49. 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.

West Phoenix 2 West Phoenix 1 Ocotillo 2 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

Comb. Turbine Comb. Turbine Comb. Turbine 1 Over 50% Outdoor Over 50% Outdoor Over 50% Outdoor 2 1973 1973 1972 3 1973 1973 1973 4 53.10 53.10 53.10 5 22 53 50 6 2 65 49 7 0 0 0 8 55 55 55 9 0 0 0 10 1 2 1 11 46000 1756000 1165000 12 0 0 6294 13 127593 547191 786747 14 7661752 15919691 18422932 15 0 0 0 16 7789345 16466882 19215973 17 146.6920 310.1108 361.8827 18 4862 0 123142 19 4796 230119 162741 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 3086 189197 78168 25 65 31185 1637 26 0 0 0 27 0 0 0 28 0 0 0 29 74110 20887 0 30 0 0 0 31 1123205 2189832 2499856 32 0 0 21472 33 1210124 2661220 2887016 34 26.3070 1.5155 2.4781 35 Gas Total Gas Total Gas Total 36 MCF MCF MCF 37 35920 0 0 1090 0 0 68600 0 0 38 1024749 0 0 1009174 0 0 1022507 0 0 39 2.986 0.000 0.000 2.051 0.000 0.000 1.106 0.000 0.000 40 6.406 0.000 0.000 4.400 0.000 0.000 2.372 0.000 0.000 41 6.252 6.252 0.000 4.360 4.360 0.000 2.320 2.320 0.000 42 0.131 0.131 0.000 0.104 0.104 0.000 0.140 0.140 0.000 43 0.000 20961.845 0.000 0.000 23913.043 0.000 0.000 60209.442 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.59. 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.

West Phoenix 4 West Phoenix 3 West Phoenix 2 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

Combined Cycle Combined Cycle Combined Cycle 1 Over 50% Outdoor Over 50% Outdoor Over 50% Outdoor 2 2001 1976 1976 3 2003 2003 2003 4 135.60 132.00 132.00 5 105 0 79 6 1220 1522 1192 7 0 0 0 8 117 88 88 9 0 0 0 10 8 1 5 11 96940000 65046570 68734020 12 32909 3866 4590 13 5405861 2550695 4370537 14 77730957 42322786 50067655 15 0 0 0 16 83169727 44877347 54442782 17 613.3461 339.9799 412.4453 18 512398 71802 75873 19 5374887 5306431 4906711 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 359811 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 234 0 273 29 8844 5934 6271 30 0 0 0 31 694511 302930 625520 32 373091 366001 125466 33 7323776 6053098 5740114 34 0.0755 0.0931 0.0835 35 Gas Total Gas Total Gas Total 36 MCF MCF MCF 37 721150 0 0 954080 0 0 688840 0 0 38 1018956 0 0 1019920 0 0 1019600 0 0 39 3.430 0.000 0.000 2.626 0.000 0.000 3.320 0.000 0.000 40 7.358 0.000 0.000 5.634 0.000 0.000 7.123 0.000 0.000 41 7.221 7.221 0.000 5.524 5.524 0.000 6.986 6.986 0.000 42 0.082 0.082 0.000 0.055 0.055 0.000 0.071 0.071 0.000 43 0.000 11296.829 0.000 0.000 10038.013 0.000 0.000 10218.244 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.69. 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.

Palo Verde 2 Palo Verde 1 Redhawk 2 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

Nuclear Combined Cycle Nuclear 1 Under 50% Outdoor Over 50% Outdoor Under 50% Outdoor 2 1986 2002 1986 3 1988 2002 1988 4 408.33 567.20 408.33 5 395 539 390 6 7957 7551 8784 7 0 0 0 8 382 492 382 9 0 0 0 10 246 27 246 11 3014199744 2429675000 3341312830 12 1076968 1077407 1772137 13 178067451 10823210 289468786 14 497849985 246097398 778466197 15 -7857443 0 -13440695 16 669136961 257998015 1056266425 17 1638.7161 454.8625 2586.7960 18 8528438 0 8414816 19 30275951 112763622 30538102 20 3653761 0 3684242 21 3502178 0 2422510 22 0 0 0 23 0 0 0 24 2817154 1786943 2977479 25 11232745 2830754 10516159 26 15222412 0 15222412 27 0 0 0 28 2420848 212783 1455311 29 648661 160530 668910 30 5124595 0 1990217 31 6380302 1256248 2913620 32 1547858 1480912 1167310 33 91354903 120491792 81971088 34 0.0303 0.0496 0.0245 35 Gas Total Nuclear Nuclear 36 MCF Kg Uranium Kg Uranium 37 17661470 0 0 465 0 0 517 0 0 38 1017678 0 0 66706 0 0 66706 0 0 39 2.976 0.000 0.000 2958.417 0.000 0.000 0.000 0.000 0.000 40 6.385 0.000 0.000 65137.588 0.000 0.000 59113.631 0.000 0.000 41 6.274 6.274 0.000 0.976 0.000 0.000 0.886 0.000 0.000 42 0.046 0.046 0.000 0.010 0.000 0.000 0.009 0.000 0.000 43 0.000 7394.382 0.000 10286.661 0.000 0.000 10314.248 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.79. 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. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 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 0 0 21 0 0 0 22 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 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.89. 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. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 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 0 0 21 0 0 0 22 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 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.9

### Schedule Page: 402.6 Line No.: 5 Column: b 

## Sundance: Generator Name Plate Rating is 605 MW at 15 degrees C and 0.85 Power Factor. Plant Output is limited by gas turbine. Schedule Page: 403.7 Line No.: 1 Column: e 

## The Palo Verde Nuclear Units have pressurized water reactors. The nuclear fuel assemblies in the reactors contain enriched uranium. The cost of nuclear fuel is amortized to fuel expense (acct. 518) based on the fuel burns, or quantity of heat, produced in the generation of energy. Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from the reactors. Additional information on APS' nuclear fuel program and nuclear decommissioning is detailed in the Notes to Consolidated Financial Statements. Schedule Page: 403.7 Line No.: 1 Column: f 

## The Palo Verde Nuclear Units have pressurized water reactors. The nuclear fuel assemblies in the reactors contain enriched uranium. The cost of nuclear fuel is amortized to fuel expense (acct. 518) based on the fuel burns, or quantity of heat, produced in the generation of energy. Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from the reactors. Additional information on APS' nuclear fuel program and nuclear decommissioning is detailed in the Notes to Consolidated Financial Statements. Schedule Page: 402.8 Line No.: 1 Column: b 

## The Palo Verde Nuclear Units have pressurized water reactors. The nuclear fuel assemblies in the reactors contain enriched uranium. The cost of nuclear fuel is amortized to fuel expense (acct. 518) based on the fuel burns, or quantity of heat, produced in the generation of energy. Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from the reactors. Additional information on APS' nuclear fuel program and nuclear decommissioning is detailed in the Notes to Consolidated Financial Statements. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.10 0 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item FERC Licensed Project No. (b) (a) (c) Plant Name: FERC Licensed Project No. Plant Name: 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.

Kind of Plant (Run-of-River or Storage)

1 Plant Construction type (Conventional or Outdoor) 2Year Originally Constructed 3Year Last Unit was Installed 4Total installed cap (Gen name plate Rating in MW) 5 0.00 0.00 Net Peak Demand on Plant-Megawatts (60 minutes) 6 0 0 Plant Hours Connect to Load 7 0 0 Net Plant Capability (in megawatts) 8(a) Under Most Favorable Oper Conditions 9 0 0 (b) Under the Most Adverse Oper Conditions 10 0 0 Average Number of Employees 11 0 0 Net Generation, Exclusive of Plant Use - Kwh 12 0 0 Cost of Plant 13Land and Land Rights 14 0 0 Structures and Improvements 15 0 0 Reservoirs, Dams, and Waterways 16 0 0 Equipment Costs 17 0 0 Roads, Railroads, and Bridges 18 0 0 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 0 0 Cost per KW of Installed Capacity (line 20 / 5) 21 0.0000 0.0000 Production Expenses 22Operation Supervision and Engineering 23 0 0 Water for Power 24 0 0 Hydraulic Expenses 25 0 0 Electric Expenses 26 0 0 Misc Hydraulic Power Generation Expenses 27 0 0 Rents 28 0 0 Maintenance Supervision and Engineering 29 0 0 Maintenance of Structures 30 0 0 Maintenance of Reservoirs, Dams, and Waterways 31 0 0 Maintenance of Electric Plant 32 0 0 Maintenance of Misc Hydraulic Plant 33 0 0 Total Production Expenses (total 23 thru 33) 34 0 0 Expenses per net KWh 35 0.0000 0.0000

FERC FORM NO. 1 (REV. 12-03) Page4060 0 0 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

FERC Licensed Project No. (e) (d) (f) Plant Name: FERC Licensed Project No. Plant Name: FERC Licensed Project No. Plant Name: Line No. 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.

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 22 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

FERC FORM NO. 1 (REV. 12-03) Page407FERC Licensed Project No. Plant Name: (b) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Item (a) 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."

1 Type of Plant Construction (Conventional or Outdoor) 2Year Originally Constructed 3Year Last Unit was Installed 4Total installed cap (Gen name plate Rating in MW) 5Net Peak Demaind on Plant-Megawatts (60 minutes) 6Plant Hours Connect to Load While Generating 7Net Plant Capability (in megawatts) 8Average Number of Employees 9Generation, Exclusive of Plant Use - Kwh 10Energy Used for Pumping 11 Net Output for Load (line 9 - line 10) - Kwh 12Cost of Plant 13Land and Land Rights 14Structures and Improvements 15Reservoirs, Dams, and Waterways 16Water Wheels, Turbines, and Generators 17Accessory Electric Equipment 18Miscellaneous Powerplant Equipment 19Roads, Railroads, and Bridges 20Asset Retirement Costs 21 Total cost (total 13 thru 20) 22Cost per KW of installed cap (line 21 / 4) 23Production Expenses 24Operation Supervision and Engineering 25Water for Power 26Pumped Storage Expenses 27Electric Expenses 28Misc Pumped Storage Power generation Expenses 29Rents 30Maintenance Supervision and Engineering 31 Maintenance of Structures 32Maintenance of Reservoirs, Dams, and Waterways 33Maintenance of Electric Plant 34Maintenance of Misc Pumped Storage Plant 35Production Exp Before Pumping Exp (24 thru 34) 36Pumping Expenses 37Total Production Exp (total 35 and 36) 38Expenses per KWh (line 37 / 9)

FERC FORM NO. 1 (REV. 12-03) Page408FERC Licensed Project No. Plant Name: FERC Licensed Project No. Plant Name: (d) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. FERC Licensed Project No. Plant Name: (e) (c) 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.

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) Page409Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of GENERATING PLANT STATISTICS (Small Plants) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name of Plant Installed Capacity

(c) (b) (a) Cost of Plant Net Peak Demand

(d) Year Orig. Const. Name Plate Rating (In MW) MW (60 min.) Net Generation Excluding Plant Use (e) (f) 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.

Solar Plants 1 1.31 32 9,896,231 1997 Flagstaff 2 0.19 564 1,540,761 1998 Star 3 12,817 1998 Tempe 4 0.07 124 114,593 1999 Glendale Airport 5 0.12 241 77,374 2001 Gilbert 6 0.29 630 557,305 1999 Scottsdale Covered Parking 7 64,174 1999 Municipal Rooftops 8 0.17 379 324,235 2002 Yuma 9 443 57,377 2002 Prescott Earu 10 2.90 4,959 1,927,250 2001 Prescott 11 1.00 846,413 2005 Red Rock 12 0.08 100 29,053 1998 Phoenix 13 1996 Off-Grid Facilities 14 30.00 39,252 74,989,914 2011 Hyder Phase 1 15 17.00 46,172 80,741,132 2011 Cotton Center 16 17.00 42,843 66,150,605 2011 Paloma 17 0.18 296 1,350,091 2011 US Airways Center 18 0.06 98 1,284,717 2011 Chase Field 19 19.00 6,292 90,709,604 2012 Chino Valley 20 6.38 2,858 29,931,901 2012 APS Solar for Schools 21 95.75 145,283 360,605,547 Total Solar Operation/Maintenance 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 (REV. 12-03) Page 410Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of GENERATING PLANT STATISTICS (Small Plants) (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (i) (h) (g) (j) (k) (l) Operation Exc'l. Fuel Production Expenses Fuel Maintenance Kind of Fuel Fuel Costs (in cents (per Million Btu) 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.
Plant Cost (Incl Asset Retire. Costs) Per MW

1 7,579,416 2 8,055,880 3 4 1,598,678 5 671,651 6 1,949,163 7 8 1,954,540 9 10 664,848 11 846,413 12 349,191 13 14 2,499,664 15 4,749,478 16 3,891,212 17 7,418,737 18 20,338,106 19 4,774,190 20 4,688,346 21 3,766,230 22 1,224,819 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 (REV. 12-03) Page 411

### Schedule Page: 410 Line No.: 14 Column: a 

## Portion of off-grid facilities are leased from others. Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
TRANSMISSION LINE STATISTICS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No.

(c) (b) (a) (d) (e) DESIGNATION

From To (f) (g) VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase)

Operating Designed Type of Supporting Structure LENGTH (Pole miles) (In the case of underground lines report circuit miles) On Structure of Line Designated On Structures of Another Line Number Of Circuits

(h) 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.

(3) STEEL (A) 500.00 500.00 74.80 1 1 PALO VERDE KYRENE (3) STEEL (A) 500.00 500.00 45.00 1 2PALO VERDE WESTWING #2 (3) STEEL 500.00 500.00 366.00 1 3FOUR CORNERS COLORADO RIVER (3) STEEL (A) 500.00 500.00 256.00 1 4NAVAJO PLANT WESTWING (3) STEEL (A) 500.00 500.00 76.00 1 5NAVAJO PLANT MOENKOPI (3) STEEL (A) 500.00 500.00 180.00 1 6MOENKOPI WESTWING (3) STEEL 500.00 500.00 206.00 1 7CHOLLA SAGUARO (3) STEEL (A) 500.00 500.00 47.00 1 8PALO VERDE WESTWING (3) STEEL (A) 500.00 500.00 120.00 1 9PALO VERDE NORTH GILA (3) STEEL (A) 500.00 500.00 242.70 1 10WESTWING MEAD (3) STEEL (A) 500.00 500.00 13.30 1 11 MEAD MARKET PLACE (3) STEEL 500.00 500.00 0.25 1 12KYRENE/PALO VERDE JOJOBA SUB (3) STEEL 500.00 500.00 18.50 2 13GILA RIVER JOJOBA SWITCHYARD (3) STEEL (A) 500.00 500.00 35.68 1 14PALO VERDE RUDD (3) STEEL (A) 500.00 500.00 3.10 1 15PALO VERDE HASSAYAMPA (3) STEEL (A) 500.00 500.00 6.00 27.00 1 16MORGAN PINNACLE PEAK (3) STEEL 500.00 500.00 1 17WESTWING DUGAS LOOP (3) STEEL (C) 345.00 345.00 12.00 566.00 2 18FOUR CORNERS PINNACLE PEAK (1) STEEL 230.00 230.00 1.30 2 19YAVAPAI TAP IN & OUT (3) STEEL (D) 345.00 230.00 12.77 1 20WESTWING EL SOL (2) WOOD 230.00 230.00 88.14 1 21CHOLLA PLANT FLAGSTAFF (3) STEEL (D) 230.00 230.00 6.00 1 22LIBERTY GILA BEND (1) WOOD 230.00 230.00 12.00 1 23LIBERTY GILA BEND (2) WOOD 230.00 230.00 28.00 1 24LIBERTY GILA BEND (2) WOOD 230.00 230.00 32.68 1 25COCONINO VERDE (2) WOOD 230.00 230.00 34.30 1 26VERDE WILLOW LAKE (2) WOOD 230.00 230.00 36.19 1 27ROUND VALLEY SELIGMAN (3) STEEL 230.00 230.00 51.20 2 28PINNACLE PEAK OCOTILLO (3) STEEL 230.00 230.00 5.65 1 29EL SOL AGUA FRIA (1) STEEL 230.00 230.00 10.02 1 30AGUA FRIA GRAND TERMINAL (3) STEEL 230.00 230.00 10.30 10.30 2 31OCOTILLO PLANT LINCOLN STREET (4) U.G. 230.00 230.00 1.00 32OCOTILLO PLANT LINCOLN STREET (1) STEEL 230.00 230.00 6.50 2 33OCOTILLO PLANT SRP TAP KYRENE SUB (3) STEEL 230.00 230.00 1.60 1 34OCOTILLO PLANT 68TH ST & SALT RIVER (3) STEEL 230.00 230.00 5.50 1 35LINCOLN STREET WEST PHOENIX PLANT

FERC FORM NO. 1 (ED. 12-87) Page 422

36 TOTAL 5,031.80 881.15 80Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
TRANSMISSION LINE STATISTICS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No.

(c) (b) (a) (d) (e) DESIGNATION

From To (f) (g) VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase)

Operating Designed Type of Supporting Structure LENGTH (Pole miles) (In the case of underground lines report circuit miles) On Structure of Line Designated On Structures of Another Line Number Of Circuits

(h) 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.

(2) WOOD 230.00 230.00 61.50 1 1SANTA ROSA SAGUARO PLANT (1) STEEL 230.00 230.00 3.20 2 2PINNACLE PEAK-OCOTILLOCACTUS SUB TAP (1) STEEL 230.00 230.00 0.12 1 3PINNACLE PEAK/LONE REACH SUB TAP (4) U.G. 230.00 230.00 0.63 1 4PINNACLE PEAK/LONE REACH SUB (1) STEEL 230.00 230.00 0.25 1 5GILA BEND/LIBERTY PANDA SWITCHYARD (1) STEEL 230.00 230.00 3.30 2 6SRP-PINNACLE PEAK DEER VALLEY TAP (4) U.G. 230.00 230.00 3.50 1 7LINCOLN STREET COUNTRY CLUB (4) U.G. 230.00 230.00 7.50 1 8SUNNYSLOPE COUNTRY CLUB (4) U.G. 230.00 230.00 2.50 1 9GRAND TERMINAL COUNTRY CLUB (2) WOOD 230.00 230.00 14.95 1 10SANTA ROSA CASA GRANDE (1) WOOD 230.00 230.00 6.74 1 11CASA GRANDE SAGUARO (2) WOOD 230.00 230.00 38.97 1 12CASA GRANDE SAGUARO (1) STEEL 230.00 230.00 11.25 1 13WESTWING-EL SOL SURPRISE (1) STEEL 230.00 230.00 7.60 1 14DEER VALLEY ALEXANDER (1) STEEL 230.00 230.00 16.70 1 15PINNACLE PEAK SUNNYSLOPE (2) WOOD 230.00 230.00 36.30 1 16OCOTILLO SANTA ROSA (2) WOOD 230.00 230.00 1.67 1 17ROUND VALLEY/SELIGMAN FORT ROCK (1) STEEL 230.00 230.00 12.00 2 18WHITE TANKS WEST PHOENIX (3) STEEL 230.00 230.00 9.00 1 19EL SOL WHITE TANKS (3) STEEL 230.00 230.00 11.90 1 20PINNACLE PEAK LONE PEAK (4) U.G. 230.00 230.00 0.16 1 21 MEADOWBROOK SUNNYSLOPE (4) U.G. 230.00 230.00 0.17 1 22MEADOWBROOK COUNTRY CLUB (1) STEEL 230.00 230.00 20.48 1 23RUDD LIBERTY (1) STEEL 230.00 230.00 3.30 2 24PALO VERDE NORTH GILA TAP (1) STEEL 230.00 230.00 3.30 2 25PALO VERDE KYRENE TAP (3) STEEL 230.00 230.00 0.75 1 26MORGAN RACEWAY TAP (2) WOOD 230.00 69.00 60.00 1 27TUBA CITY TAP POWELL SUB (2) WOOD 230.00 115.00 41.50 1 28SAGUARO PLANT SAN MANUEL (2) WOOD 115.00 115.00 21.06 1 29ORACLE SAN MANUEL (2) WOOD 115.00 115.00 47.15 1 30ADAMS MURAL (2) WOOD 115.00 115.00 11.00 1 31SANTA ROSA ASARCO (2) WOOD 115.00 115.00 3.81 1 32ASARCO VISTA (1) WOOD 115.00 115.00 3.02 1 33ASARCO VISTA (2) WOOD 115.00 115.00 49.00 1 34WILLOW LAKE BAGDAD 69.00 69.00 19.63 35UNDERGROUND

FERC FORM NO. 1 (ED. 12-87) Page 422.1

36 TOTAL 5,031.80 881.15 80Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
TRANSMISSION LINE STATISTICS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No.

(c) (b) (a) (d) (e) DESIGNATION

From To (f) (g) VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase)

Operating Designed Type of Supporting Structure LENGTH (Pole miles) (In the case of underground lines report circuit miles) On Structure of Line Designated On Structures of Another Line Number Of Circuits

(h) 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.

69.00 69.00 30.58 2,698.04 1 1OVERHEAD 1.64 2RELATED TRANSMISSION 3EHV STRUCTURES TEMP. 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

FERC FORM NO. 1 (ED. 12-87) Page 422.2

36 TOTAL 5,031.80 881.15 80Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION LINE STATISTICS (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation Expenses Maintenance Rents Total Land Construction and Other Costs Total Cost (i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses 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.

19,901,128 1780 ACSR 19,901,128 1 5,971,160 1780 ACSR 5,971,160 2 42,238,625 2156 ACSR 39,917,115 2,321,510 3 8,749,654 2156 ACSR 8,665,938 83,716 4 1,208,159 2156 ACSR 1,208,159 5 5,621,511 2156 ACSR 5,316,391 305,120 6 61,253,941 2156 ACSR 60,305,879 948,062 7 5,580,733 1780 ACSR 5,151,452 429,281 8 4,688,075 2156 ACSR 4,540,896 147,179 9 18,266,519 1590 KCM 17,090,839 1,175,680 10 677,379 1590 KCM 626,769 50,610 11 954 ACSR 12 1780 ACSR 13 41,778,908 1780 ACSR 29,540,970 12,237,938 14 971,425 1780 ACSR 776,503 194,922 15 48,985,080 1780 ACSR 33,366,026 15,619,054 16 3,178,473 2156 ACSR 3,178,473 17 31,680,708 795 ACSR 30,459,920 1,220,788 18 947,577 954 ACSR 947,577 19 3,848,232 795 ACSR 3,423,589 424,643 20 3,290,016 795 ACSR 3,146,892 143,124 21 1,683,216 1272 ACSR 1,550,628 132,588 22 1,507,444 1272 ACSR 1,358,866 148,578 23 3,679,893 1272 ACSR 3,309,278 370,615 24 2,180,355 795 ACSR 2,144,411 35,944 25 3,351,518 795 ACSR 3,298,468 53,050 26 2,106,157 795 ACSR 2,097,188 8,969 27 19,980,513 795 AA 7,704,155 12,276,358 28 757,255 1431 AA 536,958 220,297 29 3,330,426 1361 ACAR 3,218,246 112,180 30 7,579,542 1431 AA 6,759,382 820,160 31 1,826,611 2000 KC 1,826,611 32 5,813,374 954 ACSR 3,881,596 1,931,778 33 17,978 954A/1113A 17,978 34 3,313,248 1113 AA 3,275,987 37,261 35

FERC FORM NO. 1 (ED. 12-87) Page 423 36 121,583,860 947,997,886 1,069,581,746 19,430,487 14,467,225 6,614,513 40,512,225Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION LINE STATISTICS (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation Expenses Maintenance Rents Total Land Construction and Other Costs Total Cost (i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses 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.

4,646,964 954A/1113A 3,080,996 1,565,968 1 1,611,847 954 AA 1,324,874 286,973 2 1,946,642 954 ACSR 203,127 1,743,515 3 810,358 1750 CU 667,687 142,671 4 1272 ACSR 5 2,863,774 954 AA 2,785,385 78,389 6 7,163,366 1750 CU 6,141,784 1,021,582 7 5,757,743 1750 CU 5,672,649 85,094 8 1,705,524 1750 CU 1,663,288 42,236 9 4,317,412 1272 ACSR 3,775,970 541,442 10 902,115 1272 ACSR 823,686 78,429 11 7,184,114 1272 ACSR 6,665,096 519,018 12 1,585,729 954 ACSR 1,203,882 381,847 13 5,419,295 954 AA 4,485,834 933,461 14 4,516,360 1431A/1361 ACSR 4,389,119 127,241 15 7,089,297 795R/1113A 6,736,913 352,384 16 39,196 795 AA 39,196 17 23,416,408 954 SSAC 16,026,636 7,389,772 18 7,278,481 954 ACSR 6,251,970 1,026,511 19 11,424,531 954 ACSR 7,736,796 3,687,735 20 618,139 1750 ACSR 618,139 21 857,317 1750 ACSR 857,317 22 21,730,264 1780 ACSR 13,488,478 8,241,786 23 374,911 954 AA 374,911 24 383,526 954 AA 383,526 25 20,993,605 2156 ACSS 14,299,725 6,693,880 26 2,380,164 954 ACSR 2,380,164 27 1,645,714 954 ACSR 1,599,074 46,640 28 2,536,504 556 ACSR 2,462,446 74,058 29 2,429,268 556 ACSR 1,994,131 435,137 30 526,444 795 ACSR 433,334 93,110 31 410,523 795 ACSR 392,494 18,029 32 241,570 795 ACSR 229,551 12,019 33 3,173,652 795 ACSR 2,952,806 220,846 34 35,954,746 35,954,746 35

FERC FORM NO. 1 (ED. 12-87) Page 423.1 36 121,583,860 947,997,886 1,069,581,746 19,430,487 14,467,225 6,614,513 40,512,225Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION LINE STATISTICS (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation Expenses Maintenance Rents Total Land Construction and Other Costs Total Cost (i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses 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.

504,015,579 469,742,518 34,273,061 1 5,350,105 5,328,484 21,621 2 315,726 315,726 3 40,512,225 6,614,513 14,467,225 19,430,487 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

FERC FORM NO. 1 (ED. 12-87) Page 423.2 36 121,583,860 947,997,886 1,069,581,746 19,430,487 14,467,225 6,614,513 40,512,225

### Schedule Page: 422.2 Line No.: 2 Column: a INCLUDES MINOR NAVAJO RELATED TRANSMISSION, YUCCA TURBINES RELATED TRANSMISSION, FOUR CORNERS UNITS 1, 2, 3, AND TIE LINE BETWEEN THE KYRENE 500KV SWITCHYARD, AND REDHAWK TURBINES RELATED TRANSMISSION Schedule Page: 422.2 Line No.: 4 Column: a STATEMENT OF CO-OWNERSHIP AS DESCRIBED IN INSTRUCTION #8, PAGE 423 AND AS NOTED ON PAGE 422 NONE OF THE CO-OWNERS IS AN ASSOCIATED COMPANY. (A) CO-OWNERSHIP ON:

LINE # 4 - NAVAJO PLANT TO WESTWING LINE # 5 - NAVAJO PLANT TO MOENKOPI LINE # 6 - MOENKOPI TO WESTWING LINE # 8 - PALO VERDE TO WESTWING LINE # 9 - PALO VERDE TO NORTH GILA LINE #10 - WESTWING TO MEAD LINE #11 - MEAD TO MARKET PLACE LINE # 1 - PALO VERDE TO KYRENE LINE # 2 - PALO VERDE TO WESTWING #2 LINE #14 - PALO VERDE TO RUDD LINE #15 - PALO VERDE TO HASSAYAMPA LINE #16 - MORGAN TO PINNACLE PEAK 500KV/230KV (1) CO-OWNERS OF LINES 4 & 6 ARE SALT RIVER PROJECT, TUCSON ELECTRIC POWER, AND U.S. DEPARTMENT OF ENERGY (2) CO-OWNERS OF LINE 5 ARE SALT RIVER PROJECT, TUCSON ELECTRIC POWER, NEVADA POWER COMPANY, LOS ANGELES DEPARTMENT OF WATER AND POWER, AND U.S. DEPARTMENT OF ENERGY (3) CO-OWNERS OF LINE 8 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC SERVICE OF NEW MEXICO (4) CO-OWNERS OF LINE 9 ARE THE IMPERIAL IRRIGATION DISTRICT AND SAN DIEGO GAS AND ELECTRIC (5) CO-OWNERS OF LINE 10 ARE M-S-R PUBLIC POWER AGENCY, SALT RIVER PROJECT, CITY OF VERNON, SOUTHERN CALIFORNIA PUBLIC AUTHORITY, AND U.S. DEPARTMENT OF ENERGY (6) CO-OWNERS OF LINE 11 ARE M-S-R PUBLIC POWER AGENCY, SALT RIVER PROJECT, CITY OF VERNON, SOUTHERN CALIFORNIA PUBLIC AUTHORITY, AND U.S. DEPARTMENT OF ENERGY (7) CO-OWNERS OF LINE 1 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC SERVICE OF NEW MEXICO (8) CO-OWNERS OF LINE 2 ARE EL PASO ELECTRIC COMPANY, PUBLIC SERVICE OF NEW MEXICO, AND SALT RIVER PROJECT (9) CO-OWNERS OF LINE 14 ARE SALT RIVER PROJECT AND ARIZONA PUBLIC SERVICE COMPANY (10) CO-OWNERS OF LINE 15 ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, AND PUBLIC SERVICE OF NEW MEXICO Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

### (11) CO-OWNERS OF LINE 16 ARE SALT RIVER PROJECT AND ARIZONA PUBLIC SERVICE COMPANY (12) EXPENSES TO OPERATE THESE LINES ARE ALLOCATED TO PARTICIPANTS BASED ON OWNERSHIP AS SET FORTH IN OPERATION AND MAINTENANCE AGREEMENTS (13) ARIZONA PUBLIC SERVICE COMPANY'S SHARE OF THE EXPENSES TO OPERATE THESE LINES ARE RECORDED IN TRANSMISSION EXPENSE ACCOUNTS 560, 561, 563, 566, 567, 571, AND 573 (C) A.P.S. DOUBLE CIRCUIT TOWERS WITH ANOTHER UTILITY ON ONE SIDE (D) EXPENSES FOR THE OPERATION, MAINTENANCE AND RENTS ARE NOT SEGREGATED IN THE COMPANY'S BOOKS FOR EACH TRANSMISSION LINE Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
TRANSMISSION LINES ADDED DURING YEAR Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (c) (b) (a) (d) (e) LINE DESIGNATION From To Line Length

in Miles SUPPORTING STRUCTURE Type Average Number per Miles CIRCUITS PER STRUCTURE Present Ultimate

(f) (g) 

### 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

13.00 STEEL 2 2 1BISCUIT FLATS PIONEER/GATEWAY 0.52 6.00 STEEL 2 2 2WILLOW LAKE/LONESOME WELLFIELD TAP 0.35 12.00 STEEL 1 1 3YOUNGS CANYON SANDVIG 9.35 13.00 STEEL 1 1 4INTERSTATE 17 RELOCATE CORDES JUNCTION -0.44 14.00 STEEL 2 2 5WALDRIP MARINE AIR/32ND STREET 0.72 2.00 STEEL 2 2 6OLD HOME MANOR GRANITE CREEK 0.03 1.00 STEEL 1 1 7POPLAR WASH/WILHOIT KIRKLAND JUNCTION 0.05 12.00 STEEL 1 1 8WALDRIP MARINE AIR/SOUTH O'NEIL 2.18 12.00 STEEL 2 2 9PADRE/SUNSHINE TWIN ARROWS 1.29 17.00 STEEL 1 1 10BAJA WALDRIP PHASE 3 1.55 16.00 STEEL 1 1 11BAJA WALDRIP PHASE 4 2.14 16.00 STEEL 1 1 12BAJA WALDRIP PHASE 5 & TAP 1.70 17.00 STEEL 2 2 13BAJA WALDRIP PHASE 5 & TAP 1.04 12.00 STEEL 1 1 14FESTIVAL RANCH MCMICKEN/FARMER 0.72 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

21.20 163.00 20 20 FERC FORM NO. 1 (REV. 12-03) Page 424 44 TOTALTotal Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION LINES ADDED DURING YEAR (Continued) Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. (k) (j) (h) (l) (m) CONDUCTORS Size Configuration Voltage KV LINE COST Land and Poles, Towers and Fixtures Conductors (n) (p) Specification and Spacing (Operating) Land Rights and Devices (i) 

### 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.

Asset (o) Retire. Costs
45/7 ACSS 795 151,128 517,723 366,595 69 1 45/7 ACSS 795 199,464 664,881 465,417 69 2 45/7 ACSS 795 1,110,868 3,702,893 2,592,025 69 3 37 - 45/7 AL-ACSS 795 8,129 27,098 18,969 69 4 45/7 ACSS 795 319,762 1,065,873 746,111 69 5 37 AL 795 166,050 553,500 387,450 69 6 37 AL 795 81,273 270,910 189,637 69 7 45/7 ACSS 795 167,280 557,599 390,319 69 8 45/7 ACSS 795 6,481 21,604 15,123 69 9 45/7 ACSS 795 115,772 791,881 676,109 69 10 45/7 ACSS 795 244,747 815,822 571,075 69 11 45/7 ACSS 795 561,546 1,871,821 1,310,275 69 12 45/7 ACSS 795 69 13 6/1 ACSR 3/0 204,194 680,647 476,453 69 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

3,336,694 8,205,558

FERC FORM NO. 1 (REV. 12-03) Page 425 44 11,542,252Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

ACOMA-SCOTTSDALE 12.00 69.00 D 1 ADAMS-BENSON 115.00 T 2ADOBE-PHOENIX 12.00 69.00 D 3AGUA FRIA SWYD-GLENDALE 69.00 230.00 T 4AGUILA-AGUILA 12.00 69.00 D 5AJO-AJO 21.00 69.00 D 6ALEXANDER-PHOENIX 69.00 T 7ALTADENA-SCOTTSDALE 12.00 69.00 D 8ANTELOPE-PRESCOTT 12.00 69.00 D 9ARABY-YUMA 12.00 69.00 D 10ARICA-ELOY 12.00 69.00 D 11 ARLINGTON-MARICOPA COUNTY 12.00 69.00 D 12ARROWHEAD-GLENDALE 12.00 69.00 D 13ARROYO-PHOENIX 12.00 69.00 D 14ASARCO PIT-CASA GRANDE 12.00 69.00 D 15ASHFORK-ASHFORK 12.00 69.00 D 16AZTEC-AZTEC 12.00 69.00 D 17 BACON-N.W. OF SNOWFLAKE 21.00 69.00 D 18 BAGDAD-BAGDAD 12.00 115.00 T 19 BAGDAD-115KV CAP.-BAGDAD 115.00 T 20 BAJA-SAN LUIS 12.00 69.00 D 21 BALD MOUNTAIN-PRESCOTT VALLEY 12.00 69.00 D 22 BASELINE-BUCKEYE 12.00 69.00 D 23 BEARDSLEY-SURPRISE 12.00 69.00 D 24 BELL-PEORIA 12.00 69.00 D 25 BISCUIT FLATS-PHOENIX 69.00 D 26 BLACK MESA #2-GRAY MOUNTAIN 69.00 D 27 BLACK BEAK (BOUSE APA)-PARKER 69.00 161.00 T 28 BLACK BEAK (BOUSE APA)-PARKER 12.00 69.00 D 29 BLUE RIDGE-BLUE RIDGE 21.60 69.00 D 30 BLUE WATER-N. OF PARKER 12.00 34.50 D 31 BONNYBROOK-FLORENCE 12.00 115.00 D 32 BOOTHILL-E. OF TOMBSTONE 21.00 115.00 D 33 BOULEVARD-SCOTTSDALE 12.00 69.00 D 34 BUCKEYE-BUCKEYE 69.00 230.00 T 35 BUCKEYE-BUCKEYE 12.00 69.00 D 36 BUFFALO-PHOENIX 12.00 69.00 D 37 BUNYAN-NW. OF GILA BEND 12.00 69.00 D 38 BUTTE-TEMPE 12.00 69.00 D 39 CACTUS-SCOTTSDALE 69.00 230.00 12.00 T 40

FERC FORM NO. 1 (ED. 12-96) Page 426Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

CACTUS-SCOTTSDALE 12.00 69.00 D 1 CALDERWOOD-PEORIA 12.00 69.00 D 2 CAMELBACK-SCOTTSDALE 12.00 69.00 D 3 CAMERON-CAMERON 12.00 69.00 D 4 CANAL-PHOENIX 12.00 69.00 D 5 CAPITAL BUTTE-SEDONA 12.00 69.00 D 6 CASA GRANDE-CASA GRANDE 69.00 230.00 12.00 T 7 CASA GRANDE-CASA GRANDE 12.00 230.00 D 8 CASA GRANDE-CASA GRANDE 12.00 69.00 D 9 CAVE CREEK-CAVE CREEK 12.00 69.00 D 10 CEDAR MOUNTAIN-WILLIAMS 500.00 T 11 CENTURY-SCOTTSDALE 12.00 69.00 D 12 CHANDLER-CHANDLER 12.00 69.00 D 13 CHAPARRAL-SCOTTSDALE 12.00 69.00 D 14 CHERYL-PHOENIX 12.00 69.00 D 15 CHILDS-CAMP VERDE 69.00 D 16 CHINO VALLEY-CHINO VALLEY 12.00 69.00 D 17 CHOLLA-JOSEPH CITY 345.00 525.00 A,T 18 CHOLLA-JOSEPH CITY 525.00 A,T 19 CHOLLA-JOSEPH CITY 230.00 345.00 A,T 20 CHOLLA-JOSEPH CITY 69.00 345.00 A,T 21 CHOLLA-JOSEPH CITY 69.00 230.00 A,T 22 CHOLLA-JOSEPH CITY 12.00 69.00 D 23 CIELO GRANDE-PHOENIX 12.00 69.00 D 24 CLINIC - SCOTTSDALE 12.00 69.00 D 25 COCONINO-FLAGSTAFF 69.00 230.00 T 26 COCONINO-FLAGSTAFF 12.00 69.00 D 27 COCOPAH-W. OF YUMA 12.00 69.00 D 28 COLDWATER-GOODYEAR 12.00 69.00 D 29 COLORADO-N. OF PARKER 12.00 69.00 D 30 COLTER-AVONDALE 12.00 69.00 D 31 CONLEY-SNOWFLAKE 69.00 T 32 COOLIDGE-N. OF COOLIDGE 12.40 D 33 COPPER CANYON-N. OF CAMP VERDE 12.00 69.00 D 34 CORDES-CORDES JUNCTION 12.00 69.00 D 35 CORNVILLE-CORNVILLE 12.00 69.00 D 36 COTTON CENTER-N. OF GILA BEND 12.00 69.00 D 37 COTTONWOOD-COTTONWOOD 12.00 69.00 D 38 COTTONWOOD-COTTONWOOD D 39 COUNTRY CLUB-PHOENIX 12.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

COUNTRY CLUB-PHOENIX 69.00 230.00 T 1 COUNTY LINE-TONOPAH 12.00 69.00 D 2 CROSSROADS-N. OF PARKER 12.00 34.50 D 3 DALE-SCOTTSDALE 12.00 69.00 D 4 DALE-SCOTTSDALE 69.00 D 5 DAVENPORT- E. OF WILLIAMS 12.00 69.00 D 6 DEADMAN WASH-PHOENIX 12.00 69.00 D 7 DEADMAN WASH-PHOENIX 69.00 D 8 DEER VALLEY-PHOENIX 69.00 230.00 12.00 T 9 DEER VALLEY-PHOENIX 12.00 69.00 D 10 DEL RIO-PEORIA 12.00 69.00 D 11 DELANO-PRESCOTT 12.00 69.00 D 12 DESERT RIDGE-SCOTTSDALE 12.00 69.00 D 13 DESERT SANDS - YUMA 69.00 T 14 DESERT SKY-BUCKEYE 12.00 69.00 D 15 DESERT SPRINGS-PHOENIX 12.00 69.00 D 16 DEWEY-N. OF DEWEY 12.00 69.00 D 17 DIXILETA-N. OF SCOTTSDALE 12.00 69.00 D 18 DON LUIS-BISBEE 12.00 69.00 D 19 DOUBLETREE-PHOENIX 12.00 69.00 D 20 DOVE VALLEY-PHOENIX 12.00 69.00 D 21 DOWNING-SCOTTSDALE 12.00 69.00 D 22 DRAKE-PAULDEN 69.00 D 23 DRY LAKE SUB 7.20 69.00 D 24 DUGAS-MAYER 69.00 525.00 T 25 DUGAS-MAYER T 26 DURANGO-PHOENIX 12.00 69.00 D 27 DYSART-SURPRISE 12.00 69.00 D 28 EAGLE EYE-W. OF AGUILA 69.00 230.00 T 29 EAST END-SCOTTSDALE 12.00 69.00 D 30 EASTERN OFFICE-PHOENIX 12.00 69.00 D 31 EASTGATE-CASA GRANDE 12.00 69.00 D 32 EHRENBERG-EHRENBERG 12.00 33.00 D 33 EL SOL-YOUNGTOWN 69.00 230.00 T 34 EL SOL-YOUNGTOWN 12.00 69.00 D 35 ELDEN-FLAGSTAFF 12.00 69.00 D 36 ENCANTO-PHOENIX 12.00 69.00 D 37 ESTRELLITA-GOODYEAR 12.00 69.00 D 38 EVANS CHURCHILL-PHOENIX 12.00 69.00 D 39 FAIRVIEW-N. OF DOUGLAS 12.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

FARMER - SURPRISE 69.00 T 1 FESTIVAL RANCH-BUCKEYE 12.00 69.00 D 2 FILLMORE-PHOENIX 12.00 69.00 D 3 FISH SAWMILL-N. OF FLAGSTAFF 12.00 69.00 D 4 FLORES-CONGRESS 12.00 69.00 D 5 FLYING E-WICKENBURG 12.00 69.00 D 6 FOOTHILLS-YUMA 12.00 69.00 D 7 FORTIETH PLACE-PHOENIX 12.00 69.00 D 8 FOUR CORNERS-FRUITLAND,NM 345.00 525.00 A,T 9 FOUR CORNERS-FRUITLAND,NM 230.00 345.00 A,T 10 FOUR CORNERS-FRUITLAND,NM 69.00 230.00 A,T 11 GARFIELD-PHOENIX 12.00 69.00 D 12 GARLAND PRAIRIE-E. OF WILLIAMS 12.00 69.00 D 13 GATEWAY - PHOENIX 12.00 69.00 D 14 GAVILAN PEAK-PHOENIX 69.00 230.00 T 15 GAVILAN PEAK-PHOENIX 12.00 69.00 D 16 GILA BEND-GILA BEND 69.00 230.00 T 17 GILA BEND-GILA BEND 12.00 69.00 D 18 GILBERT-GILBERT 12.00 69.00 D 19 GILLESPIE#1-N. OF GILA BEND 12.00 69.00 D 20 GLENDALE-GLENDALE 12.00 230.00 D 21 GRAND CANYON-GRAND CANYON 12.00 69.00 D 22 GRANITE CREEK - CHINO VALLEY 69.00 T 23 GRANITE REEF - SCOTTSDALE 12.00 69.00 D 24 GRAY MOUNTAIN-S. OF CAMERON 12.00 69.00 D 25 GREENBRIER-GLENDALE 12.00 69.00 D 26 GREENWAY-GLENDALE 12.00 69.00 D 27 GREYBEARS-CHINO VALLEY 12.00 69.00 D 28 GRISWOLD-PHOENIX 12.00 69.00 D 29 HAMBLIN 7.20 69.00 D 30 HANKS-N. OF FLAGSTAFF 12.00 69.00 D 31 HAPPY VALLEY TEMP-PEORIA 12.00 69.00 D 32 HARBOR-PHOENIX 12.00 69.00 D 33 HARQUAHALA-TONOPAH 12.00 69.00 D 34 HASHKNIFE-HEBER 69.00 D 35 HATFIELD-PEORIA 12.00 69.00 D 36 HAVASU- PARKER 12.00 69.00 D 37 HAYDEN-HAYDEN 21.00 69.00 D 38 HAYES GULCH-GLOBE 21.00 69.00 D 39 HEARN-SURPRISE 12.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.3Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

HEDGEPETH HILLS-PHOENIX 12.00 69.00 D 1 HOHOKAM-TEMPE 12.00 69.00 D 2 HONEYWELL-PHOENIX 12.00 69.00 D 3 HOODOO WASH-YUMA 500.00 T 4 HORN-HORN 12.00 69.00 D 5 HOWARD-MESA 12.00 69.00 D 6 HUMBUG-PEORIA 12.00 69.00 D 7 HYDER-HYDER 12.00 69.00 D 8 INDIAN BEND-PHOENIX 12.00 69.00 D 9 INDIANOLA-PHOENIX 12.00 69.00 D 10 IVALON-YUMA 12.00 69.00 D 11 JACKSON STREET-PHOENIX 12.00 69.00 D 12 JAVELINA-SURPRISE 12.00 69.00 D 13JOMAX-SCOTTSDALE 12.00 69.00 D 14 KACHINA-KACHINA VILLAGE 12.00 69.00 D 15 KEAMS CANYON-W. OF KEAMS CANYON 21.00 69.00 D 16 KEARNY-KEARNY 21.00 D 17 KIRKLAND JUNCTION-SE. OF KIRKLAND 12.00 69.00 D 18 LAGUNA-YUMA 12.00 69.00 D 19 LE BARRON HILL-FLAGSTAFF 7.20 69.00 D 20 LEROUX-N. OF HOLBROOK 12.00 69.00 D 21 LEUPP JUNCTION-W. OF WINSLOW 21.00 69.00 D 22 LIBERTY IRON-PHOENIX 69.00 D 23 LINCOLN STREET (230kV)-PHOENIX 69.00 230.00 12.00 T 24 LINCOLN STREET NORTH-PHOENIX 12.00 69.00 D 25 LINCOLN STREET WEST-PHOENIX 12.00 69.00 D 26 LITCHFIELD-LITCHFIELD PARK 12.00 69.00 D 27 LOMA VISTA-PHOENIX 12.00 69.00 D 28 LONE PEAK-PHOENIX 69.00 230.00 T 29 LONE PEAK-PHOENIX 12.00 69.00 D 30 LONESOME VALLY-PRESCOTT 12.00 69.00 D 31 LOOKOUT-PHOENIX 12.00 69.00 D 32 MAGNOLIA - STANTON 7.20 69.00 D 33 MARINE AIR BASE-YUMA 12.00 69.00 D 34 MARINETTE-SUN CITY 12.00 69.00 D 35 MARTINEZ WASH-WICKENBURG 7.20 69.00 D 36 MAZATAL-RYE 12.00 69.00 D 37 MC GUIREVILLE-MC GUIREVILLE 12.00 69.00 D 38 MCCORMICK-SCOTTSDALE 12.00 69.00 D 39 MCDOWELL-PHOENIX 12.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.4Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

MCMICKEN-SURPRISE 12.00 69.00 D 1 MEADOWBROOK-PHOENIX 69.00 230.00 T 2 MEADOWBROOK-PHOENIX 12.00 69.00 D 3 MERIDIAN-GLENDALE 69.00 D 4 MERRILL-FLORENCE 12.00 69.00 D 5 METRO-PHOENIX 12.00 69.00 D 6 MILLER WASH-VALLE 7.20 69.00 D 7 MILLIGAN-ELOY 69.00 230.00 T 8 MILLIGAN TEMP-ELOY 12.00 69.00 D 9 MINGUS-JEROME 7.20 69.00 D 10 MITTRY 12.00 69.00 D 11 MOENKOPI-CAMERON 525.00 T 12 MOENKOPI-CAMERON 525.00 T 13 MONTE CRISTO-PHOENIX 12.00 69.00 D 14 MOON VALLEY-PHOENIX 12.00 69.00 D 15 MORGAN-PEORIA 230.00 525.00 34.50 T 16 MORRISTOWN-MORRISTOWN 12.00 69.00 D 17 MOUNTAIN VIEW-SUN CITY 12.00 69.00 D 18 MT. FLOYD-MT. FLOYD 12.00 4.16 D 19 MUMMY MOUNTAIN-PARADISE VALLEY 12.00 69.00 D 20 MUNDS PARK-S. OF FLAGSTAFF 21.00 69.00 D 21 MURAL-E. OF LOWELL 12.00 69.00 D 22 MURAL-E. OF LOWELL 69.00 115.00 T 23 NADASY-N. OF WILLIAMS 7.20 69.00 D 24 NAVAJO-PAGE 500.00 A,T 25 NAVAJO-PAGE 500.00 A,T 26 NAVAJO ARMY DEPOT-FLAGSTAFF 12.00 69.00 D 27 NEW RIVER-NEW RIVER 12.00 69.00 D 28 NEWMAN PARK-S. OF FLAGSTAFF 7.20 69.00 D 29 NORTH GILA-YUMA 500.00 T 30 NORTH GILA-YUMA 500.00 T 31 NORTH GILA-YUMA 69.00 345.00 T 32 NORTH VALLEY-PHOENIX 12.00 69.00 D 33 OAK CREAK-OAK CREEK 12.00 69.00 D 34 OBERLIN TEMP-WITTMAN 12.00 69.00 D 35 OCOTILLO-TEMPE 69.00 230.00 A,T 36 OCOTILLO-TEMPE A,T 37 OCOTILLO-TEMPE 69.00 A,T 38 OLD HOME MANOR-CHINO VALLEY 69.00 D 39 ORANGEWOOD-PHOENIX 12.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.5Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

ORMES-CORDES JUNCTION 4.16 2.40 D 1 OSBORNE TANK 12.00 69.00 D 2 PADRE - E. OF ANGELL 12.00 69.00 D 3 PALM VALLEY-GOODYEAR 69.00 230.00 T 4 PALM VALLEY-GOODYEAR 12.00 69.00 D 5 PALOMA-W. OF GILA BEND 12.00 69.00 D 6 PALOMINAS-PALOMINAS 12.00 69.00 D 7 PANDA - GILA BEND 230.00 A,T 8 PAPAGO BUTTE-SCOTTSDALE 12.00 69.00 D 9 PARADISE-PHOENIX 12.00 69.00 D 10 PARKS-PARKS 12.00 69.00 D 11 PATTERSON-OUT OF BUCKEYE 12.00 69.00 D 12 PATTON-OUT OF MORRISTON 12.00 69.00 D 13 PAULDEN-PAULDEN 12.00 69.00 D 14 PEBBLECREEK-GOODYEAR 12.00 69.00 D 15 PEORIA-PEORIA 12.00 69.00 D 16 PERRYVILLE-N.E. OF BUCKEYE 12.00 69.00 D 17 PICKET-SUPERIOR 12.00 115.00 D 18 PIMA-GOODYEAR 12.00 69.00 D 19 PINAL-GLOBE 69.00 115.00 T 20 PINAL-GLOBE 21.00 69.00 D 21 PINE SPRINGS-W. OF WILLIAMS 7.20 69.00 D 22 PINNACLE PEAK-PHOENIX 230.00 500.00 T 23 PINNACLE PEAK-PHOENIX 230.00 345.00 T 24 PINNACLE PEAK-PHOENIX 69.00 230.00 T 25 PIONEER-PHOENIX 12.00 69.00 D 26 PLANET-NE. OF PARKER 12.00 69.00 D 27 PLEASANT-GLENDALE 12.00 69.00 D 28 POLAND JUNCTION NW. OF MAYER 12.00 69.00 D 29 POLK-PHOENIX 12.00 69.00 D 30 POLLOCK-SW. OF ASHFORK 12.00 69.00 D 31 POPLAR WASH-PEEPLES VALLEY 7.20 69.00 D 32 PREACHER CANYON-PAYSON 69.00 345.00 T 33 PREACHER CANYON-PAYSON 21.00 69.00 D 34 PRESCOTT CHINO WELLS-CHINO VALEY 7.20 69.00 D 35 PRESCOTT CITY-PRESCOTT 12.00 69.00 D 36 PYRAMID PEAK-GLENDALE 12.00 69.00 D 37 QUAIL SPRINGS-SE. OF COTTONWOOD 12.00 69.00 D 38 QUARTZSITE-QUARTZSITE 12.00 69.00 D 39 QUECHAN-YUMA 12.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.6Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

RACEWAY-PEORIA 69.00 230.00 T 1 RAINBOW VALLEY-SE. OF BUCKEYE 12.00 69.00 D 2 RAINTREE-SCOTTSDALE 12.00 69.00 D 3 RAMON ASO-RED LAKE, N. OF WILLIAMS 12.40 69.00 D 4 RAWHIDE-SCOTTSDALE 12.00 69.00 D 5 REACH-SCOTTSDALE 69.00 230.00 T 6 RED LAKE-E. OF WILLIAMS 21.00 69.00 D 7 REDONDO-YUMA 12.00 69.00 D 8 REIDHEAD-SNOWFLAKE 7.20 69.00 D 9 RINCON-WICKENBURG 7.20 69.00 D 10 RIO VISTA-SUN CITY 12.00 69.00 D 11 RIVERSIDE-YUMA 12.00 69.00 D 12 ROAD RUNNER-PHOENIX 12.00 69.00 D 13 ROBBINS BUTTE-OUT OF BUCKEYE 7.20 69.00 D 14 ROCK SPRINGS-ROCK SPRINGS 12.00 69.00 D 15 ROGERS LAKE-SW. OF FLAGSTAFF 7.20 69.00 D 16 ROSE GARDEN-PHOENIX 12.00 69.00 D 17 ROUND VALLEY 230.00 T 18 SADDLE MTN-W. OF TONOPAH 12.00 69.00 D 19 SADDLEBROOK-ORACLE JUNCTION 115.00 T 20 SAGE VALLEY-VALLE 12.00 69.00 D 21 SAGUARO 525kV-RED ROCK 115.00 500.00 A,T 22 SAGUARO 230kv-RED ROCK 115.00 230.00 A,T 23 SAGUARO 115kV-RED ROCK 12.50 115.00 A,T 24 SALOME-S.E. OF SALOME 12.00 69.00 D 25 SAN LUIS-SAN LUIS 12.00 69.00 D 26 SAN LUIS (MEXICO CONN.)-SAN LUIS 34.50 69.00 D 27 SAN MANUEL-SAN MANUEL 46.00 115.00 D 28 SAN MANUEL-SAN MANUEL 12.00 115.00 D 29 SAN PEDRO-W. OF DOUGLAS 12.00 69.00 D 30 SANDVIG-FLAGSTAFF 12.00 69.00 D 31 SANGUINETTI-YUMA 69.00 T 32 SANTA ROSA-SE. OF MARICOPA 69.00 230.00 T 33 SARIVAL-GOODYEAR 12.00 69.00 D 34 SEDONA-SEDONA 12.00 69.00 D 35 SELIGMAN COMPRESSER STATION-SELIGMAN 4.20 230.00 D 36 SEXTON-E. OF STANFIELD 69.00 D 37 SHAW-PHOENIX 12.00 69.00 D 38 SHEA-SCOTTSDALE 12.00 69.00 D 39 SHERMAN STREET-PHOENIX 12.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.7Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

SHOW LOW-SHOW LOW 12.00 69.00 D 1 SHOW LOW-SHOW LOW 69.00 D 2 SHUMWAY-SHOW LOW 12.00 69.00 D 3 SHUMWAY-SHOW LOW 69.00 D 4 SKUNK CREEK-GLENDALE 12.00 69.00 D 5 SNOWFLAKE-SNOWFLAKE 12.00 69.00 D 6 SOLANA-GILA BEND 12.00 69.00 D 7 SONORA 12.00 69.00 D 8 SOUTH O'NEIL - YUMA 69.00 T 9 SPANISH GARDENS-SURPRISE 12.00 69.00 D 10 SPIDER WEB-S. OF GRAY MOUNTAIN 2.30 69.00 D 11 STAGECOACH-SCOTTSDALE 12.00 69.00 D 12 STANTON-S. OF YARNELL 7.20 69.00 D 13 STARDUST-SUN CITY WEST 12.00 69.00 D 14 STOUT-PHOENIX 12.00 69.00 D 15 STRAWBERRY-STRAWBERRY 21.00 69.00 D 16 STURM RUGER-N. OF PRESCOTT 4.16 69.00 D 17 STURM RUGER-N. OF PRESCOTT 12.40 69.00 D 18 SUGARLOAF-SNOWFLAKE 69.00 525.00 T 19 SUNDOG-PRESCOTT 12.00 69.00 D 20 SUNNYSLOPE-PHOENIX 69.00 230.00 T 21 SUNNYSLOPE-PHOENIX 12.00 69.00 D 22 SUNSHINE-WINSLOW 12.00 69.00 D 23 SURPRISE-SURPRISE 69.00 230.00 T 24 SURPRISE-SURPRISE 12.00 69.00 D 25 SWITZER CANYON-FLAGSTAFF 12.00 69.00 D 26 SYCAMORE-DUGAS 7.20 69.00 D 27TABLE MESA-NEW RIVER 7.20 69.00 D 28TAPCO-E. OF CLARKDALE 2.40 69.00 D 29TARTESSO-BUCKEYE 12.00 69.00 D 30TAT MOMOLI-CASA GRANDE 230.00 T 31 TEMPE-TEMPE 12.00 69.00 D 32TENTH STREET-YUMA 12.00 69.00 D 33THAYER-THAYER 12.00 69.00 D 34THIRTY-SECOND STREET-YUMA 12.00 69.00 D 35THOMPSON PEAK-SCOTTSDALE 12.00 69.00 D 36TOLTEC-ARIZONA CITY 12.00 69.00 D 37TONALEA-TUBA CITY 12.00 69.00 D 38TONOPAH-TONOPAH 12.00 69.00 D 39TONTO-PAYSON 21.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.8Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

TONTO-PAYSON D 1 TUBA CITY-TUBA CITY 12.00 69.00 D 2TURF-PHOENIX 12.00 69.00 D 3TUSAYAN-TUSAYAN 12.00 69.00 D 4TUSAYAN-TUSAYAN 69.00 D 5TUTHILL-BUCKEYE 12.00 69.00 D 6TWENTY-THIRD STREET-PHOENIX 12.00 69.00 D 7TWIN ARROWS - FLAGSTAFF 69.00 T 8 UNION HILLS-PHOENIX 12.00 69.00 D 9 UTTING-SE. OF BOUSE 12.00 69.00 D 10VALENCIA-BUCKEYE 12.00 69.00 D 11 VALLE-WILLIAMS 21.00 69.00 D 12 VALLEY FARMS-FLORENCE 69.00 115.00 T 13VALLEY FARMS-FLORENCE 12.00 69.00 D 14VARNEY-SURPRISE 12.00 69.00 D 15VERDE-CLARKDALE 69.00 230.00 T 16VICKSBURG-S. OF VICKSBURG JUNCTION 12.00 69.00 D 17VISTA-CASA GRANDE 12.00 69.00 D 18WADDELL-SURPRISE 12.00 69.00 D 19WALDRIP - YUMA 69.00 T 20WATSON-BUCKEYE 12.00 69.00 D 21 WELCH-E. OF ASHBROOK 2.40 69.00 D 22 WELLFIELD - PRESCOTT VALLEY 69.00 D 23WEST PHOENIX-PHOENIX 69.00 230.00 T 24WEST PHOENIX-PHOENIX 12.40 69.00 D 25WESTBROOK-PEORIA 12.00 69.00 D 26WESTWING-SUN CITY 230.00 525.00 T 27WESTWING-SUN CITY 525.00 T 28WESTWING-SUN CITY 525.00 T 29WESTWING-SUN CITY 230.00 T 30WESTWING-SUN CITY 12.00 69.00 T 31 WESTWING-SUN CITY 69.00 230.00 T 32 WHITE SPAR-PRESCOTT 12.00 69.00 D 33WHITE TANKS-AVONDALE 69.00 230.00 T 34WHY-WHY 21.00 69.00 D 35WICKENBURG-WICKENBURG 12.00 69.00 D 36WILD BURRO-NEW RIVER 7.20 69.00 D 37WILD FLOWER-GOODYEAR 12.00 69.00 D 38WILHOIT-PRESCOTT 12.00 69.00 D 39WILLIAMS-WILLIAMS 12.00 69.00 D 40

FERC FORM NO. 1 (ED. 12-96) Page 426.9Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 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).

WILLOW LAKE-PRESCOTT 115.00 230.00 T 1 WILLOW LAKE-PRESCOTT 69.00 230.00 T 2 WINONA-WINONA 12.00 69.00 D 3WINSLOW-WINSLOW 12.00 69.00 D 4WINTERSBURG-WINTERSBURG 12.00 69.00 D 5WOODRUFF-HOLBROOK 21.00 69.00 D 6WOODY MOUNTAIN-FLAGSTAFF 12.00 69.00 D 7WUPATKI-FLAGSTAFF 12.00 69.00 D 8YALE-PHOENIX 12.00 69.00 D 9YARNELL-YARNELL 12.00 69.00 D 10YAVAPAI-CHINO VALLEY 230.00 525.00 T 11 YAVAPAI-CHINO VALLEY 69.00 230.00 T 12YORKSHIRE-PHOENIX 12.00 69.00 D 13YUCCA-YUMA 69.00 161.00 T 14YUMA PALMS TEMP-YUMA 12.00 69.00 D 15 ZENIFF-SNOWFLAKE 69.00 D 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

FERC FORM NO. 1 (ED. 12-96) Page 426.10Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

83 2 1 2 83 2 3 188 1 48 1 capacitor bank-69kv 4 20 1 5 1 capacitor bank-69kv 5 9 1 6 48 1 capacitor bank-69kv 7 83 2 8 20 1 9 57 2 14 1 capacitor bank-69kv 10 20 1 4 2 capacitor bank-12kv 11 12 1 12 83 2 22 1 capacitor bank-69kv 13 42 1 14 9 1 15 9 1 16 16 1 17 3 1 18 28 1 19 40 4 capacitor bank-115kv 20 20 1 14 1 capacitor bank-69kv 21 83 2 10 2 capacitor bank -12kv 22 40 2 22 2 capacitor bank-69kv 23 20 1 24 83 2 25 14 1 capacitor bank-69kv 26 27 31 1 28 9 1 29 9 1 30 15 1 31 13 1 32 20 1 33 83 2 34 267 2 35 20 1 36 83 2 37 7 1 10 1 capacitor bank-69kv 38 167 4 39 522 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

125 3 48 1 capacitor bank-69kv 1 41 1 2 125 3 3

2 1 4 83 2 5 40 2 14 4 capacitor bank-12kV 6 100 1 7 50 1 8 20 1 9 41 1 10 11 83 2 12 83 2 13 83 2 14 40 2 15 16 38 2 17 1002 6 1 395 1 capacitor bank 500kv 18 125 4 reactor 500kV 19 203 1 870 2 capacitor bank 345kv 20 143 1 21 150 2 22

9 1 23 83 2 7 2 capacitor bank -12kV 24 40 2 7 2 capacitor bank -12kV 25 355 2 26 40 2 36 2 capacitor bank-69kv 27 83 2 14 1 cap bank 69kv 28 83 2 29 1 cap bank 69kv 29 9 1 30 83 2 31 32 33 41 2 12 4 capacitor bank-12kv 34 20 1 35 20 1 7 1 capacitor bank 69kv 36 40 2 37 40 2 11 1 capacitor bank-69kV 38 6 2 capacitor bank-12kV 39 125 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

355 2 1 20 1 14 2 capacity bank-69kV 2 20 1 3 83 2 7 2 capacitor bank-12kv 4 29 1 capacitor bank 69kV 5 3 1 6 83 2 7 2 capacitor bank -12kv 7 29 1 capacitor - 69kv 8 564 3 9 125 3 48 1 capacitor bank-69kV 10 18 1 11 40 2 12 83 2 10 2 capacitor bank-12kv 13 14 4 1 15 83 2 10 2 capacitor bank-12kv 16 40 2 14 1 capacitor bank-69kv 17 83 2 7 2 capacitor bank-12kv 18 20 1 19 42 1 20 83 2 4 2 capacitor bank-12kv 21 123 3 48 1 capacitor bank-69kv 22 22 3 capacitor bank-69kv 23 1 24 269 3 4 190 1 shunt reactor 25 372 1 capacitor bank-525kv 26 83 2 7 2 capacitor bank-12kV 27 125 3 28 100 2 29 41 1 5 2 capacitor bank-12kV 30 41 1 4 1 capacitor bank-12kV 31 41 1 14 2 capacitor bank-12kV 32 20 1 33 376 2 34 83 2 48 1 capacitor bank-69kv 35 40 2 36 83 2 37 41 1 4 1 capacitor bank-12kv 38 83 2 10 4 capacitor bank-12kv 39 41 1 10 4 capacitor bank-12kv 40

FERC FORM NO. 1 (ED. 12-96) Page 427.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

1 20 1 2 83 2 29 1 capacitor bank-69kv 3 1 2 4 20 1 7 1 capacitor bank-69kv 5 20 1 22 2 capacitor bank-69kv 6 83 2 29 2 capacitor bank-69kv 7 83 2 7 2 capacitor bank-12kv 8 1025 3 1 125 3 reactor 525kv 9 1325 2 1 155 4 reactor 345kV 10 106 2 11 167 4 10 4 capacitor bank 12kv 12 10 1 13 42 14 188 1 15 41 1 16 200 2 17 40 2 30 2 capacitor bank-69kv 18 83 2 7 2 capacitor bank 12kv 19 20 1 14 1 capacitor bank-69kv 20 100 2 21

9 1 22 23 41 1 24 1 2 25 41 1 26 125 3 11 3 capacitor bank-12kV 27 20 1 28 41 1 29 1 30 1 31 18 1 32 125 3 33 10 1 34 35 41 1 36 20 1 37 5 6 38 20 1 39 83 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.3Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

83 2 29 1 capacitor bank-69kv 1 20 1 5 2 capacitor bank-12kv 2 83 2 3 4 10 1 5 1 6 40 2 7 9 1 8 83 2 7 2 capacitor bank-12kV 9 125 3 10 40 2 11 125 3 12 83 2 13 41 1 14 9 1 15 9 1 16 17 9 1 18 36 2 29 2 capacitor bank-69kV 19 1 20 20 1 21 6 1 22 23 188 1 24 83 2 35 1 capacitor bank-69kV 25 167 4 19 8 capacitor bank-12kv 26 83 2 27 83 2 28 376 2 29 41 1 30 40 2 31 83 2 32 1 33 83 2 7 2 capacitor bank-12kV 34 83 2 35 1 36 20 1 37 16 1 38 83 2 39 83 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.4Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

83 2 1 188 1 2 125 3 48 1 capacitor bank-69kV 3 4 41 1 14 2 capacitor bank-69kv 5 125 3 10 4 capacitor bank -12kv 6 1 7 188 1 1 8 20 1 9 1 2 10 7 1 11 1,540 4 capacitor bank 525kv 12 646 10 shunt reactor 525kv 13 83 2 14 83 2 15 600 1 16

9 1 11 1 capacitor bank-69kv 17 83 2 48 1 capacitor bank-69kv 18 3 1 19 83 2 20 9 1 21 9 1 10 4 capacitor bank-12kv 22 50 1 23 1 24 382 2 shunt reactor-525kv 25 1,207 2 capacitor bank 525kV 26 6 1 27 20 1 28 1 29 184 4 shunt reactor 30 489 1 capacitor bank 500kv 31 509 6 1 32 83 2 33 40 2 10 2 capacitor bank 12kv 34 16 1 35 355 2 36 318 2 capacitor bank 230kv 37 48 1 capacitor bank 69kv 38 39 125 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.5Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

4 1 1 1 2 1 2 3 188 1 1 4 41 1 5 20 1 6 20 1 7 8 40 2 9 125 3 7 2 capacitor bank-12kV 10 5 1 11 16 1 12 9 1 13 20 1 14 41 1 15 83 2 16 20 1 17 13 1 18 36 2 19 84 1 20 41 1 21 1 22 1872 3 190 1 shunt reactor - 525V 23 2025 3 1 24 752 4 159 3 capacitor bank 230kv 25 83 2 26 4 1 27 20 1 28 9 1 29 40 2 29 2 capacitor bank-69kV 30 2 3 31 1 1 32 162 2 33 16 1 34 8 6 1 35 40 2 36 41 1 37 40 2 22 2 capacitor bank-69kv 38 16 1 39 83 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.6Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

188 1 1

9 1 2 83 2 3 1 1 4 83 2 5 376 2 48 1 capacitor bank-69kV 6 4 1 7 20 1 8 1 9 1 10 83 2 11 9 1 12 83 2 13 1 3 14 16 1 15 1 16 83 2 17 18 20 1 7 1 capacitor bank-69kv 19 20 1 21 1450 2 42 1 reactor 525kV 22 896 2 1 23 22 1 2 49 2 capacitor bank-115kv 24 20 1 7 2 capacitor bank-69kv 25 40 2 7 1 capacitor bank-69kv 26 20 1 4 1 capacitor bank-34.5k 27 65 4 28 138 5 112 4 capacitor bank-115kV 29 6 1 30 32 2 31 32 355 2 94 2 capacitor bank 230kv 33 83 2 29 2 capacitor bank-69kV 34 40 2 35 16 1 36 37 83 2 38 83 2 39 83 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.7Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

40 2 10 4 capacitor bank-12kv 1 29 3 capacitor bank-69kV 2 9 1 6 2 capacitor bank-12kv 3 14 2 capacitor bank-69kV 4 83 2 5 40 2 6 20 1 7 1 2 8 9 83 2 10 1 11 83 2 12 1 1 13 83 2 14 83 2 15 9 1 16 5 3 17 20 1 18 269 3 1 14 1 capacitor bank-69kv 19 40 2 7 1 capacitor bank-69kv 20 355 2 21 83 2 43 1 capacitor bank-69kv 22 2 3 23 564 3 53 1 capacitor bank-69kv 24 125 3 25 32 2 26 1 27 1 28 2 29 9 1 30 31 83 2 32 40 2 33 20 1 34 83 2 35 83 2 36 41 1 14 2 capacitor bank 69kv 37 1 2 38 16 1 10 1 capacitor bank-69kv 39 40 2 7 1 capacitor bank-69kv 40

FERC FORM NO. 1 (ED. 12-96) Page 427.8Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

10 4 capacitor bank-21.6 1 20 1 6 2 capacitor bank - 12V 2 83 2 3 9 1 7 6 capacitor bank-12kv 4 7 1 capacitor bank-69kV 5 41 1 6 83 2 7 8 83 2 9 9 1 10 40 2 11 2 3 12 188 1 13 41 1 14 41 1 15 200 2 29 4 capacitor bank-69kV 16 20 1 17 83 2 14 4 capacitor bank-12kv 18 41 1 19 20 83 2 21 1 22 20 1 23 564 3 35 1 capacitor bank-69kv 24 166 3 10 4 capacitor bank-12kV 25 41 1 26 4500 9 2 27 571 3 reactor 525kV 28 390 1 capacitor bank 525kv 29 212 2 reactor 230kV 30 41 1 31 376 2 32 40 2 12 4 capacitor bank-12kv 33 376 2 34

3 1 35 36 2 12 1 capacitor bank-69kv 36 1 37 83 2 38 3 1 39 17 2 6 1 capacitor bank-69kv 40

FERC FORM NO. 1 (ED. 12-96) Page 427.9Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 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.

166 2 25 1 reactor 230kV 1 376 2 2

3 1 3 20 2 4 18 1 5 4 1 6 18 1 7 1 capacitor bank 69kv 7 1 8 83 2 10 4 capacitor bank-12kv 9 9 1 10 672 2 11 100 1 12 20 1 13 84 1 25 1 capacitor bank-69kv 14 20 1 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

FERC FORM NO. 1 (ED. 12-96) Page 427.10

### Schedule Page: 426 Line No.: 1 Column: a STATEMENT OF CO-OWNERSHIP AS DESCRIBED IN INSTRUCTION #6, PAGE 427 AND AS NOTED ON PAGE 426. NONE OF THE CO-OWNERS IS AN ASSOCIATED COMPANY (A) CO-OWNERSHIP ON: CEDAR MOUNTAIN CHOLLA SWITCHYARD HOODOO WASH FOUR CORNERS SWITCHYARD MORGAN SUBSTATION NAVAJO SWITCHYARD NORTH GILA PINNACLE PEAK WESTWING 525KV SWITCHYARD WESTWING 230KV SWITCHYARD (1) CO-OWNERS OF CEDAR MOUNTAIN ARE SALT RIVER PROJECT, TUCSON ELECTRIC POWER COMPANY, UNITED STATES (2) CO-OWNER OF CHOLLA SWITCHYARD IS PACIFICORP (3) CO-OWNERS OF HOODOO WASH ARE IMPERIAL IRRIGATION DISTRICT, SAN DEIGO GAS & ELECTRIC (4) CO-OWNERS OF FOUR CORNER SWITCHYARD ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, PUBLIC SERVICE OF NEW MEXICO, SOUTHERN CALIFORNIA EDISON, AND TUCSON ELECTRIC POWER COMPANY (5) CO-OWNER OF MORGAN SUBSTATION IS SALT RIVER PROJECT (6) CO-OWNERS OF NAVAJO SWITCHYARD ARE SALT RIVER PROJECT, NEVADA POWER COMPANY, UNITED STATES, TUCSON ELECTRIC POWER COMPANY, AND LOS ANGELES DEPARTMENT OF WATER AND POWER (7) CO-OWNERS OF NORTH GILA SUBSTATION ARE SAN DIEGO GAS & ELECTRIC AND IMPERIAL IRRIGATION DISTRICT (8) CO-OWNER OF PINNACLE PEAK 500KV SUBSTATION AND 230KV NORTH SUBSTATION IS SALT RIVER PROJECT (9) CO-OWNERS OF WESTWING 525KV SWITCHYARD ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, TUCSON ELECTRIC POWER COMPANY, PUBLIC SERVICE COMPNANY OF NEW MEXICO, AND UNITED STATES (10) CO-OWNERS OF WESTWING 230KV SWITCHYARD ARE SALT RIVER PROJECT, EL PASO ELECTRIC COMPANY, PUBLIC SERVICE COMPANY OF NEW MEXICO, AND UNITED STATES (B) EXPENSES FOR THE OPERATION, MAINTENANCE, AND RENTS ARE NOT SEGREGATED IN THE COMPANY'S BOOKS FOR EACH SUBSTATION (C) SUBSTATIONS THAT APS DOES NOT OWN THE MAJORITY PORTION AND IS NOT OPERATING AGENT ARE NOT LISTED ON THIS REPORT Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

### Schedule Page: 426 Line No.: 1 Column: b A-ATTENDED D-DISTRIBUTION T-TRANSMISSION Schedule Page: 426 Line No.: 1 Column: c VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 Column: d VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 Column: e VOLTAGE IS EXPRESSED IN KV Schedule Page: 426 Line No.: 1 Column: k CAPACITY IS EXPRESSED IN MVAR Schedule Page: 426.2 Line No.: 24 Column: f 0.25 MVa Schedule Page: 426.3 Line No.: 4 Column: f 

## 0.3 MVa Schedule Page: 426.3 Line No.: 25 Column: f 

## 0.7 MVa Schedule Page: 426.3 Line No.: 30 Column: f 0.1 MVa Schedule Page: 426.3 Line No.: 31 Column: f 0.1 MVa Schedule Page: 426.4 Line No.: 6 Column: f 0.3 MVa Schedule Page: 426.4 Line No.: 20 Column: f 

## 0.1 MVa Schedule Page: 426.4 Line No.: 33 Column: f 

## 0.1 MVa Schedule Page: 426.4 Line No.: 36 Column: f 

## 0.1 MVa Schedule Page: 426.5 Line No.: 7 Column: f 

## 0.1 MVa Schedule Page: 426.5 Line No.: 24 Column: f 

## 0.1 MVa Schedule Page: 426.5 Line No.: 29 Column: f 

## 0.1 MVa Schedule Page: 426.6 Line No.: 2 Column: f 

## 0.1 MVa Schedule Page: 426.6 Line No.: 22 Column: f 

## 0.1 MVa Schedule Page: 426.7 Line No.: 9 Column: f 

## 0.1 MVa Schedule Page: 426.7 Line No.: 10 Column: f 

## 0.01 MVa Schedule Page: 426.7 Line No.: 16 Column: f 

## 0.025 MVa Schedule Page: 426.7 Line No.: 21 Column: f 

## 0.25 MVa Schedule Page: 426.8 Line No.: 11 Column: f 

## 0.025 MVa Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2

### Schedule Page: 426.8 Line No.: 27 Column: f 

## 0.1 MVa Schedule Page: 426.8 Line No.: 28 Column: f 

## 0.25 MVa Schedule Page: 426.8 Line No.: 29 Column: f 

## 0.2 MVa Schedule Page: 426.9 Line No.: 22 Column: f 

## 0.15 MVa Schedule Page: 426.9 Line No.: 37 Column: f 

## 0.25 MVa Schedule Page: 426.10 Line No.: 8 Column: f 

## 0.1 MVa Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.3Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES Arizona Public Service Company X 04/10/2013 2012/Q4

Line No. Description of the Non-Power Good or Service Name of

(c) (b) (a) (d) Associated/Affiliated Company Account Charged or

Credited Amount Credited 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.Charged or

1 Non-power Goods or Services Provided by Affiliated 2 Common stock dividends 222,200,000 Pinnacle West Capital Corporation 438 3 Share of estimated income taxes 1,196,491 Pinnacle West Capital Corporation 236 4 Share of withholding and payroll taxes 224,633,281 Pinnacle West Capital Corporation 236,241,408 5 Share of other post retirement benefits 6 contributions 86,733,806 Pinnacle West Capital Corporation 228.3 7 Share of employee benefits 8 (excluding pension & OPEB contributions) 131,538,698 Pinnacle West Capital Corporation 228.3,925,926 9 Employee payroll deductions 58,403,066 Pinnacle West Capital Corporation 143,232,242 10 Shared services 25,554,514 Pinnacle West Capital Corporation various 11 Compensation paid in stock 36,538,598 Pinnacle West Capital Corporation various 12 13 14 15 16 17 18 19 20 Non-power Goods or Services Provided for Affiliate 21 Share of other post retirement benefits 22 reimbursement 30,375,306 Pinnacle West Capital Corporation 228.3 23 Shared services 11,336,921 Pinnacle West Capital Corporation various 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42

FERC FORM NO. 1 (New) Page 429 FERC FORM NO. 1-F (New)

### Schedule Page: 429 Line No.: 4 Column: d 

## Includes employer share of FICA allocated at 7% Schedule Page: 429 Line No.: 8 Column: d 

## Includes benefits allocated at 37% & injuries and damages allocated at 1% Schedule Page: 429 Line No.: 10 Column: d 

## Includes corporate allocations at 100.0% and governance allocations at 99.5% Schedule Page: 429 Line No.: 11 Column: d 

## Includes governance allocations at 99.5% Name of Respondent

Arizona Public Service Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr)

04/10/2013 

### Year/Period of Report

2012/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

### INDEX

Schedule Page No.

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

### INDEX (continued)

Schedule Page No. 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

Index 2 FERC FORM NO. 1 (ED. 12-95)

### INDEX (continued)

Schedule Page No.

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

Index 3 FERC FORM NO. 1 (ED. 12-95)

### INDEX (continued)

Schedule Page No. 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

Index 4 FERC FORM NO. 1 (ED. 12-90)

### INDEX (continued)

Schedule Page No.

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

Index 5 FERC FORM NO. 1 (ED. 12-90)