THIS FILING IS

Item 1: An Initial (Original)

Submission

X OR Resubmission No. ____

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

Arizona Public Service Company End of 2012/Q4
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) The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions,

explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are

reported.

 “In connection with our regular examination of the financial statements of for the year ended on which we have

reported separately under date of , we have also reviewed schedules 

of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for

conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its

applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such

tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

 Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph

(except as noted below) conform in all material respects with the accounting requirements of the Federal Energy

Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” 

The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. 

Describe the discrepancies that exist. 

(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. 

To further that effort, new selections, “Annual Report to Stockholders,” and “CPA Certification Statement” have been

added to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on the

Commission’s website at http://www.ferc.gov/help/how-to.asp. 

(g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of

FERC Form 1 and 3-Q free of charge from http://www.ferc.gov/docs-filing/eforms/form-1/form-1.pdf and

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

IV. When to Submit:

FERC Forms 1 and 3-Q must be filed by the following schedule:

FERC FORM 1 & 3-Q (ED. 03-07) ii
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and

b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. §

141.400). 

V. Where to Send Comments on Public Reporting Burden.

 The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144

hours per response, including the time for reviewing instructions, searching existing data sources, gathering and

maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for

the FERC Form 3-Q collection of information is estimated to average 150 hours per response. 

 Send comments regarding these burden estimates or any aspect of these collections of information, including

suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC

20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of

Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory

Commission). No person shall be subject to any penalty if any collection of information does not display a valid control

number (44 U.S.C. § 3512 (a)).

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

Arizona Public Service Company End of

03 Previous Name and Date of Change (if name changed during year)

04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

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 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

LIST OF SCHEDULES (Electric Utility)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 1 General Information 101

 2 Control Over Respondent 102

 3 Corporations Controlled by Respondent 103

 4 Officers 104

 5 Directors 105

 6 Information on Formula Rates 106(a)(b)

 7 Important Changes During the Year 108-109

 8 Comparative Balance Sheet 110-113

 9 Statement of Income for the Year 114-117

 10 Statement of Retained Earnings for the Year 118-119

 11 Statement of Cash Flows 120-121

 12 Notes to Financial Statements 122-123

 13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)

 14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201

 15 Nuclear Fuel Materials 202-203

 16 Electric Plant in Service 204-207

 17 Electric Plant Leased to Others 213

 18 Electric Plant Held for Future Use 214

 19 Construction Work in Progress-Electric 216

 20 Accumulated Provision for Depreciation of Electric Utility Plant 219

 21 Investment of Subsidiary Companies 224-225

 22 Materials and Supplies 227

 23 Allowances 228(ab)-229(ab)

 24 Extraordinary Property Losses 230

 25 Unrecovered Plant and Regulatory Study Costs 230

 26 Transmission Service and Generation Interconnection Study Costs 231

 27 Other Regulatory Assets 232

 28 Miscellaneous Deferred Debits 233

 29 Accumulated Deferred Income Taxes 234

 30 Capital Stock 250-251

 31 Other Paid-in Capital 253

 32 Capital Stock Expense 254

 33 Long-Term Debt 256-257

 34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261

 35 Taxes Accrued, Prepaid and Charged During the Year 262-263

 36 Accumulated Deferred Investment Tax Credits 266-267

FERC FORM NO. 1 (ED. 12-96) Page 2
LIST 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 37 Other Deferred Credits 269

 38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273

 39 Accumulated Deferred Income Taxes-Other Property 274-275

 40 Accumulated Deferred Income Taxes-Other 276-277

 41 Other Regulatory Liabilities 278

 42 Electric Operating Revenues 300-301

 43 Regional Transmission Service Revenues (Account 457.1) 302

 44 Sales of Electricity by Rate Schedules 304

 45 Sales for Resale 310-311

 46 Electric Operation and Maintenance Expenses 320-323

 47 Purchased Power 326-327

 48 Transmission of Electricity for Others 328-330

 49 Transmission of Electricity by ISO/RTOs 331

 50 Transmission of Electricity by Others 332

 51 Miscellaneous General Expenses-Electric 335

 52 Depreciation and Amortization of Electric Plant 336-337

 53 Regulatory Commission Expenses 350-351

 54 Research, Development and Demonstration Activities 352-353

 55 Distribution of Salaries and Wages 354-355

 56 Common Utility Plant and Expenses 356

 57 Amounts included in ISO/RTO Settlement Statements 397

 58 Purchase and Sale of Ancillary Services 398

 59 Monthly Transmission System Peak Load 400

 60 Monthly ISO/RTO Transmission System Peak Load 400a

 61 Electric Energy Account 401

 62 Monthly Peaks and Output 401

 63 Steam Electric Generating Plant Statistics 402-403

 64 Hydroelectric Generating Plant Statistics 406-407

 65 Pumped Storage Generating Plant Statistics 408-409

 66 Generating Plant Statistics Pages 410-411

FERC FORM NO. 1 (ED. 12-96) Page 3
LIST 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 67 Transmission Line Statistics Pages 422-423

 68 Transmission Lines Added During the Year 424-425

 69 Substations 426-427

 70 Transactions with Associated (Affiliated) Companies 429

 71 Footnote Data 450

Stockholders' Reports Check appropriate box:

X Two copies will be submitted

No annual report to stockholders is prepared

FERC FORM NO. 1 (ED. 12-96) Page 4
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) PAGE 101
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.

FERC FORM NO. 1 (ED. 12-96) Page 102
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

(a) (b) (c)

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.

 1 Bixco, Inc. Conducts exploration 100

 2 activities for gas, oil, and

 3 coal for possible use in APS

 4 utility operations - Inactive

 5

 6 APS Foundation, Inc. A non-profit corporation 100

 7 which makes distributions

 8 to charitable organizations

 9

 10 Axiom Power Solutions, Inc. A corporation which is 100

 11 engaged in the sales of

 12 security and energy

 13 management systems -

 14 Inactive

 15

 16 PWENewco, Inc. Organized primarily to own 100

 17 real and personal property

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

FERC FORM NO. 1 (ED. 12-96) Page 103
Name 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

(a) (b) (c)

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.

 1 Chief Executive Officer Donald E. Brandt 1,146,000

 2

 3 President and Chief Operating Officer Donald G. Robinson 685,000

 4

 5 Vice President, Controller and Chief Accounting Officer Denise R. Danner 285,000

 6

 7 Vice President, Resource Management Patrick Dinkel 253,000

 8

 9 Executive Vice President and Chief Nuclear Officer Randall K. Edington 900,000

 10

 11 Executive Vice President and General Counsel David P. Falck 487,000

 12

 13 Vice President, Energy Delivery Daniel T. Froetscher 285,000

 14

 15 Senior Vice President, Customers and Regulation Jeffrey B. Guldner 315,000

 16

 17 Executive Vice President and Chief Financial Officer James R. Hatfield 515,000

 18

 19 Vice President, Communications John S. Hatfield 258,000

 20

 21 Vice President and Chief Customer Officer Tammy D. McLeod 252,000

 22

 23 Vice President and Treasurer Lee R. Nickloy 255,000

 24

 25 Executive Vice President, Operations Mark A. Schiavoni 435,000

 26

 27 Senior Vice President, Human Resources and Ethics Lori S. Sundberg 333,000

 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) X An 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
Name 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 No. (a) (b)

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.

 1 Donald E. Brandt, Chairman and CEO Phoenix, Arizona

 2

 3 Edward N. Basha, Jr Chandler, Arizona

 4

 5 Michael L. Gallagher Phoenix, Arizona

 6

 7 Roy A. Herberger, Jr. Phoenix, Arizona

 8

 9 Dale E. Klein Austin, Texas

 10

 11 Susan Clark - Johnson Paradise Valley, Arizona

 12

 13 Humberto S. Lopez Tucson, Arizona

 14

 15 Kathryn L. Munro La Jolla, California

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 17 Bruce J. Nordstrom Flagstaff, Arizona

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 19 Denis A. Cortese Fountain Hills, Arizona

 20

 21 Note: Currently there is no Executive

 22 Committee of the Board of Directors

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FERC FORM NO. 1 (ED. 12-95) Page 105
Name 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

 1 FERC Electric Tariff, Volume 2 ER10-1264

 2 FERC Electric Tariff, Volume 5 ER09-1402

 3 FERC Electric Rate Schedule No. 182 ER10-1386

 4 FERC Electric Tariff, Volume 6 ER09-1349

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FERC FORM NO. 1 (NEW. 12-08) Page 106
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) X An 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
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No. Accession No. \ Filed Date

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

X No

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

 1 20120514-5095 05/14/2012 ER11-3638 See FootnoteFERC Electric Tariff, Volume 2

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FERC FORM NO. 1 (NEW. 12-08) Page 106a
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) X An 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
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of 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.

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FERC FORM NO. 1 (NEW. 12-08) Page 106b
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) X An 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) X An 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) X An 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) X An 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) X An 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 113th Congress will consider a climate change bill. In the event climate change

legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a

variety of factors, none of which can be fully known until a law is enacted and the specifics of the resulting program

are established. These factors include the terms of the legislation with regard to allowed 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) X An 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 

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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

Kivalina plaintiffs’ 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 in Kivalina is 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

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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 SO2 removal 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” NOx emissions 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 NOx controls 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 NOx emissions. 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 NOx controls 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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(2) A Resubmission

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Year/Period of Report

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IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

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 NOx emission 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. EPA issued 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

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IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.10
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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IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.11
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 Plant Sites. Certain properties which APS now owns or which were previously owned

by it or its corporate predecessors were at one time sites of, or sites associated with, manufactured gas plants. APS

is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse

effect on its financial position, results of operations or cash flows.

Name of Respondent

Arizona Public Service Company 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

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Year/Period of Report

2012/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

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 is continuing to work with area stakeholders to implement agreements to

minimize the effect, if any, on future operations of the plant. The effect of the drought cannot be fully assessed at

this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely

affect the amount of power available, or the price thereof, from Four Corners.

Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous

court actions, which, in addition to future supply conditions, have the potential to impact APS 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

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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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IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

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 

This Report is:

(1) X An 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 109.15
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 

This Report is:

(1) X An 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 109.16
• 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

Arizona Public Service Company 

This Report is:

(1) X An 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 109.17
• 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) X An 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) X An 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 in the 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) X An 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) X An 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) X An 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

 1 UTILITY PLANT

 2 Utility Plant (101-106, 114) 200-201 14,914,905,234 14,293,093,724

 3 Construction Work in Progress (107) 200-201 456,350,998 387,396,423

 4 TOTAL Utility Plant (Enter Total of lines 2 and 3) 15,371,256,232 14,680,490,147

 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 200-201 5,683,978,497 5,450,571,192

 6 Net Utility Plant (Enter Total of line 4 less 5) 9,687,277,735 9,229,918,955

 7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 202-203 109,365,418 109,348,410

 8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 0 0

 9 Nuclear Fuel Assemblies in Reactor (120.3) 256,728,088 231,473,149

 10 Spent Nuclear Fuel (120.4) 0 0

 11 Nuclear Fuel Under Capital Leases (120.6) 0 0

 12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 202-203 133,950,187 113,374,710

 13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 232,143,319 227,446,849

 14 Net Utility Plant (Enter Total of lines 6 and 13) 9,919,421,054 9,457,365,804

 15 Utility Plant Adjustments (116) 0 0

 16 Gas Stored Underground - Noncurrent (117) 0 0

 17 OTHER PROPERTY AND INVESTMENTS

 18 Nonutility Property (121) 5,255,512 5,255,512

 19 (Less) Accum. Prov. for Depr. and Amort. (122) 1,688,381 1,665,035

 20 Investments in Associated Companies (123) 0 0

 21 Investment in Subsidiary Companies (123.1) 224-225 8,746 8,746

 22 (For Cost of Account 123.1, See Footnote Page 224, line 42)

 23 Noncurrent Portion of Allowances 228-229 0 0

 24 Other Investments (124) 0 0

 25 Sinking Funds (125) 0 0

 26 Depreciation Fund (126) 570,625,425 513,732,954

 27 Amortization Fund - Federal (127) 0 0

 28 Other Special Funds (128) 311,453 250,211

 29 Special Funds (Non Major Only) (129) 0 0

 30 Long-Term Portion of Derivative Assets (175) 41,563,063 58,272,888

 31 Long-Term Portion of Derivative Assets – Hedges (176) 0 3,803,618

 32 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 616,075,818 579,658,894

 33 CURRENT AND ACCRUED ASSETS

 34 Cash and Working Funds (Non-major Only) (130) 0 0

 35 Cash (131) 3,263,558 7,420,504

 36 Special Deposits (132-134) 0 0

 37 Working Fund (135) 218,475 218,108

 38 Temporary Cash Investments (136) 17,248 12,234,189

 39 Notes Receivable (141) 924,992 924,992

 40 Customer Accounts Receivable (142) 203,615,582 201,792,722

 41 Other Accounts Receivable (143) 71,198,680 78,291,280

 42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 3,340,209 3,748,325

 43 Notes Receivable from Associated Companies (145) 0 0

 44 Accounts Receivable from Assoc. Companies (146) 0 15,545

 45 Fuel Stock (151) 227 31,334,390 21,999,982

 46 Fuel Stock Expenses Undistributed (152) 227 0 0

 47 Residuals (Elec) and Extracted Products (153) 227 0 0

 48 Plant Materials and Operating Supplies (154) 227 218,095,667 204,386,748

 49 Merchandise (155) 227 0 0

 50 Other Materials and Supplies (156) 227 0 0

 51 Nuclear Materials Held for Sale (157) 202-203/227 0 0

 52 Allowances (158.1 and 158.2) 228-229 0 0

FERC FORM NO. 1 (REV. 12-03) Page 110
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)

 53 (Less) Noncurrent Portion of Allowances 0 0

 54 Stores Expense Undistributed (163) 227 0 0

 55 Gas Stored Underground - Current (164.1) 0 0

 56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 0 0

 57 Prepayments (165) 32,147,460 28,303,420

 58 Advances for Gas (166-167) 0 0

 59 Interest and Dividends Receivable (171) 0 0

 60 Rents Receivable (172) 0 0

 61 Accrued Utility Revenues (173) 94,845,364 125,239,466

 62 Miscellaneous Current and Accrued Assets (174) 81,483,059 201,328,176

 63 Derivative Instrument Assets (175) 84,997,558 136,116,648

 64 (Less) Long-Term Portion of Derivative Instrument Assets (175) 41,563,063 58,272,888

 65 Derivative Instrument Assets - Hedges (176) 0 11,090,253

 66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 3,803,618

 67 Total Current and Accrued Assets (Lines 34 through 66) 777,238,761 963,537,202

 68 DEFERRED DEBITS

 69 Unamortized Debt Expenses (181) 22,491,524 21,181,437

 70 Extraordinary Property Losses (182.1) 230a 0 0

 71 Unrecovered Plant and Regulatory Study Costs (182.2) 230b 0 0

 72 Other Regulatory Assets (182.3) 232 1,200,038,505 1,409,619,466

 73 Prelim. Survey and Investigation Charges (Electric) (183) 6,401,837 6,012,305

 74 Preliminary Natural Gas Survey and Investigation Charges 183.1) 0 0

 75 Other Preliminary Survey and Investigation Charges (183.2) 0 0

 76 Clearing Accounts (184) -96,367 166,152

 77 Temporary Facilities (185) 0 0

 78 Miscellaneous Deferred Debits (186) 233 240,529,568 245,310,527

 79 Def. Losses from Disposition of Utility Plt. (187) 0 0

 80 Research, Devel. and Demonstration Expend. (188) 352-353 0 0

 81 Unamortized Loss on Reaquired Debt (189) 19,561,430 20,486,731

 82 Accumulated Deferred Income Taxes (190) 234 894,894,567 1,078,997,258

 83 Unrecovered Purchased Gas Costs (191) 0 0

 84 Total Deferred Debits (lines 69 through 83) 2,383,821,064 2,781,773,876

 85 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 13,696,556,697 13,782,335,776

FERC FORM NO. 1 (REV. 12-03) Page 111
Name of Respondent This Report is: Year/Period of Report

(1) An Original

(2) A Resubmission

x

Date of Report

(mo, da, yr)

end of

Line

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(a)

Ref.

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(b)

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(c)

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(d)

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

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

 1 PROPRIETARY CAPITAL

 2 Common Stock Issued (201) 250-251 178,162,367 178,162,367

 3 Preferred Stock Issued (204) 250-251 0 0

 4 Capital Stock Subscribed (202, 205) 0 0

 5 Stock Liability for Conversion (203, 206) 0 0

 6 Premium on Capital Stock (207) 2,398,807,686 2,398,807,687

 7 Other Paid-In Capital (208-211) 253 18,400,365 18,400,365

 8 Installments Received on Capital Stock (212) 252 0 0

 9 (Less) Discount on Capital Stock (213) 254 0 0

 10 (Less) Capital Stock Expense (214) 254b 37,511,652 37,511,652

 11 Retained Earnings (215, 215.1, 216) 118-119 1,624,229,623 1,510,731,982

 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 7,746 7,746

 13 (Less) Reaquired Capital Stock (217) 250-251 0 0

 14 Noncorporate Proprietorship (Non-major only) (218) 0 0

 15 Accumulated Other Comprehensive Income (219) 122(a)(b) -89,095,286 -125,591,173

 16 Total Proprietary Capital (lines 2 through 15) 4,093,000,849 3,943,007,322

 17 LONG-TERM DEBT

 18 Bonds (221) 256-257 565,855,000 655,855,000

 19 (Less) Reaquired Bonds (222) 256-257 0 0

 20 Advances from Associated Companies (223) 256-257 0 0

 21 Other Long-Term Debt (224) 256-257 2,599,730,406 2,648,177,037

 22 Unamortized Premium on Long-Term Debt (225) 0 0

 23 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 9,486,025 7,198,492

 24 Total Long-Term Debt (lines 18 through 23) 3,156,099,381 3,296,833,545

 25 OTHER NONCURRENT LIABILITIES

 26 Obligations Under Capital Leases - Noncurrent (227) 0 0

 27 Accumulated Provision for Property Insurance (228.1) 0 0

 28 Accumulated Provision for Injuries and Damages (228.2) 1,826,753 973,537

 29 Accumulated Provision for Pensions and Benefits (228.3) 1,051,452,575 1,260,339,226

 30 Accumulated Miscellaneous Operating Provisions (228.4) 0 0

 31 Accumulated Provision for Rate Refunds (229) 535,736 9,834,939

 32 Long-Term Portion of Derivative Instrument Liabilities 96,654,266 92,880,131

 33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 4,331,681 68,137,406

 34 Asset Retirement Obligations (230) 357,097,415 279,642,641

 35 Total Other Noncurrent Liabilities (lines 26 through 34) 1,511,898,426 1,711,807,880

 36 CURRENT AND ACCRUED LIABILITIES

 37 Notes Payable (231) 92,175,000 0

 38 Accounts Payable (232) 215,589,681 322,040,469

 39 Notes Payable to Associated Companies (233) 0 0

 40 Accounts Payable to Associated Companies (234) 74,317,008 19,566,059

 41 Customer Deposits (235) 79,688,507 72,176,064

 42 Taxes Accrued (236) 262-263 126,056,280 121,338,952

 43 Interest Accrued (237) 48,741,548 54,454,119

 44 Dividends Declared (238) 0 0

 45 Matured Long-Term Debt (239) 0 0

FERC FORM NO. 1 (rev. 12-03) Page 112
Name of Respondent This Report is: Year/Period of Report

(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) (continued)

 46 Matured Interest (240) 0 0

 47 Tax Collections Payable (241) -12,813 6,069

 48 Miscellaneous Current and Accrued Liabilities (242) 156,272,165 131,763,719

 49 Obligations Under Capital Leases-Current (243) 0 1,029,418

 50 Derivative Instrument Liabilities (244) 200,831,352 217,232,686

 51 (Less) Long-Term Portion of Derivative Instrument Liabilities 96,654,266 92,880,131

 52 Derivative Instrument Liabilities - Hedges (245) 5,478,201 150,332,729

 53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 4,331,681 68,137,406

 54 Total Current and Accrued Liabilities (lines 37 through 53) 898,150,982 928,922,747

 55 DEFERRED CREDITS

 56 Customer Advances for Construction (252) 109,359,166 116,805,411

 57 Accumulated Deferred Investment Tax Credits (255) 266-267 99,819,092 58,240,341

 58 Deferred Gains from Disposition of Utility Plant (256) 13,734,136 18,307,928

 59 Other Deferred Credits (253) 269 222,935,180 189,532,594

 60 Other Regulatory Liabilities (254) 278 513,088,229 470,102,597

 61 Unamortized Gain on Reaquired Debt (257) 458,291 501,596

 62 Accum. Deferred Income Taxes-Accel. Amort.(281) 272-277 0 0

 63 Accum. Deferred Income Taxes-Other Property (282) 2,570,393,448 2,428,297,226

 64 Accum. Deferred Income Taxes-Other (283) 507,619,517 619,976,589

 65 Total Deferred Credits (lines 56 through 64) 4,037,407,059 3,901,764,282

 66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 13,696,556,697 13,782,335,776

FERC FORM NO. 1 (rev. 12-03) Page 113
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 INCOME

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

(a) (b) (c)

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

 1 UTILITY OPERATING INCOME

 2 Operating Revenues (400) 300-301 3,317,931,261 3,274,438,030

 3 Operating Expenses

 4 Operation Expenses (401) 320-323 1,705,929,816 1,751,027,005

 5 Maintenance Expenses (402) 320-323 205,959,108 210,680,823

 6 Depreciation Expense (403) 336-337 328,826,684 359,134,941

 7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337 6,495,644 2,494,645

 8 Amort. & Depl. of Utility Plant (404-405) 336-337 68,446,302 63,533,348

 9 Amort. of Utility Plant Acq. Adj. (406) 336-337

 10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 55,045 96,328

 11 Amort. of Conversion Expenses (407)

 12 Regulatory Debits (407.3)

 13 (Less) Regulatory Credits (407.4) 431,516 863,035

 14 Taxes Other Than Income Taxes (408.1) 262-263 184,088,582 171,393,974

 15 Income Taxes - Federal (409.1) 262-263 279,934 6,901,954

 16 - Other (409.1) 262-263 13,011,314 19,177,086

 17 Provision for Deferred Income Taxes (410.1) 234, 272-277 947,004,484 1,164,902,602

 18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 703,460,192 986,025,594

 19 Investment Tax Credit Adj. - Net (411.4) 266

 20 (Less) Gains from Disp. of Utility Plant (411.6) 4,573,792 4,573,774

 21 Losses from Disp. of Utility Plant (411.7)

 22 (Less) Gains from Disposition of Allowances (411.8) 4,169,987

 23 Losses from Disposition of Allowances (411.9) 4,008,180 179,975

 24 Accretion Expense (411.10)

 25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 2,751,469,606 2,758,060,278

 26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 566,461,655 516,377,752

FERC FORM NO. 1/3-Q (REV. 02-04) Page 114
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 INCOME FOR THE YEAR (Continued)

Arizona Public Service Company X

04/10/2013

2012/Q4

 Previous Year to Date Line

(in dollars)

(g) (j) (k)

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 115
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 INCOME FOR THE YEAR (continued)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 Previous Year

(a) (b) (c)

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)

 27 Net Utility Operating Income (Carried forward from page 114) 566,461,655 516,377,752

 28 Other Income and Deductions

 29 Other Income

 30 Nonutilty Operating Income

 31 Revenues From Merchandising, Jobbing and Contract Work (415) 1,694,330 2,729,514

 32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 1,093,830 2,042,617

 33 Revenues From Nonutility Operations (417) 1,500 1,500

 34 (Less) Expenses of Nonutility Operations (417.1) 10,329 34,166

 35 Nonoperating Rental Income (418) -143,546 486,952

 36 Equity in Earnings of Subsidiary Companies (418.1) 119

 37 Interest and Dividend Income (419) 309,580 405,637

 38 Allowance for Other Funds Used During Construction (419.1) 22,435,728 23,706,665

 39 Miscellaneous Nonoperating Income (421) 40,044,684 64,271,430

 40 Gain on Disposition of Property (421.1) 624,094 472,537

 41 TOTAL Other Income (Enter Total of lines 31 thru 40) 63,862,211 89,997,452

 42 Other Income Deductions

 43 Loss on Disposition of Property (421.2) 1,510,980 1,351,992

 44 Miscellaneous Amortization (425)

 45 Donations (426.1) 2,552,595 2,250,854

 46 Life Insurance (426.2) -1,418,011

 47 Penalties (426.3) 5,302,000 10,245

 48 Exp. for Certain Civic, Political & Related Activities (426.4) 3,078,370 2,905,075

 49 Other Deductions (426.5) 46,341,213 70,474,982

 50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 58,785,158 75,575,137

 51 Taxes Applic. to Other Income and Deductions

 52 Taxes Other Than Income Taxes (408.2) 262-263 901,863 955,111

 53 Income Taxes-Federal (409.2) 262-263 -7,084,804 -9,024,937

 54 Income Taxes-Other (409.2) 262-263 -703,666 -73,171

 55 Provision for Deferred Inc. Taxes (410.2) 234, 272-277 100,612 152,625

 56 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 234, 272-277 1,698,590 2,105,305

 57 Investment Tax Credit Adj.-Net (411.5)

 58 (Less) Investment Tax Credits (420) 2,817,922 473,093

 59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) -11,302,507 -10,568,770

 60 Net Other Income and Deductions (Total of lines 41, 50, 59) 16,379,560 24,991,085

 61 Interest Charges

 62 Interest on Long-Term Debt (427) 191,200,337 209,406,256

 63 Amort. of Debt Disc. and Expense (428) 2,929,008 3,329,780

 64 Amortization of Loss on Reaquired Debt (428.1) 1,329,221 1,329,221

 65 (Less) Amort. of Premium on Debt-Credit (429)

 66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 43,303 43,303

 67 Interest on Debt to Assoc. Companies (430)

 68 Other Interest Expense (431) 6,899,565 9,454,554

 69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 14,971,254 18,357,892

 70 Net Interest Charges (Total of lines 62 thru 69) 187,343,574 205,118,616

 71 Income Before Extraordinary Items (Total of lines 27, 60 and 70) 395,497,641 336,250,221

 72 Extraordinary Items

 73 Extraordinary Income (434)

 74 (Less) Extraordinary Deductions (435)

 75 Net Extraordinary Items (Total of line 73 less line 74)

 76 Income Taxes-Federal and Other (409.3) 262-263

 77 Extraordinary Items After Taxes (line 75 less line 76)

 78 Net Income (Total of line 71 and 77) 395,497,641 336,250,221

FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
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 RETAINED EARNINGS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

Current

Quarter/Year

Year to Date

Balance

(a) (b) (c)

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 Balance-Beginning of Period 1,510,731,982 1,403,381,761

 2 Changes

 3 Adjustments to Retained Earnings (Account 439)

 4

 5

 6

 7

 8

 9 TOTAL Credits to Retained Earnings (Acct. 439)

 10

 11

 12

 13

 14

 15 TOTAL Debits to Retained Earnings (Acct. 439)

 16 Balance Transferred from Income (Account 433 less Account 418.1) 395,497,641 336,250,221

 17 Appropriations of Retained Earnings (Acct. 436)

 18

 19

 20

 21

 22 TOTAL Appropriations of Retained Earnings (Acct. 436)

 23 Dividends Declared-Preferred Stock (Account 437)

 24

 25

 26

 27

 28

 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)

 30 Dividends Declared-Common Stock (Account 438)

 31 -282,000,000 ( 228,900,000)

 32

 33

 34

 35

 36 TOTAL Dividends Declared-Common Stock (Acct. 438) -282,000,000 ( 228,900,000)

 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings

 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) 1,624,229,623 1,510,731,982

APPROPRIATED RETAINED EARNINGS (Account 215)

 39

 40

FERC FORM NO. 1/3-Q (REV. 02-04) Page 118
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 RETAINED EARNINGS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

Current

Quarter/Year

Year to Date

Balance

(a) (b) (c)

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

 45 TOTAL Appropriated Retained Earnings (Account 215)

APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)

 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)

 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)

 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) 1,624,229,623 1,510,731,982

UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account

Report only on an Annual Basis, no Quarterly

 49 Balance-Beginning of Year (Debit or Credit) 7,746 7,746

 50 Equity in Earnings for Year (Credit) (Account 418.1)

 51 (Less) Dividends Received (Debit)

 52

 53 Balance-End of Year (Total lines 49 thru 52) 7,746 7,746

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:

 2 Net Income (Line 78(c) on page 117) 395,497,641 336,250,221

 3 Noncash Charges (Credits) to Income:

 4 Depreciation and Depletion 335,322,328 361,629,586

 5 Amortization of UTL PLT; ACQ; ADJ; Prop Loss; Reg Study; Nuclear Fuel 144,995,415 129,461,261

 6

 7 Deferred Fuel and Purchased Power -45,143,221 -85,991,422

 8 Deferred Income Taxes (Net) 190,018,457 51,149,448

 9 Investment Tax Credit Adjustment (Net) 41,578,751 57,257,852

 10 Net (Increase) Decrease in Receivables 43,308,391 12,965,490

 11 Net (Increase) Decrease in Inventory -23,043,326 -23,397,630

 12 Net (Increase) Decrease in Allowances Inventory

 13 Net Increase (Decrease) in Payables and Accrued Expenses -102,444,105 79,231,375

 14 Net (Increase) Decrease in Other Regulatory Assets -15,510,752 -4,782,074

 15 Net Increase (Decrease) in Other Regulatory Liabilities 44,355,108 135,947,579

 16 (Less) Allowance for Other Funds Used During Construction 22,435,728 23,706,665

 17 (Less) Undistributed Earnings from Subsidiary Companies

 18 Other (provide details in footnote):

 19 Other Current Assets 117,062,176 51,761,278

 20 Other Current Liabilities 31,025,646 14,714,614

 21 Other Current Long Term Assets/Liabilities Net -993,853 -4,087,654

 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 1,133,592,928 1,088,403,259

 23

 24 Cash Flows from Investment Activities:

 25 Construction and Acquisition of Plant (including land):

 26 Gross Additions to Utility Plant (less nuclear fuel) -839,770,854 -837,847,061

 27 Gross Additions to Nuclear Fuel -25,254,939 -37,409,363

 28 Gross Additions to Common Utility Plant

 29 Gross Additions to Nonutility Plant -561,303

 30 (Less) Allowance for Other Funds Used During Construction 14,971,255 18,357,892

 31 Other (provide details in footnote):

 32 Contributions in Aid of Construction 49,875,809 38,096,640

 33

 34 Cash Outflows for Plant (Total of lines 26 thru 33) -830,121,239 -856,078,979

 35

 36 Acquisition of Other Noncurrent Assets (d)

 37 Proceeds from Disposal of Noncurrent Assets (d)

 38

 39 Investments in and Advances to Assoc. and Subsidiary Companies

 40 Contributions and Advances from Assoc. and Subsidiary Companies

 41 Disposition of Investments in (and Advances to)

 42 Associated and Subsidiary Companies

 43 Proceeds from Nuclear Decommissioning Trust and Sales (a) 417,603,316 497,779,660

 44 Purchase of Investment Securities (a)

 45 Proceeds 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)

 46 Loans Made or Purchased

 47 Collections on Loans

 48 Investment in Nuclear Decommissioning Trust and Sales (a) -434,852,259 -513,798,660

 49 Net (Increase) Decrease in Receivables

 50 Net (Increase ) Decrease in Inventory

 51 Net (Increase) Decrease in Allowances Held for Speculation

 52 Net Increase (Decrease) in Payables and Accrued Expenses -24,524,603 -3,289,484

 53 Other (provide details in footnote):

 54 Investments and Other Assets -1,098,995 41,438,450

 55

 56 Net Cash Provided by (Used in) Investing Activities

 57 Total of lines 34 thru 55) -872,993,780 -833,949,013

 58

 59 Cash Flows from Financing Activities:

 60 Proceeds from Issuance of:

 61 Long-Term Debt (b) 351,081,750 295,353,000

 62 Preferred Stock

 63 Common Stock

 64 Other (provide details in footnote):

 65

 66 Net Increase in Short-Term Debt (c) 92,175,000

 67 Current Obligations for Capital Leases 57,536

 68

 69

 70 Cash Provided by Outside Sources (Total 61 thru 69) 443,256,750 295,410,536

 71

 72 Payments for Retirement of:

 73 Long-term Debt (b) -497,000,000 -401,029,418

 74 Preferred Stock

 75 Common Stock

 76 Other (provide details in footnote):

 77 Current Obligations for Capital Leases -1,029,418

 78 Net Decrease in Short-Term Debt (c)

 79

 80 Dividends on Preferred Stock

 81 Dividends on Common Stock -222,200,000 -228,900,000

 82 Net Cash Provided by (Used in) Financing Activities

 83 (Total of lines 70 thru 81) -276,972,668 -334,518,882

 84

 85 Net Increase (Decrease) in Cash and Cash Equivalents

 86 (Total of lines 22,57 and 83) -16,373,520 -80,064,636

 87

 88 Cash and Cash Equivalents at Beginning of Period 19,872,801 99,937,437

 89

 90 Cash and Cash Equivalents at End of period 3,499,281 19,872,801

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) X An 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) X An 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) X An 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 123.1
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) X An 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 123.2
• 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) X An 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 123.3
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) X An 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 123.4
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 another postretirement 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) X An 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 123.5
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) X An 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 123.6
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) X An 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 123.7
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) X An 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 123.8
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) X An 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 123.9
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) X An 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 123.10
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 in the 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) X An 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 123.11
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) X An 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) X An 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) X An 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 December 31, 2012.

Name of Respondent

Arizona Public Service Company 

This Report is:

(1) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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 of trust assets relative to the

benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments

including long-term fixed income assets and return-generating assets. The target allocation between

return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded

status. The plan’s funded status is reviewed on at least a monthly basis. 

Long-term fixed income assets, also known as liability-hedging assets, are designed to offset changes in the

benefit obligations due to changes in interest rates. Long-term fixed income assets consist primarily of fixed income

debt securities issued by the U.S. Treasury, other government agencies, and corporations. Long-term fixed income

assets may also include interest rate swaps, U.S. Treasury futures and other instruments.

Return-generating assets are intended to provide a reasonable long-term rate of investment return with a

prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and

alternative investments. International equities include investments in both developed and emerging markets. 

Alternative investments 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) X An 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 in corporate bonds of investment-grade U.S. issuers, and U.S. Treasuries. Non-fixed income

assets are primarily invested in large cap U.S. equities in diverse industries, and international equities in both

emerging and developed markets. 

See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The

plans invest directly in fixed income and equity securities, in addition to investing indirectly in 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) X An 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) X An 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) X An 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 21st Century 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) X An 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) X An 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) X An 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 accidental outage of any of the three units. The property damage, decontamination, and replacement

power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective

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) X An 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) X An 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 52nd Street Superfund Site, OU3 in

Phoenix, Arizona. APS has facilities that are within this Superfund site. APS has agreed with EPA to perform

certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed

with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater

remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and

study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because

the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present

time expenditures related to this matter cannot be reasonably estimated.

Name of Respondent

Arizona Public Service Company 

This Report is:

(1) X An 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

Kivalina plaintiffs’ 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 in Kivalina is 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”) with their 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) X An 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) X An 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) X An 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 123.37
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) X An 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 123.38
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) X An 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 123.39
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 

This Report is:

(1) X An 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 123.40
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 

This Report is:

(1) X An 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 123.41
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 

This Report is:

(1) X An 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 123.42
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 

This Report is:

(1) X An 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 123.43
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) X An 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 123.44
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 

This Report is:

(1) X An 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 123.45
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) X An 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 123.46
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 

This Report is:

(1) X An 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 123.47
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 

This Report is:

(1) X An 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 123.48
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 

This Report is:

(1) X An 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 123.49
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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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 123.55
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.

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 and

Losses 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

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

( 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

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

( 39,502,968)

Balance of Account 219 at End of Current

Quarter/Year

 10

FERC FORM NO. 1 (NEW 06-02) Page 122a
Other 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)

 1 ( 100,333,601) ( 136,294,557)

 2 70,891,143 73,826,600

 3 ( 57,262,471) ( 63,123,216)

 4 13,628,672 10,703,384 336,250,221 346,953,605

 5 ( 86,704,929) ( 125,591,173)

 6 ( 86,704,929) ( 125,591,173)

 7 59,887,524 63,367,481

 8 ( 22,774,913) ( 26,871,594)

 9 37,112,611 36,495,887 395,497,641 431,993,528

 10 ( 49,592,318) ( 89,095,286)

FERC FORM NO. 1 (NEW 06-02) Page 122b
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. (a) (b)

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.

 1 Utility Plant

 2 In Service

 3 Plant in Service (Classified) 14,398,115,244 14,398,115,244

 4 Property Under Capital Leases

 5 Plant Purchased or Sold

 6 Completed Construction not Classified 462,907,933 462,907,933

 7 Experimental Plant Unclassified

 8 Total (3 thru 7) 14,861,023,177 14,861,023,177

 9 Leased to Others

 10 Held for Future Use 53,882,057 53,882,057

 11 Construction Work in Progress 456,350,998 456,350,998

 12 Acquisition Adjustments

 13 Total Utility Plant (8 thru 12) 15,371,256,232 15,371,256,232

 14 Accum Prov for Depr, Amort, & Depl 5,683,978,497 5,683,978,497

 15 Net Utility Plant (13 less 14) 9,687,277,735 9,687,277,735

 16 Detail of Accum Prov for Depr, Amort & Depl

 17 In Service:

 18 Depreciation 5,136,337,746 5,136,337,746

 19 Amort & Depl of Producing Nat Gas Land/Land Right

 20 Amort of Underground Storage Land/Land Rights

 21 Amort of Other Utility Plant 547,640,751 547,640,751

 22 Total In Service (18 thru 21) 5,683,978,497 5,683,978,497

 23 Leased to Others

 24 Depreciation

 25 Amortization and Depletion

 26 Total Leased to Others (24 & 25)

 27 Held for Future Use

 28 Depreciation

 29 Amortization

 30 Total Held for Future Use (28 & 29)

 31 Abandonment of Leases (Natural Gas)

 32 Amort of Plant Acquisition Adj

 33 Total Accum Prov (equals 14) (22,26,30,31,32) 5,683,978,497 5,683,978,497

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 201
Name 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

(a) (b) (c)

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.

 1 Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)

 2 Fabrication 36,691,948 25,695,669

 3 Nuclear Materials 62,693,685 44,141,618

 4 Allowance for Funds Used during Construction 10,118,084 9,141,375

 5 (Other Overhead Construction Costs, provide details in footnote) -155,307 2,643,390

 6 SUBTOTAL (Total 2 thru 5) 109,348,410

 7 Nuclear Fuel Materials and Assemblies

 8 In Stock (120.2) 81,605,045

 9 In Reactor (120.3) 231,473,149 81,605,046

 10 SUBTOTAL (Total 8 & 9) 231,473,149

 11 Spent Nuclear Fuel (120.4)

 12 Nuclear Fuel Under Capital Leases (120.6)

 13 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 113,374,710

 14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 227,446,849

 15 Estimated net Salvage Value of Nuclear Materials in line 9

 16 Estimated net Salvage Value of Nuclear Materials in line 11

 17 Est Net Salvage Value of Nuclear Materials in Chemical Processing

 18 Nuclear Materials held for Sale (157)

 19 Uranium

 20 Plutonium

 21 Other (provide details in footnote):

 22 TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)

FERC FORM NO. 1 (ED. 12-89) Page 202
Name of Respondent This Report Is:

(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

(d) (e) (f)

Changes during Year

Amortization Other Reductions (Explain in a footnote) End of Year

 1

 31,431,934 30,955,683 2

 40,051,369 66,783,934 3

 7,478,351 11,781,108 4

 2,643,390 -155,307 5

 109,365,418 6

 7

 81,605,045 8

 56,350,107 256,728,088 9

 256,728,088 10

 11

 12

 -76,925,584 56,350,107 133,950,187 13

 232,143,319 14

 15

 16

 17

 18

 19

 20

 21

 22

FERC FORM NO. 1 (ED. 12-89) Page 203
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) X An 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
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 IN SERVICE (Account 101, 102, 103 and 106)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Account Balance Additions

(a) (b) (c)

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 1. INTANGIBLE PLANT

 2 (301) Organization

 3 (302) Franchises and Consents 3,424,429 25,782

 4 (303) Miscellaneous Intangible Plant 554,923,961 42,701,620

 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 558,348,390 42,727,402

 6 2. PRODUCTION PLANT

 7 A. Steam Production Plant

 8 (310) Land and Land Rights 5,828,482 242

 9 (311) Structures and Improvements 173,273,600 12,119,436

 10 (312) Boiler Plant Equipment 1,126,640,886 32,746,276

 11 (313) Engines and Engine-Driven Generators

 12 (314) Turbogenerator Units 258,567,285 7,919,200

 13 (315) Accessory Electric Equipment 162,018,051 2,633,782

 14 (316) Misc. Power Plant Equipment 98,266,442 -15,463,182

 15 (317) Asset Retirement Costs for Steam Production 12,975,896 59,472,962

 16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 1,837,570,642 99,428,716

 17 B. Nuclear Production Plant

 18 (320) Land and Land Rights 4,521,619 -30,278

 19 (321) Structures and Improvements 736,048,948 22,649,048

 20 (322) Reactor Plant Equipment 1,187,407,438 6,256,495

 21 (323) Turbogenerator Units 367,460,220 9,322,995

 22 (324) Accessory Electric Equipment 277,414,164 4,801,579

 23 (325) Misc. Power Plant Equipment 148,509,967 15,687,726

 24 (326) Asset Retirement Costs for Nuclear Production -28,495,803 1,401,365

 25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 2,692,866,553 60,088,930

 26 C. Hydraulic Production Plant

 27 (330) Land and Land Rights

 28 (331) Structures and Improvements

 29 (332) Reservoirs, Dams, and Waterways

 30 (333) Water Wheels, Turbines, and Generators

 31 (334) Accessory Electric Equipment

 32 (335) Misc. Power PLant Equipment

 33 (336) Roads, Railroads, and Bridges

 34 (337) Asset Retirement Costs for Hydraulic Production

 35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)

 36 D. Other Production Plant

 37 (340) Land and Land Rights 7,816,314 2,003,167

 38 (341) Structures and Improvements 70,667,183 8,592,513

 39 (342) Fuel Holders, Products, and Accessories 47,972,020 1,274,259

 40 (343) Prime Movers 634,587,225 7,997,892

 41 (344) Generators 818,689,790 136,967,336

 42 (345) Accessory Electric Equipment 97,519,693 32,405,186

 43 (346) Misc. Power Plant Equipment 18,105,008 1,478,289

 44 (347) Asset Retirement Costs for Other Production

 45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 1,695,357,233 190,718,642

 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 6,225,794,428 350,236,288

FERC FORM NO. 1 (REV. 12-05) Page 204
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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Account Balance Additions

(a) (b) (c)

Beginning of Year

 47 3. TRANSMISSION PLANT

 48 (350) Land and Land Rights 144,692,883 9,757,471

 49 (352) Structures and Improvements 82,475,618 2,581,037

 50 (353) Station Equipment 868,416,763 41,990,869

 51 (354) Towers and Fixtures 104,649,311 1,529,276

 52 (355) Poles and Fixtures 413,144,379 11,856,096

 53 (356) Overhead Conductors and Devices 348,635,832 16,367,766

 54 (357) Underground Conduit 20,587,963 117,462

 55 (358) Underground Conductors and Devices 31,290,877 1,393,375

 56 (359) Roads and Trails

 57 (359.1) Asset Retirement Costs for Transmission Plant

 58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 2,013,893,626 85,593,352

 59 4. DISTRIBUTION PLANT

 60 (360) Land and Land Rights 50,090,477 1,435,573

 61 (361) Structures and Improvements 63,615,851 4,572,977

 62 (362) Station Equipment 429,187,104 26,967,421

 63 (363) Storage Battery Equipment

 64 (364) Poles, Towers, and Fixtures 498,376,210 31,712,288

 65 (365) Overhead Conductors and Devices 307,393,321 2,325,624

 66 (366) Underground Conduit 630,386,957 15,312,905

 67 (367) Underground Conductors and Devices 1,456,977,856 47,222,515

 68 (368) Line Transformers 741,561,623 32,214,971

 69 (369) Services 334,561,609 8,937,040

 70 (370) Meters 218,674,402 48,608,646

 71 (371) Installations on Customer Premises 40,629,555 1,114,019

 72 (372) Leased Property on Customer Premises

 73 (373) Street Lighting and Signal Systems 75,073,660 274,471

 74 (374) Asset Retirement Costs for Distribution Plant

 75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 4,846,528,625 220,698,450

 76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT

 77 (380) Land and Land Rights

 78 (381) Structures and Improvements

 79 (382) Computer Hardware

 80 (383) Computer Software

 81 (384) Communication Equipment

 82 (385) Miscellaneous Regional Transmission and Market Operation Plant

 83 (386) Asset Retirement Costs for Regional Transmission and Market Oper

 84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)

 85 6. GENERAL PLANT

 86 (389) Land and Land Rights 14,636,876 26,421

 87 (390) Structures and Improvements 166,553,207 5,119,987

 88 (391) Office Furniture and Equipment 148,708,496 31,329,195

 89 (392) Transportation Equipment 37,915,709 2,320,172

 90 (393) Stores Equipment 256,764

 91 (394) Tools, Shop and Garage Equipment 29,728,420 4,264,718

 92 (395) Laboratory Equipment 1,077,783

 93 (396) Power Operated Equipment 11,778,714

 94 (397) Communication Equipment 169,945,091 23,385,468

 95 (398) Miscellaneous Equipment 10,099,577 2,421,052

 96 SUBTOTAL (Enter Total of lines 86 thru 95) 590,700,637 68,867,013

 97 (399) Other Tangible Property

 98 (399.1) Asset Retirement Costs for General Plant

 99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 590,700,637 68,867,013

 100 TOTAL (Accounts 101 and 106) 14,235,265,706 768,122,505

 101 (102) Electric Plant Purchased (See Instr. 8)

 102 (Less) (102) Electric Plant Sold (See Instr. 8)

 103 (103) Experimental Plant Unclassified

 104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 14,235,265,706 768,122,505

FERC FORM NO. 1 (REV. 12-05) Page 206
(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

Arizona Public Service Company End of 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

 6,258 3,443,953 3

 12,379,029 117,109 585,363,661 4

 12,385,287 117,109 588,807,614 5

 6

 7

 -33,986 5,794,738 8

 1,542,060 183,850,976 9

 3,508,010 1,155,879,152 10

 11

 2,191,038 264,295,447 12

 1,647,829 163,004,004 13

 897,386 -515,489 81,390,385 14

 72,448,858 15

 9,786,323 -549,475 1,926,663,560 16

 17

 4,491,341 18

 877,207 757,820,789 19

 2,366,426 1,191,297,507 20

 2,437,716 374,345,499 21

 219,587 281,996,156 22

 2,876,260 161,321,433 23

 -2,516,663 -29,611,101 24

 8,777,196 -2,516,663 2,741,661,624 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 152,615 9,972,096 37

 1,058,058 -55,274 78,146,364 38

 49,246,279 39

 8,281,777 634,303,340 40

 9,050,949 -899,467 945,706,710 41

 282,449 -12,299 129,630,131 42

 646,324 18,936,973 43

 44

 19,319,557 -814,425 1,865,941,893 45

 37,883,076 -2,516,663 -1,363,900 6,534,267,077 46

FERC FORM NO. 1 (REV. 12-05) Page 205
(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

Arizona Public Service Company End of 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

 1,176,527 155,626,881 48

 303,521 -589,539 84,163,595 49

 5,572,297 986,587 905,821,922 50

 612 106,177,975 51

 743,705 424,256,770 52

 781,546 364,222,052 53

 48,588 20,656,837 54

 32,684,252 55

 56

 57

 7,450,269 1,573,575 2,093,610,284 58

 59

 173 -16,346 51,509,531 60

 266,027 67,922,801 61

 3,648,915 1,248,989 453,754,599 62

 63

 4,960,363 35 -292,324 524,835,846 64

 2,655,902 9,281 307,072,324 65

 2,760,159 413 2,082 642,942,198 66

 9,583,537 36,067 1,494,652,901 67

 6,556,096 -5,729 767,214,769 68

 602,781 342,895,868 69

 20,004,754 247,278,294 70

 251,489 -37,841 41,454,244 71

 72

 335,081 10,562 75,023,612 73

 74

 51,625,277 448 954,741 5,016,556,987 75

 76

 77

 78

 79

 80

 81

 82

 83

 84

 85

 -17,982 14,645,315 86

 4,199,807 167,473,387 87

 22,558,554 157,479,137 88

 3,447,324 5,362,616 42,151,173 89

 256,764 90

 506,408 33,048 33,519,778 91

 127,003 950,780 92

 715,727 11,062,987 93

 5,603,392 1,333 187,728,500 94

 7,235 12,513,394 95

 37,165,450 5,379,015 627,781,215 96

 97

 98

 37,165,450 5,379,015 627,781,215 99

 146,509,359 -2,516,215 6,660,540 14,861,023,177 100

 101

 102

 103

 146,509,359 -2,516,215 6,660,540 14,861,023,177 104

FERC FORM NO. 1 (REV. 12-05) Page 207
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

(a) (b)

(Designate associated companies with a double asterisk) Property LeasedCommission

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) Page 213

47 TOTAL
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 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

(a) (b) (c) 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.

 1 Land and Rights:

 2 Roanoke Substation 12/31/1991 12/31/2022 282,772

 3 35th Ave. & Roanoke Ave., Phoenix, AZ

 4 Prescott Service Center Office 11/30/2005 12/31/2017 2,004,206

 5 Prescott, AZ

 6 Madison Substation 12/31/1993 12/31/2022 592,651

 7 11th St. & Jackson St., Phoenix, AZ

 8 Paradise Substation 10/31/2006 12/31/2022 401,193

 9 15021 N. 33rd Place, Phoenix, AZ

 10 Palo Verde to Kyrene 500KV Line 5/31/2007 12/31/2022 4,024,859

 11 Maricopa, AZ

 12 Sun Valley (TS5) to Trilby Wash (TS1) Transmission e 12/31/2008 12/31/2015 14,677,520

 13 Township 040N 040W Sec 29; Maricopa, AZ

 14 Palm Valley (TS3) to Trilby Wash (TS1) Transmissione 12/31/2008 12/31/2015 16,510,753

 15 Township 040N 020W Sec 20; Surprise, AZ

 16 Palo Verde to Sun Valley (TS5) 500KV Transmission Le 12/31/2008 12/31/2016 4,299,208

 17 Township 030N 070W Sec 28; Maricopa, AZ

 18 Buckeye to Elianto (SV4) Transmission Line 5/31/2008 12/31/2022 653,352

 19 Township 010N 030W Sec 7; Buckeye, AZ

 20

 21 Other Property:

 22 Other General Parcels (2) 12/31/1999 12/31/2022 281,561

 23

 24 Other Transmission Parcels (2) 12/31/1999 12/31/2022 92,023

 25

 26 Other Distribution Parcels (4) 12/31/1999 12/31/2022 556,004

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

 44

 45

 46

FERC FORM NO. 1 (ED. 12-96) Page 214

47 Total 53,882,057
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 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

(a) (b) (c) 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.

 1 Land and Rights:

 2 Delaney Substation 9/30/2008 12/31/2016 1,074,847

 3 Thomas & 451st Ave.; Maricopa, AZ

 4 Payson Substation 12/31/2008 12/31/2015 746,020

 5 Township100N 100E Sec2; Payson, AZ

 6 Sun Valley (TS5) Substation 12/31/2008 12/31/2016 5,328,441

 7 Township 04N 04E Sec29; Buckeye, AZ

 8 Via Dona (NE2) Substation 10/31/2008 12/31/2022 1,929,113

 9 118th Place & Via Dona Rd; Scottsdale, AZ

 10 Citrus (WS4) Substation 5/1/2009 12/31/2022 427,534

 11 Parcel 502-40-267 /T01NR02W.S10/ 2.633 acres

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Other Property:

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

 44

 45

 46

FERC FORM NO. 1 (ED. 12-96) Page 214.1

47 Total 53,882,057
Name 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 - 

(a) (b)

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.

 1 Palo Verde Nuclear Plant Improvements 102,615,834

 2 Cholla Plant Improvements 3,974,643

 3 Four Corners Plant Improvements 8,109,350

 4 Navajo Plant Improvements 2,367,651

 5 Gas & Oil Plant Improvements 21,441,616

 6 Solar Additions 100,696,004

 7

 8 Transmission Land and Land Rights 7,772,862

 9 Transmission Substations - Add/Improvements 21,190,915

 10 500 KV Lines - Add/Improvements 46,735,549

 11 115/230 KV Lines - Add/Improvements 14,630,564

 12 69 KV Lines - Add/Improvements 16,596,622

 13 ANPP 500 KV Transmission System 1,607,040

 14 Navajo Southern Transmission System 561,001

 15 PV/YUMA 500 KV Transmission System 797,249

 16 Morgan - Pinnacle Peak Transmission System 331,021

 17 Transmission Lines Relocates 2,360,975

 18 Transmission Lines Replace

 19 Transmission Reliability 7,260,808

 20

 21 Distribution Land and Land Rights 3,831,844

 22 Distribution Substation - Add/Improvements 2,618,558

 23 Overhead lines - Add/Improvements 2,600,252

 24 Underground Lines - Add/Improvements 3,921,317

 25 Distribution Relocates 3,102,070

 26 Distribution Replace 11,790,078

 27 Distribution Reliability 7,261,255

 28 Other Distribution 1,034,440

 29

 30 General Computer/Communications 41,745,542

 31 Buildings & Equip/Land & Land Rights 19,267,100

 32 Research, Development, Technical Research 128,838

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

FERC FORM NO. 1 (ED. 12-87) Page 216

43 TOTAL 456,350,998
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 PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Item Total

(a) (b) (c) (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.

 1 Balance Beginning of Year 4,952,911,448 4,952,911,448

 2 Depreciation Provisions for Year, Charged to

 3 (403) Depreciation Expense 328,826,684 328,826,684

(403.1) Depreciation Expense for Asset

Retirement Costs

 4 6,495,644 6,495,644

 5 (413) Exp. of Elec. Plt. Leas. to Others

 6 Transportation Expenses-Clearing 3,115,456 3,115,456

 7 Other Clearing Accounts 460,272 460,272

 8 Other Accounts (Specify, details in footnote):

 9

TOTAL Deprec. Prov for Year (Enter Total of

lines 3 thru 9)

 10 338,898,056 338,898,056

 11 Net Charges for Plant Retired:

 12 Book Cost of Plant Retired 132,659,157 132,659,157

 13 Cost of Removal 31,507,464 31,507,464

 14 Salvage (Credit) 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

 17

 18 Book Cost or Asset Retirement Costs Retired

Balance End of Year (Enter Totals of lines 1,

10, 15, 16, and 18)

 19 5,136,337,746 5,136,337,746

 20 Steam Production

Section B. Balances at End of Year According to Functional Classification

 1,094,613,696 1,094,613,696

 21 Nuclear Production 1,471,531,350 1,471,531,350

 22 Hydraulic Production-Conventional

 23 Hydraulic Production-Pumped Storage

 24 Other Production 483,075,786 483,075,786

 25 Transmission 624,798,831 624,798,831

 26 Distribution 1,318,599,421 1,318,599,421

 27 Regional Transmission and Market Operation

 28 General 143,718,662 143,718,662

 29 TOTAL (Enter Total of lines 20 thru 28) 5,136,337,746 5,136,337,746

FERC FORM NO. 1 (REV. 12-05) Page 219
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 Entities 4,681,883

 (6,552,415)

Name of Respondent

Arizona Public Service Company 

This Report is:

(1) X An 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
Name 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

(a) (b) (c)

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.

 1 BIXCO INC.

 2 Capital Stock, Common (10,000 Shares) 1,000

 3 Equity 7,746

 4 Subtotal BIXCO, Inc 8,746

 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 224

42 Total Cost of Account 123.1 $ 0 TOTAL 8,746
Name 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 8,746
Name 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

(a) (b) (c)

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.

 1 Fuel Stock (Account 151) 21,999,982 31,334,390

 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

 7 Production Plant (Estimated) 105,770,964 113,530,876

 8 Transmission Plant (Estimated) 28,883,524 30,666,214

 9 Distribution Plant (Estimated) 69,509,544 73,480,157

 10 Regional Transmission and Market Operation Plant

(Estimated)

 11 Assigned to - Other (provide details in footnote) 222,716 418,420

 12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 204,386,748 218,095,667

 13 Merchandise (Account 155)

 14 Other Materials and Supplies (Account 156)

 15 Nuclear Materials Held for Sale (Account 157) (Not

applic to Gas Util)

 16 Stores Expense Undistributed (Account 163)

 17

 18

 19

 20 TOTAL Materials and Supplies (Per Balance Sheet) 226,386,730 249,430,057

FERC FORM NO. 1 (REV. 12-05) Page 227
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) X An 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
Name 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

(a) (b)

(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

 1 Balance-Beginning of Year 100,299.00 36,876.00

 2

 3 Acquired During Year:

 4 Issued (Less Withheld Allow)

 5 Returned by EPA

 6

 7

 8 Purchases/Transfers:

 9

 10

 11

 12

 13

 14

 15 Total

 16

 17 Relinquished During Year:

 18 Charges to Account 509 8,807.00

 19 Other:

 20

 21 Cost of Sales/Transfers:

 22

 23

 24

 25

 26

 27

 28 Total

 29 Balance-End of Year 91,492.00 36,876.00

 30

 31 Sales:

 32 Net Sales Proceeds(Assoc. Co.)

 33 Net Sales Proceeds (Other)

 34 Gains

 35 Losses

Allowances Withheld (Acct 158.2)

 36 Balance-Beginning of Year 533.00 533.00

 37 Add: Withheld by EPA

 38 Deduct: Returned by EPA 533.00

 39 Cost of Sales

 40 Balance-End of Year 533.00

 41

 42 Sales:

 43 Net Sales Proceeds (Assoc. Co.)

 44 Net Sales Proceeds (Other) 533.00 259

 45 Gains 259

 46 Losses

FERC FORM NO. 1 (ED. 12-95) Page 228a
Name 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

 36,876.00 36,876.00 958,776.00 1,169,703.00 1

 2

 3

 36,876.00 36,876.00 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 8,807.00 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 36,876.00 36,876.00 995,652.00 1,197,772.00 29

 30

 31

 32

 33

 34

 35

 533.00 533.00 26,091.00 28,223.00 36

 1,066.00 1,066.00 37

 533.00 1,066.00 38

 39

 533.00 533.00 26,624.00 28,223.00 40

 41

 42

 43

 533.00 51 1,066.00 310 44

 51 310 45

 46

FERC FORM NO. 1 (ED. 12-95) Page 229a
Name 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

(a) (b)

(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

 1 Balance-Beginning of Year

 2

 3 Acquired During Year:

 4 Issued (Less Withheld Allow)

 5 Returned by EPA

 6

 7

 8 Purchases/Transfers:

 9

 10

 11

 12

 13

 14

 15 Total

 16

 17 Relinquished During Year:

 18 Charges to Account 509

 19 Other:

 20

 21 Cost of Sales/Transfers:

 22

 23

 24

 25

 26

 27

 28 Total

 29 Balance-End of Year

 30

 31 Sales:

 32 Net Sales Proceeds(Assoc. Co.)

 33 Net Sales Proceeds (Other)

 34 Gains

 35 Losses

Allowances Withheld (Acct 158.2)

 36 Balance-Beginning of Year

 37 Add: Withheld by EPA

 38 Deduct: Returned by EPA

 39 Cost of Sales

 40 Balance-End of Year

 41

 42 Sales:

 43 Net Sales Proceeds (Assoc. Co.)

 44 Net Sales Proceeds (Other)

 45 Gains

 46 Losses

FERC FORM NO. 1 (ED. 12-95) Page 228b
Name 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) Page 229b
Name 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.

(a) (b) (c) (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

(e) (f)

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 TOTAL
Name 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.

(a) (b) (c) (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

(e) (f)

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 TOTAL
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 Service and Generation Interconnection Study Costs

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

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

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 SIS (W481834) ( 1,783) 143 143

 23 Facilities Study (W484970) ( 202) 143 143

 24 Facilities Study (W485732) ( 222) 143 82,167 143

 25 SIS (W491430) ( 4,595) 143 143

 26 SMG SIS (W494782) 143 ( 3,426) 143

 27 SIS (W496400) ( 380) 143 143

 28 SMG SIS (W498627) 38,371 143 143

 29 SIS (W498627) 143 143

 30 SMG SIS (W498775) 143 ( 871) 143

 31 SIS (W498775) 143 143

 32 Feasibility Study (W499627) ( 646) 143 143

 33 SIS (W501595) 43 143 143

 34 SMG SIS (W501608) 38,909 143 143

 35 SIS (W501608) 143 143

 36 SMG SIS (W501609) 143 ( 2,435) 143

 37 SIS (W501609) 143 143

 38 SMG SIS (W501630) 143 ( 1,186) 143

 39 SIS (W501630) 143 143

 40 SIS (W502191) 143 143

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231
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 Service and Generation Interconnection Study Costs

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 SMG SIS (W502192) 143 ( 1,496) 143

 23 SIS (W502192) 143 143

 24 SMG SIS (W502193) 143 6,268 143

 25 SIS (W502193) 143 143

 26 SMG SIS (W502227) 143 5,913 143

 27 SIS (W502227) 143 143

 28 SMG SIS (W502231) 143 387 143

 29 SIS (W502231) 143 143

 30 SMG SIS (W502232) 143 376 143

 31 SIS (W502232) 143 143

 32 SIS (W502466) ( 385) 143 143

 33 SMG SIS (W502474) 143 2,888 143

 34 SIS (W502474) 143 143

 35 SMG SIS (W502842) 143 2,463 143

 36 SIS (W502842) 143 143

 37 Facilities Study (WA103398) ( 3) 143 ( 941) 143

 38 Facilities Study (WA103399) 226 143 143

 39 SIS (WA105240) ( 57) 143 143

 40 SMG SISSTD 2,799 143 143

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 SMG FACSTD (WA108732) 34 143 35,352 143

 23 SMG FACSTD (WA122533) 242 143 143

 24 SMG FACSTD (WA125613) 34 143 143

 25 SMG SISSTD (WA127662) 164 143 143

 26 SIS (WA127701) 1,971 143 138,333 143

 27 SIS (WA12773) 88 143 143

 28 SMG SISSTD (WA129301) 3,094 143 143

 29 SMG SISSTD (WA129495) 199 143 143

 30 Facilities Study (WA130324) 1,163 143 ( 781) 143

 31 Facilities Study (WA131362) 18,652 143 143

 32 SMG SIS (WA133988) 28 143 143

 33 SMG FACSTD (WA135348) 586 143 143

 34 SMG FACSTD (WA136886) 480 143 143

 35 SIS (WA141334) 2,045 143 143

 36 SIS (WA141336) ( 2,300) 143 143

 37 SIS (WA14320) 143 2,248 143

 38 Facilities Study (WA144239) 161 143 ( 25,000) 143

 39 SMG SISSTD (WA149964) 143 ( 20,000) 143

 40 Facilities Study (WA1894) ( 651) 143 143

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.2
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 SIS (WA1896) 87 143 143

 23 SIS (WA19661) 143 7,557 143

 24 SIS (WA20194) 143 3,708 143

 25 SMG FESSTD (WA20696) 103 143 143

 26 Feasibility Study (WA21556) ( 343) 143 143

 27 Feasibility Study (WA21557) ( 248) 143 143

 28 Facilities Study (WA32271) ( 441) 143 143

 29 Facilities Study (WA32691) ( 624) 143 143

 30 Facilities Study (WA32696) ( 630) 143 143

 31 Facilities Study (WA32698) ( 668) 143 143

 32 Facilities Study (WA34675) 278 143 143

 33 Facilities Study (WA34677) ( 569) 143 143

 34 Facilities Study (WA37362) ( 1,436) 143 143

 35 SIS (WA61589) 143 143

 36 Feasibility Study (WA61729) ( 259) 143 143

 37 SIS (WA61729) ( 801) 143 143

 38 SIS (WA63058) 175 143 ( 87,758) 143

 39 SMG SISSTD (WA64474) ( 505) 143 143

 40 Feasibility Study (WA67121) ( 398) 143 143

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.3
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 SIS (WA67121) ( 813) 143 143

 23 Facilities Study (WA69759) 360 143 143

 24 Facilities Study (WA69760) 745 143 143

 25 SMG FESSTD (WA71338) 143 229 143

 26 Facilities Study (WA73845) ( 129) 143 143

 27 SMG SIS (WA74455) 143 ( 7,220) 143

 28 SMG FACSTD (WA78073) 465 143 143

 29 Feasibility Study (WA78455) ( 21) 143 3,949 143

 30 SMG FACSTD (WA78524) 148 143 143

 31 SMG SISSTD (WA81603) 142 143 143

 32 Facilities Study (WA82014) ( 820) 143 143

 33 Facilities Study (WA83613) 143 69,514 143

 34 SIS (WA84273) 3,540 143 143

 35 SIS (WA85636) 199 143 143

 36 SMG SISSTD (WA86512) 146 143 143

 37 SMG SIS (WA92157) 240 143 143

 38 SMG SIS (WA92158) 39 143 143

 39 SMG SIS (WA92165) 66 143 143

 40 SIS (WA92332) ( 398) 143 143

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.4
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 SIS (WA94821) 876 143 143

 23 SIS (WA95638) 311 143 143

 24 Facilities Study (WA98450) 143 6,534 143

 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) Page 231.5
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

(a) (c) (d)

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)

 1 Deferred Compensation 32,527,167 1,255,416 33,782,583

 2

 3 Capital Contribution on Phoenix-Mead Transmission 12,700,564 108 332,040 12,368,524

 4 U-1345-90-269 Amortize through 2050

 5

 6 Income Taxes - AFUDC Equity 84,407,966 14,671,478 283, 410.1 3,161,586 95,917,858

 7 E-01345A-03-0437 Amortize through 2041

 8

 9 Palo Verde Rent Levelization 3,051,163 525 762,790 2,288,373

 10 E-01345A-03-0437 Amortize through 2015

 11

 12 Decontamination 225,466 407 55,045 170,421

 13 E-01345A-03-0437 Amortize through 2017

 14

 15 Deferred Loss on Sales of Property 4,561 254 4,561

 16

 17 Prior Flow Through of Tax Benefits 13,590,960 190 2,944,928 10,646,032

 18 Amortize through 2019

 19

 20 Deferred Fuel and Purchased Power 27,549,088 116,716,112 Various 71,572,891 72,692,309

 21 E-01345A-03-0437,E-01345A-05-0816,-0826,-0827

 22 Amortize through 2013

 23

 24 Deferred Fuel and Purchased Power Mark-to-Market 77,349,681 547, 555 37,371,258 39,978,423

 25 E-01345A-03-0437,E-01345A-05-0816,-0826,-0827

 26 Amortize through 2016

 27

 28 Deferred Fuel and Purchased Power - Accr. Interest 344,655 344,655

 29 E-01345A-08-0172

 30 Amortize through 2013

 31

 32 Four Corners Coal Reclamation 30,456,014 501 4,413,012 26,043,002

 33 E-01345A-05-0816,-0826,-0827 Amortize through 2016

 34

 35 Navajo Coal Reclamation 6,094,221 501 417,890 5,676,331

 36 E-01345A-08-0172 Amortize through 2026

 37

 38 Transmission Vegetation Management 40,888,477 571 9,086,328 31,802,149

 39 ER11-3468-000 Amortize through 2016

 40

 41 Pension and Other Postretirement Benefits 1,022,619,763 228.3, 926 242,129,250 780,490,513

 42 E-01345A-08-0172

 43

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

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

(a) (c) (d)

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)

 1 Pension and Other Postretirement Benefits Deferral 11,921,933 13,503,074 926 4,237,500 21,187,507

 2 E-01345A-08-0172

 3 Amortize through 2015

 4

 5 Demand Side Management 7,987,072 254 7,987,072

 6 E-01345A-03-0437,E-01345A-05-0816,-0826,-0827

 7 Amortize through 2013

 8

 9 Income Taxes - Change in Rates 2,854,815 308,759 3,163,574

 10 Amortize through 2041

 11

 12 Income Taxes - Medicare Subsidy 19,973,631 283, 410.1 1,534,994 18,438,637

 13 Amortize through 2024

 14

 15 Income Taxes - Investment Tax Credit Basis Adjust 15,416,924 11,952,951 283, 410.1 727,727 26,642,148

 16 Amortize through 2044

 17

 18 Property Tax Deferral 1,088,306 1,088,306

 19 E-01345A-08-0172

 20

 21 Lost Fixed Cost Recovery 7,346,000 7,346,000

 22 E-01345A-08-0172

 23 Amortize through 2014

 24

 25 FERC Transmission True up 9,971,160 9,971,160

 26 Amortize through 2014

 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 1,409,619,466 177,157,911 386,738,872 1,200,038,505
Schedule Page: 232 Line No.: 20 Column: d

411.8, 426.5, 555

Name of Respondent

Arizona Public Service Company 

This Report is:

(1) X An 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
Name 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

(a) (b) (c)

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.

 1 Rouse Promissory Note 2,774,979 131 924,992 1,849,987

 2

 3 Rouse Deferred Lease Payments 75,428,499 4,617,281 80,045,780

 4

 5 Redhawk Effluent Water 200,000 200,000

 6

 7 Information Sys Leases & Maint. 5,169,642 7,542,214 165 6,795,165 5,916,691

 8

 9 Unamortized Arrangement Fees 6,580,760 431,525 3,202,880 3,377,880

 10

 11 Prepaid Training 627,250 232 627,250

 12

 13 Long-Term Prepaid Insurance 1,012,352 165 122,801 889,551

 14

 15 Income Tax Receivable 132,378,571 132,378,571

 16

 17 Preliminary Legal Expenses 363,281 100,655 463,936

 18

 19 Transmission Debits 16,097,319 565 11,690,759 4,406,560

 20

 21 License Fees 820,250 920 820,250

 22

 23 Banked Energy 3,855,372 3,855,372

 24

 25 Prepaid Payroll Agreements 294,601 294,601

 26

 27 Prepaid Water Supply Agreement 3,983,647 1,962,870 5,946,517

 28

 29 Minor Items 206,626 111,225 Various 40,979 276,872

 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)

 245,310,527 240,529,568
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 INCOME TAXES (Account 190)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Description and Location Balance of Begining

(a) (b) (c)

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.

 1 Electric

 2 Risk Management Activities 145,086,840 81,515,171

 3 Pension and Other Post Retirement Liabilities 494,744,000 392,486,094

 4 Regulated Liabilities - Asset Retirement Obligation 89,955,947 101,334,237

 5 Regulated Liabilities - Other 85,464,667 88,850,433

 6 Credit and Loss Carryforwards 106,668,296 52,440,837

 7 Other 157,077,508 178,267,795

 8 TOTAL Electric (Enter Total of lines 2 thru 7) 1,078,997,258 894,894,567

 9 Gas

 10

 11

 12

 13

 14

 15 Other

 16 TOTAL Gas (Enter Total of lines 10 thru 15

 17 Other (Specify)

 18 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 1,078,997,258 894,894,567

Notes

FERC FORM NO. 1 (ED. 12-88) Page 234
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)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Class and Series of Stock and Number of shares

(a) (b) (c)

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.

 1 Common Stock 100,000,000 2.50

 2

 3 Total Common Stock 100,000,000

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

FERC FORM NO. 1 (ED. 12-91) Page 250
AS 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 Amount Shares

(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.

 71,264,947 178,162,367 1

 2

 71,264,947 178,162,367 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

FERC FORM NO. 1 (ED. 12-88) Page 251
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line Item Amount (a) (b)

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 Gain on Resale or Cancellation of Capital Stock - Account 210 1,505,626

 2 Balance at Beginning of Year: $1,505,626

 3 Credits

 4 Debits

 5 Balance at End of Year: $1,505,626

 6

 7 Misc Paid in Capital - Account 211

 8 Transfer of Contract from Pinnacle West Marketing & Trading LLC 12,323,739

 9 Balance at Beginning of Year: $12,323,739

 10 Credit

 11 Debit

 12 Balance at End of Year: $12,323,739

 13

 14 El Dorado transfer of Aegis software to APS 4,571,000

 15 Balance at Beginning of Year: $4,571,000

 16 Credit

 17 Debit

 18 Balance at End of Year: $4,571,000

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

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) X An 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
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 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

(a) (b)

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.

 1 Common Stock Expense 37,461,284

 2 Shelf Registration 50,368

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

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

22 TOTAL 37,511,652
Name 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 

(b) (c) (a)

Total expense, 

Premium or Discount

Principal Amount

(For new issue, give commission Authorization numbers and dates) Of Debt issued

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 Pollution Control Bonds Account 221

 2 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series A 49,400,000 1,062,971

 3 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series B 65,750,000 1,314,677

 4 Farmington, NM Pollution Control Revenue Refunding Bonds. 1994 Series C 31,500,000 776,159

 5 Coconino County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 1994 Series A 32,650,000 1,055,827

 6 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. Series 1998 16,870,000 538,817

 7 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 12,850,000 416,334

 8 Coconino County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series B 26,710,000 653,379

 9 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2002 Series A 90,000,000 585,000

 10 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series A 38,150,000 763,172

 11 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series B 32,000,000 351,144

 12 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series C 32,000,000 351,144

 13 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series D 32,000,000 351,144

 14 Navajo County, AZ Pollution Cntrl Corp Polllution Cntrl Rev Bonds. 2009 Series E 32,000,000 351,144

 15 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series A 35,975,000 357,088

 16 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series B 32,000,000 526,071

 17 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series C 32,000,000 317,633

 18 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series D 32,000,000 317,633

 19 Maricopa County, AZ Pollution Cntrl Corp Pollution Cntrl Rev Bonds. 2009 Series E 32,000,000 317,631

 20 Subtotal 655,855,000 10,406,968

 21

 22 Other Long Term Debt Account 224

 23 6.500% Unsecured Senior Note 375,000,000 2,547,180

 24 2,632,500 D

 25 5.625% Unsecured Senior Note 200,000,000 2,049,339

 26 2,288,000 D

 27 4.650% Unsecured Senior Note 300,000,000 2,529,839

 28 2,208,000 D

 29 5.800% Unsecured Senior Note 300,000,000 2,097,256

 30 810,000 D

 31 5.500% Unsecured Senior Note 250,000,000 2,362,692

 32 2,147,500 D

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

33 TOTAL 3,630,585,405 52,745,082
Name 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 

(b) (c) (a)

Total expense, 

Premium or Discount

Principal Amount

(For new issue, give commission Authorization numbers and dates) Of Debt issued

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 6.250% Unsecured Senior Note 250,000,000 1,659,703

 2 1,355,000 D

 3 6.875% Unsecured Senior Note 150,000,000 1,333,769

 4 226,500 D

 5 8.750% Unsecured Senior Note 500,000,000 4,301,413

 6 275,000 D

 7 5.05% Unsecured Senior Note 300,000,000 3,096,550

 8 2,022,000 D

 9 4.50% Unsecured Senior Note 325,000,000 3,321,373

 10 3,074,500 D

 11 COLI LOANS (Option II Benefits) 24,730,405

 12

 13 Subtotal 2,974,730,405 42,338,114

 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 52,745,082
Name 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

5/25/94 5/01/24 5/25/94 5/01/24 49,400,000 2,321,800 2

9/14/94 9/01/24 9/14/94 9/01/24 65,750,000 3,090,250 3

9/14/94 9/01/24 9/14/94 9/01/24 31,500,000 905,625 4

10/12/94 10/01/29 10/12/94 10/01/29 32,650,000 1,183,563 5

11/16/98 11/01/33 11/16/98 11/01/33 16,870,000 225,369 6

5/28/09 6/01/34 5/28/09 6/01/34 12,850,000 706,750 7

9/22/09 4/01/38 9/22/09 4/01/38 26,710,000 401,263 8

11/01/02 5/01/29 11/01/02 5/01/29 3,934,238 9

5/28/09 6/01/34 5/28/09 6/01/34 38,150,000 1,924,400 10

5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 1,760,000 11

5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 1,760,000 12

5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 1,840,000 13

5/28/09 6/01/34 5/28/09 6/01/34 32,000,000 1,840,000 14

6/26/09 5/01/29 6/26/09 5/01/29 35,975,000 2,158,500 15

6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 774,871 16

6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 1,840,000 17

6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 1,920,000 18

6/26/09 5/01/29 6/26/09 5/01/29 32,000,000 1,920,000 19

 565,855,000 30,506,629 20

 21

 22

3/01/02 3/01/12 3/01/02 3/01/12 4,062,500 23

 24

5/07/03 5/15/33 5/07/03 5/15/33 200,000,000 11,250,000 25

 26

5/07/03 5/15/15 5/07/03 5/15/15 300,000,000 13,950,000 27

 28

6/29/04 6/30/14 6/29/04 6/30/2014 300,000,000 17,400,000 29

 30

08/22/05 9/01/35 8/22/05 9/1/2035 250,000,000 13,750,000 31

 32

FERC FORM NO. 1 (ED. 12-96) Page 257

 3,165,585,406 189,852,046 33
Name 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.

8/03/06 8/01/16 8/03/06 8/01/16 250,000,000 15,625,000 1

 2

8/03/06 8/01/36 8/03/06 8/01/36 150,000,000 10,312,500 3

 4

2/26/09 3/01/19 2/26/09 3/01/19 500,000,000 43,750,000 5

 6

8/25/11 09/1/2041 8/25/11 09/1/2041 300,000,000 15,150,000 7

 8

1/13/12 4/01/42 1/13/12 4/01/42 325,000,000 14,095,417 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

 3,165,585,406 189,852,046 33
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) X An 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
Name 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)

(a) (b)

Line Amount 

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.

 1 Net Income for the Year (Page 117) 395,497,641

 2

 3

 4 Taxable Income Not Reported on Books

 5 Contributions in Aid of Construction 35,627,220

 6 Tax Gain/Loss on Sale of Business Property -39,460,943

 7 Other Taxable Income Not Reported on Books 8,095,396

 8

 9 Deductions Recorded on Books Not Deducted for Return

 10 Book Depreciation and Amortization 487,478,924

 11 Income Tax Per Books 244,395,541

 12 Pension and Other Post-Retirement Benefits 87,459,181

 13 Other Deductions Recorded on Books Not Deducted for Return (see footn) 215,331,968

 14 Income Recorded on Books Not Included in Return

 15 Book Gain/Loss on Sale of Business Property 725,079

 16 Mark-to-Market Adjustments -748,556

 17 Cash Surrender Value -1,187,854

 18 Other Income Recorded on Books Not Included in Return -3,967,107

 19 Deductions on Return Not Charged Against Book Income

 20 Tax Depreciation and Amortization -617,062,024

 21 Expenditures Capitalized for Book Not Tax -227,843,649

 22 Other Deductions on Return Not Charged Against Book Income (see footn) -354,459,367

 23

 24

 25

 26

 27 Federal Tax Net Income 229,881,451

 28 Show Computation of Tax:

 29 ($229,881,451) * 35% 80,458,508

 30

 31 Tax Carryforward Attributes Utilized -87,263,378

 32

 33 Net Federal Tax Expense -6,804,470

 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) X An 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
Name 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.

 1 Federal Income 32,547,937 -2,869,083 -6,804,870 -6,845,720 -24,968,542

 2 FICA 48,734,363 48,734,363

 3 Unemployment 301,640 301,640

 4 Heavy Vehicle Use 29,011 23,735 105,869

 5 Fuel Tax -27,388 34,423 17,794

 6 Subtotal 32,549,560 -2,869,083 42,289,291 42,313,946 -24,968,542

 7

 8 New Mexico: State and Local

 9 Real and Personal Property 4,727,251 8,499,160 8,734,624

 10 Income 3,251,250 612,025 50 -3,863,225

 11 Unemployment 45,039 45,039

 12 Sales 27,495 252,401 278,432

 13 Use 13,946 14,240

 14 Subtotal 8,005,996 9,422,571 9,072,385 -3,863,225

 15

 16 Arizona: State and Local

 17 Real and Personal Property 70,617,703 155,686,496 148,236,321

 18 Income -27,694,837 11,698,785 8,034,791 24,030,843

 19 Diesel Fuel

 20 State and City Sales 17,957,987 279,309,025 279,267,496

 21 State and City Use 1,355,713 26,369,228 26,611,147

 22 State and City Tax Reserve 7,356,602 793,410 137,492 -2,117,000

 23 Unemployment 638,726 638,726

 24 Subtotal 69,593,168 474,495,670 462,925,973 21,913,843

 25

 26 NV Real and Personal 32,210 128,563 96,492

 27 Unemployment

 28 Subtotal 32,210 128,563 96,492

 29

 30 California: State and Local

 31 Real and Personal Property 14,356 27,907 28,310

 32 Income -588,307 -3,417 7,310 599,034

 33 Unemployement -188 -188

 34 Subtotal -573,951 24,302 35,432 599,034

 35

 36 Utah: State -135,930

 37 Income 135,735 194 -1

 38 Subtotal 135,735 194 -1 -135,930

 39

 40

 -2,869,083

FERC FORM NO. 1 (ED. 12-96) Page 262

41 TOTAL 121,338,952 526,360,650 514,444,285 -9,256,873
Name 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.

 1 Texas: State

 2 Income 71 59 58 -72

 3 Unemployment

 4 Subtotal 71 59 58 -72

 5

 6 Sales Tax - Palo Verde Lease

 7 Payroll - other

 8 Sales Tax - Unbilled Revenue 11,596,163 -2,801,981

 9 Subtotal 11,596,163 -2,801,981

 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

41 TOTAL 121,338,952 526,360,650 514,444,285 -9,256,873
Name 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.

 9,678,080 -4,926,917 279,934 -7,084,804 1

 25,676,539 23,057,824 2

 301,640 3

 -53,123 23,735 4

 -10,759 34,423 5

 9,614,198 -4,926,917 25,956,473 16,332,818 6

 7

 8

 4,491,788 8,499,160 9

 4,254 636,962 -24,937 10

 45,039 11

 1,464 252,401 12

 -294 13,946 13

 4,492,958 4,254 9,136,122 286,449 14

 15

 16

 78,067,878 151,782,769 3,903,727 17

 4,333,637 12,376,854 -678,069 18

 19

 17,999,516 279,309,025 20

 1,113,794 26,369,228 21

 5,895,520 -2,026,355 702,765 22

 638,726 23

 103,076,708 4,333,637 162,133,268 310,245,402 24

 25

 64,281 128,563 26

 27

 64,281 128,563 28

 29

 30

 13,953 27,907 31

 -2,761 -656 32

 -188 33

 13,953 25,146 -844 34

 35

 36

 199 -5 37

 199 -5 38

 39

 40

FERC FORM NO. 1 (ED. 12-96) Page 263

 126,056,280 -589,026 197,379,830 326,863,820 41
Name 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

 126,056,280 -589,026 197,379,830 326,863,820 41
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)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Account Balance at Beginning

(c) (a) (b)

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.

 1 Electric Utility

 2 3%

 3 4%

 4 7%

 5 10% 510,843 255 420 81,816

 6 30% 57,729,498 255 44,396,673 420 2,736,106

 7

 8 TOTAL 58,240,341 44,396,673 2,817,922

Other (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 266
Balance at End

(h) (i)

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) Page 267
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 DEFFERED CREDITS (Account 253)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Description and Other DEBITS

 Credits

Account

(a) (b) (c)

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.

 1 Deferred Compensation 9,946,238 182.3 540,077 2,539,627 11,945,788

 2

 3 Palo Verde Unit II Rent

 4 Levelization (1/2000 to 12/2015) 18,990,313 242,411.6 4,747,579 14,242,734

 5

 6 Coal Reclamation 104,575,596 232 309,475 104,266,121

 7

 8 Navajo Retiree Health Care Costs 13,320,586 1,273,101 14,593,687

 9

 10 Legal Reserves 4,122,653 6,517,245 10,639,898

 11

 12 Construction Advances 4,596,902 143 2,021,461 2,575,441

 13

 14 AMI Meters 1,871,176 586, 107 1,871,176 477,613 477,613

 15

 16 License Fees 1,631,411 930.2 1,014,073 617,338

 17

 18 Leasehold Improvements 289,004 131 40,731 248,273

 19

 20 Escheated Funds 45,633 131 6,913 5,344 44,064

 21

 22 Banked Energy 3,914,360 555 3,914,360

 23

 24 SCE Right of Way 25,815,001 721,961 26,536,962

 25

 26 Tolling Agreements 36,607,110 36,607,110

 27

 28 Minor Item 413,721 143 273,570 140,151

 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 189,532,594 14,739,415 48,142,001 222,935,180
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 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.

 1 Accelerated Amortization (Account 281)

 2 Electric

 3 Defense Facilities

 4 Pollution Control Facilities

 5 Other (provide details in footnote):

 6

 7

 8 TOTAL Electric (Enter Total of lines 3 thru 7)

 9 Gas

 10 Defense Facilities

 11 Pollution Control Facilities

 12 Other (provide details in footnote):

 13

 14

 15 TOTAL Gas (Enter Total of lines 10 thru 14)

 16

 17 TOTAL (Acct 281) (Total of 8, 15 and 16)

 18 Classification of TOTAL

 19 Federal Income Tax

 20 State Income Tax

 21 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 272

NOTES
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 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

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

(e) (f) (h) (j) (g) (k) (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.

 1 Account 282

 2 Electric 2,300,125,503 398,712,558 252,007,093

 3 Gas

 4

 5 TOTAL (Enter Total of lines 2 thru 4) 2,300,125,503 398,712,558 252,007,093

 6

 7

 8 UTP recorded in ADIT for FERC 128,171,723 -4,609,243

 9 TOTAL Account 282 (Enter Total of lines 5 thru 2,428,297,226 394,103,315 252,007,093

 10 Classification of TOTAL

 11 Federal Income Tax 2,002,131,063 324,859,363 208,215,106

 12 State Income Tax 426,166,163 69,243,952 43,791,987

 13 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 274

NOTES
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 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

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

(e) (f) (h) (j) (g) (k) (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.

 1 Account 283

 2 Electric

 3 Reg. Assets - AFUDC 33,347,061 13,690,548 9,138,805

 4 Reg Assets - Mark to Market 30,558,550 12,923,975 27,686,525

 5 Reg Assets - Pension and Other 408,716,460 5,856,706 97,816,321

 6 Reg Assets - Other 74,214,822 27,351,469 32,146,191

 7 Mark to Market 57,492,627 3,198,457 51,710,295

 8 Other 15,647,069 62,162,669 43,273,970

 9 TOTAL Electric (Total of lines 3 thru 8) 619,976,589 125,183,824 261,772,107

 10 Gas

 11

 12

 13

 14

 15

 16

TOTAL Gas (Total of lines 11 thru 16) 17

 18

 19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 619,976,589 125,183,824 261,772,107

 20 Classification of TOTAL

 21 Federal Income Tax 511,170,697 103,189,026 215,902,742

 22 State Income Tax 108,805,892 21,994,798 45,869,365

 23 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 276

NOTES
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 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

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

(e) (f) (g) (h) (i) (j) (k)

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

219 24,231,211 33,212,000 7

 34,535,768 8

 24,231,211 507,619,517 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 24,231,211 507,619,517 19

 20

 19,973,787 418,430,768 21

 4,257,424 89,188,749 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

Account Credits

(a) (c) (d)

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)

 1 PacifiCorp CT Deferred Gain 16,000,000 456 2,000,000 14,000,000

 2 U-1345-90-269 Amortize through 2019

 3

 4 Asset Retirement Obligation 225,017,542 230 19,228,660 50,677,336 256,466,218

 5 FERC Order #552

 6

 7 Spent Nuclear Fuel Storage 48,916,373 518 4,616,988 1,369,476 45,668,861

 8 E-01345A-03-0437,E-01345A-05-0816,-0826,

 9 -0827 Amortize through 2047

 10

 11 Pinnacle West Energy Loan Interest 366,624 407.4 366,624

 12 E-01345A-03-0437,E-01345A-05-0816,-0826,

 13 -0827 Amortize through 2012

 14

 15 Income Taxes - Unamortized Investment Tax Credit 31,460,413 190 1,529,729 23,905,999 53,836,683

 16 E-01345A-05-0816,-0826,-0827

 17 Amortize through 2044

 18

 19 Sundance Maintenance 7,241,400 1,609,200 8,850,600

 20 E-01345A-05-0816,-0826,-0827

 21

 22 Income Tax - Change in Rates 62,282,038 6,663,796 68,945,834

 23 Amortize through 2041

 24

 25 Amonix Promissory Note 6,161,929 6,161,929

 26

 27 Renewable Energy Standard 53,522,266 549 114,050,446 98,695,741 38,167,561

 28 E-01345A-03-0437,E-01345A-05-0816,-0826,

 29 -0827

 30

 31 Star Center Patent Rights 1,125,393 1,125,393

 32 E-01345A-09-0357

 33

 34 AZ Sun Program 3,924,463 440, 442 17,498,692 18,684,398 5,110,169

 35 E-01345A-09-0338

 36

 37 Excess Deferred Taxes 13,590,960 190 2,944,928 10,646,032

 38 Amortize through 2019

 39

 40 Demand Side Management 440, 442 69,030,889 73,047,007 4,016,118

FERC FORM NO. 1/3-Q (REV 02-04) Page 278

41 TOTAL 470,102,597 231,767,095 274,752,727 513,088,229
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

Account Credits

(a) (c) (d)

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)

 1 E-01345A-03-0437, E-01345A-05-0816, -0826, -0827

 2 Amortize through 2013

 3

 4 Minor Items 493,196 107, 182.3 500,139 99,774 92,831

 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 470,102,597 231,767,095 274,752,727 513,088,229
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.

Title of Account

(a) (b) (c)

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)

 1 Sales of Electricity

 2 (440) Residential Sales 1,585,395,614 1,543,136,337

 3 (442) Commercial and Industrial Sales

 4 Small (or Comm.) (See Instr. 4) 1,274,445,187 1,265,970,898

 5 Large (or Ind.) (See Instr. 4) 174,856,673 171,428,100

 6 (444) Public Street and Highway Lighting 20,613,057 20,665,695

 7 (445) Other Sales to Public Authorities 183,950 204,903

 8 (446) Sales to Railroads and Railways

 9 (448) Interdepartmental Sales

 10 TOTAL Sales to Ultimate Consumers 3,055,494,481 3,001,405,933

 11 (447) Sales for Resale 178,534,117 165,945,037

 12 TOTAL Sales of Electricity 3,234,028,598 3,167,350,970

 13 (Less) (449.1) Provision for Rate Refunds -4,620,305 9,414,000

 14 TOTAL Revenues Net of Prov. for Refunds 3,238,648,903 3,157,936,970

 15 Other Operating Revenues

 16 (450) Forfeited Discounts 9,018,574 9,143,930

 17 (451) Miscellaneous Service Revenues 24,986,765 35,368,829

 18 (453) Sales of Water and Water Power

 19 (454) Rent from Electric Property 9,160,288 36,328,311

 20 (455) Interdepartmental Rents

 21 (456) Other Electric Revenues 4,480,274 4,676,926

 22 (456.1) Revenues from Transmission of Electricity of Others 31,636,457 30,983,064

 23 (457.1) Regional Control Service Revenues

 24 (457.2) Miscellaneous Revenues

 25

 26 TOTAL Other Operating Revenues 79,282,358 116,501,060

 27 TOTAL Electric Operating Revenues 3,317,931,261 3,274,438,030

FERC FORM NO. 1/3-Q (REV. 12-05) Page 300
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

Current Year (no Quarterly) Previous 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

 13,256,456 13,290,230 1,005,074 994,244 2

 3

 12,531,865 12,588,782 122,360 121,116 4

 2,222,623 2,188,600 3,721 3,744 5

 140,121 139,231 981 971 6

 3,071 3,483 160 161 7

 8

 9

 28,154,136 28,210,326 1,132,296 1,120,236 10

 4,342,927 3,433,100 49 46 11

 32,497,063 31,643,426 1,132,345 1,120,282 12

 13

 32,497,063 31,643,426 1,132,345 1,120,282 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) X An 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) X An 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

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of 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

(b) (c)

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 TOTAL
Name 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

(a) (b)

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.

 1 440 Residential

 2 E-12 3,576,341 481,258,688 434,491 8,231 0.1346

 3 ET-1 3,123,661 369,200,219 182,851 17,083 0.1182

 4 ET-2 3,202,570 388,181,720 207,404 15,441 0.1212

 5 ECT-2 1,571,617 165,469,997 63,467 24,763 0.1053

 6 ECT-1R 970,561 101,670,794 35,176 27,592 0.1048

 7 E-12 Low Income 336,107 31,996,332 38,332 8,768 0.0952

 8 ET-1 Low Income 144,024 14,185,708 9,614 14,981 0.0985

 9 ET-2 Low Income 289,136 28,640,884 18,417 15,699 0.0991

 10 ECT-2 Low Income 65,588 6,018,242 3,048 21,518 0.0918

 11 ECT-1R Low Income 13,542 1,255,627 662 20,456 0.0927

 12 ET-SP 8,204 928,932 533 15,392 0.1132

 13 EPR-2 1,510 159,689 84 17,976 0.1058

 14 EPR-6 87,386 9,429,835 10,980 7,959 0.1079

 15 ET-EV 296 32,542 15 19,733 0.1099

 16 E-47 1,747 530,969 0.3039

 17 Solar/Green Power 92,495

 18 Total Residential 13,392,290 1,599,052,673 1,005,074 13,325 0.1194

 19

 20 442 Commercial

 21 E-20 43,408 5,081,702 407 106,654 0.1171

 22 E-30 5,268 1,278,973 4,340 1,214 0.2428

 23 E-32 XS 1,401,087 184,913,967 81,485 17,194 0.1320

 24 E-32 S 2,523,528 333,754,301 29,078 86,785 0.1323

 25 E-32 M 3,088,701 302,523,796 3,879 796,262 0.0979

 26 E-32 L 2,935,447 243,377,649 805 3,646,518 0.0829

 27 E-32 TOU XS 3,852 430,549 80 48,150 0.1118

 28 E-32 TOU S 38,021 4,259,245 226 168,235 0.1120

 29 E-32 TOU M 74,018 6,997,485 68 1,088,500 0.0945

 30 E-32 TOU L 225,962 17,676,441 43 5,254,930 0.0782

 31 SCHOOL TOU RATE M 11,809 1,296,970 10 1,180,900 0.1098

 32 SCHOOL TOU RATE L 10,743 1,069,254 7 1,534,714 0.0995

 33 E-34 527,776 39,265,500 19 27,777,684 0.0744

 34 E-35 819,050 54,284,523 22 37,229,545 0.0663

 35 E-36 M 1,498 150,725 1 1,498,000 0.1006

 36 E-40 798 1

 37 E-47 20,763 8,021,561 0.3863

 38 E-56 793 463,891 1 793,000 0.5850

 39 E-221 339,840 31,115,796 1,354 250,990 0.0916

 40 EPR-2 9,839 909,515 25 393,560 0.0924

 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 TOTAL
Name 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

(a) (b)

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 EPR-6 279,078 28,562,245 491 568,387 0.1023

 2 Solar/Green Power 394,908

 3 SC-S 330,155 23,458,607 18 18,341,944 0.0711

 4 Total Commercial 12,690,636 1,289,288,401 122,360 103,716 0.1016

 5

 6 442 Industrial and Irrigation

 7 E-30 59 17,143 69 855 0.2906

 8 E-32 XS 46,610 7,577,186 2,201 21,177 0.1626

 9 E-32 S 83,950 11,211,528 785 106,943 0.1336

 10 E-32 M 188,931 21,044,573 274 689,529 0.1114

 11 E-32 L 390,787 34,428,613 95 4,113,547 0.0881

 12 E-32 TOU XS 50 9,102 2 25,000 0.1820

 13 E-32 TOU S 492 70,890 4 123,000 0.1441

 14 E-32 TOU M 4,694 451,010 4 1,173,500 0.0961

 15 E-32 TOU L 68,092 5,368,307 8 8,511,500 0.0788

 16 E-34 192,154 14,918,969 8 24,019,250 0.0776

 17 E-35 484,340 34,446,094 13 37,256,923 0.0711

 18 E-36 39,299 3,970,073 4 9,824,750 0.1010

 19 E-47 759 174,480 129 5,884 0.2299

 20 E-221 12,417 1,130,588 106 117,142 0.0911

 21 EPR-6 13,562 1,448,435 12 1,130,167 0.1068

 22 Special Contracts 722,113 40,928,190 7 103,159,000 0.0567

 23 Total Industrial & Irrigation 2,248,309 177,195,181 3,721 604,222 0.0788

 24

 25 444 Public Street Lighting 141,880 20,892,416 981 144,628 0.1473

 26 Total Public Street Lighting 141,880 20,892,416 981 144,628 0.1473

 27

 28 445 Other Public Authorities 3,013 184,306 160 18,831 0.0612

 29 Total Other Public Authorities 3,013 184,306 160 18,831 0.0612

 30

 31 Unbilled MWh & Revenue

 32 Residential Unbilled -135,834 -13,657,059 0.1005

 33 Commercial Unbilled -158,771 -14,843,214 0.0935

 34 Ind & Irrig. Unbilled -25,686 -2,338,508 0.0910

 35 Public Str Lighting Unbilled -1,701 -279,715 0.1644

 36 Other Public Auth Unbilled

 37 Total Unbilled Mwh & Revenue -321,992 -31,118,496 0.0966

 38

 39 449.1 Provision for Rate Refunds

 40 Residential PRR 1,917,000

 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 TOTAL
Name 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

(a) (b)

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 Commercial PRR 1,763,000

 2 Industrial & Irrigation PRR 364,000

 3 Public Street Lighting PRR

 4 Sales For Resale - Traditional 576,305

 5 Other Public Authorities PRR

 6 Total Provision for Rate Refunds 4,620,305

 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) X An 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
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Aguila Irrigation District RQ 86308 2.071 1.380 1.380

 2 Buckeye Irrigation District RQ 86306 0.582 0.485 0.484

 3 City of Williams RQ MRT Vol 1 5.311 5.311 4.102

 4 Electrical District No. 3 RQ 89695 90.176 90.176 83.556

 5 Electrical District No. 6 RQ 86307 0.043 0.007 0.007

 6 Electrical District No. 7 RQ 86304 0.000 0.000 0.000

 7 Electrical District No. 8 RQ 86310 14.158 9.439 9.438

 8 Harquahala Valley Irrigation District RQ 86309 4.450 4.079 4.078

 9 Maricopa County Municipal Water Conser RQ 86058 0.255 0.043 0.043

 10 McMullen Valley Irrigiation District RQ 86311 4.139 2.069 2.069

 11 Roosevelt Irrigation District RQ 86305 1.102 0.827 0.826

 12 Tohono O'Odham Utility Authority RQ 87975 8.255 8.255 6.798

 13 Tonopah Irrigation District RQ 86312 1.250 0.938 0.938

 14 Town of Wickenburg RQ 85726 1.644 0.816 0.815

FERC FORM NO. 1 (ED. 12-90) Page 310

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 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

SALES FOR RESALE (Account 447)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

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 Demand Monthly 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.

 1 Citigroup Energy Inc. IF MRT Vol 3

 2 Valley Electric Association IF WSPP

 3 Arizona Electric Power Cooperative SF WSPP

 4 Barclays Bank PLC SF MRT Vol 3

 5 BP Energy Company SF WSPP

 6 California Independent Systems Operator SF MRT Vol 3

 7 Cargill Power Markets, LLC SF WSPP

 8 Central Arizona Water Conservation Dist SF MRT Vol 3

 9 Citigroup Energy Inc. SF MRT Vol 3

 10 Constellation Energy Commodities Group SF WSPP

 11 DB Energy Trading LLC SF WSPP

 12 EDF Trading North America LLC SF WSPP

 13 El Paso Electric Company SF WSPP

 14 Gila River Power, L.P. SF MRT Vol 3

FERC FORM NO. 1 (ED. 12-90) Page 310.1

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 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

SALES FOR RESALE (Account 447)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

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 Demand Monthly 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.

 1 IBERDROLA Renewables, Inc. SF MRT Vol 3

 2 Idaho Power Company SF WSPP

 3 Imperial Irrigation District SF WSPP

 4 J. Aron & Company SF WSPP

 5 JP Morgan Ventures Energy Corporation SF WSPP

 6 Los Alamos County SF WSPP

 7 Los Angeles Dept of Water and Power SF WSPP

 8 Macquarie Energy LLC SF MRT Vol 3

 9 Morgan Stanley Capital Group, Inc. SF MRT Vol 3

 10 Nevada Power Company SF WSPP

 11 PacifiCorp SF MRT Vol 3

 12 Powerex Corp. SF WSPP

 13 PPL Energy Plus, LLC SF WSPP

 14 Public Service Co of Colorado SF WSPP

FERC FORM NO. 1 (ED. 12-90) Page 310.2

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 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

SALES FOR RESALE (Account 447)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

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 Demand Monthly 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.

 1 Public Service Co of New Mexico SF WSPP

 2 Rainbow Energy Marketing Corporation SF WSPP

 3 Salt River Project SF WSPP

 4 Sempra Generation SF WSPP

 5 Shell Energy North America (US), L.P. SF MRT Vol 3

 6 Sierra Pacific Power Co. SF WSPP

 7 Southern California Edison Company SF WSPP

 8 Southwestern Public Service Company SF WSPP

 9 Tenaska Power Services Company SF WSPP

 10 TransAlta Energy Marketing, US, Inc. SF WSPP

 11 Tri-State Generation and Transmission SF WSPP

 12 Tucson Electric Power Co. SF WSPP

 13 Twin Eagle Resource Management, LLC SF WSPP

 14 UNS Electric, Inc. SF WSPP

FERC FORM NO. 1 (ED. 12-90) Page 310.3

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 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

SALES FOR RESALE (Account 447)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

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 Demand Monthly 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.

 1 WAPA, Colorado River Storage Project SF WSPP

 2 WAPA, Desert Southwest Region SF WSPP

 3 Arizona Electric Power Cooperative OS WSPP

 4 Central Arizona Water Conservation Dist OS MRT Vol 3

 5 Los Angeles Dept of Water & Power OS WSPP

 6 Nevada Power Company OS WSPP

 7 PacifiCorp OS MRT Vol 3

 8 PacifiCorp Supplemental Coal OS RS # 182

 9 PacifiCorp Supplemental Other OS RS # 182

 10 Public Service Co of New Mexico OS WSPP

 11 Salt River Project OS WSPP

 12 Southwest Reserve Sharing Group OS SRSG1

 13 Tenaska Power Services Company OS WSPP

 14 Tri-State Generation and Transmission OS WSPP

FERC FORM NO. 1 (ED. 12-90) Page 310.4

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 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

SALES FOR RESALE (Account 447)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

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 Demand Monthly 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.

 1 Tucson Electric Power Co. OS WSPP

 2 WAPA, Desert Southwest Region OS WSPP

 3 Change in Estimate AD

 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

 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

SALES FOR RESALE (Account 447) (Continued)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (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.

 12,073 165,431 422,077 316,919 904,427 1

 4,256 58,298 143,326 229,280 430,904 2

 32,539 851,858 683,327 39,600 1,574,785 3

 500,037 40,554,163 4,312,217 44,866,380 4

 63 863 2,071 26,762 29,696 5

 383,803 383,803 6

 82,566 1,128,095 2,952,241 1,514,607 5,594,943 7

 35,690 488,810 1,250,605 627,084 2,366,499 8

 370 5,141 11,639 380,195 396,975 9

 18,007 247,466 646,142 540,158 1,433,766 10

 7,275 99,647 236,752 361,782 698,181 11

 45,589 3,881,398 450,679 4,332,077 12

 8,601 117,757 300,334 175,644 593,735 13

 7,098 197,949 252,226 159,960 610,135 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

 3,361,315
Name 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

(g) (h) (i) (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.

 122,800 9,222,279 9,222,279 1

 61,677 4,502,346 4,502,346 2

 26,549 655,514 655,514 3

 11,520 336,100 336,100 4

 27,200 808,200 808,200 5

 599,231 15,871,840 15,871,840 6

 119,149 3,915,748 3,915,748 7

 38,976 968,712 968,712 8

 269,212 7,976,501 7,976,501 9

 122,200 3,731,220 3,731,220 10

 55,625 1,544,800 1,544,800 11

 50,239 1,199,729 1,199,729 12

 29,510 909,530 909,530 13

 105,946 3,155,849 3,155,849 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

 3,361,315
Name 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

(g) (h) (i) (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.

 70,975 2,070,740 2,070,740 1

 12,347 307,211 307,211 2

 112,078 3,692,144 3,692,144 3

 29,200 954,650 954,650 4

 14,246 396,794 396,794 5

 7,632 225,906 225,906 6

 70,917 2,190,877 2,190,877 7

 79,917 2,290,139 2,290,139 8

 126,562 2,636,945 2,636,945 9

 10,250 266,305 266,305 10

 147,066 4,508,721 4,508,721 11

 39,043 1,157,476 1,157,476 12

 4,053 120,463 120,463 13

 400 13,600 13,600 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

 3,361,315
Name 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

(g) (h) (i) (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.

 181,771 5,484,239 5,484,239 1

 3,642 53,852 53,852 2

 160,475 4,292,683 4,292,683 3

 40,890 1,141,718 1,141,718 4

 90,585 3,051,029 3,051,029 5

 429 14,966 14,966 6

 85,875 2,301,233 2,301,233 7

 2,950 83,550 83,550 8

 1,534 57,593 57,593 9

 116,867 3,154,604 3,154,604 10

 81,938 2,051,389 2,051,389 11

 266,015 7,121,986 7,121,986 12

 23,620 671,733 671,733 13

 88,337 2,369,280 2,369,280 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

 3,361,315
Name 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

(g) (h) (i) (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.

 2,670 98,985 98,985 1

 403 9,668 9,668 2

 72 2,200 2,200 3

 2,240 50,640 50,640 4

 100 1,500 1,500 5

 100 1,200 1,200 6

 350 10,850 10,850 7

 11,000 289,847 289,847 8

 49,856 1,367,919 1,367,919 9

 7,600 163,528 163,528 10

 255 7,500 7,500 11

 4,226 4,000,046 4,000,046 12

 13 338 338 13

 13 650 650 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

 3,361,315
Name 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

(g) (h) (i) (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.

 416 8,766 8,766 1

 1 250 250 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) X An 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) X An 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
ELECTRIC 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

If the amount for previous year is not derived from previously reported figures, explain in footnote.

 1 1. POWER PRODUCTION EXPENSES

 2 A. Steam Power Generation

 3 Operation

 4 (500) Operation Supervision and Engineering 8,974,658 7,525,334

 5 (501) Fuel 242,031,514 251,582,097

 6 (502) Steam Expenses 24,977,443 25,631,368

 7 (503) Steam from Other Sources

 8 (Less) (504) Steam Transferred-Cr.

 9 (505) Electric Expenses 5,142,368 4,881,737

 10 (506) Miscellaneous Steam Power Expenses 14,508,293 13,119,031

 11 (507) Rents 618,665 656,702

 12 (509) Allowances

 13 TOTAL Operation (Enter Total of Lines 4 thru 12) 296,252,941 303,396,269

 14 Maintenance

 15 (510) Maintenance Supervision and Engineering 7,890,924 7,625,136

 16 (511) Maintenance of Structures 2,316,545 2,339,567

 17 (512) Maintenance of Boiler Plant 33,504,590 41,038,446

 18 (513) Maintenance of Electric Plant 9,456,739 9,702,765

 19 (514) Maintenance of Miscellaneous Steam Plant 12,020,766 8,131,801

 20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 65,189,564 68,837,715

 21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 361,442,505 372,233,984

 22 B. Nuclear Power Generation

 23 Operation

 24 (517) Operation Supervision and Engineering 25,295,808 23,549,422

 25 (518) Fuel 87,024,312 82,380,419

 26 (519) Coolants and Water 10,992,861 10,795,943

 27 (520) Steam Expenses 9,814,961 10,657,036

 28 (521) Steam from Other Sources

 29 (Less) (522) Steam Transferred-Cr.

 30 (523) Electric Expenses 8,906,115 6,753,419

 31 (524) Miscellaneous Nuclear Power Expenses 32,916,930 37,109,388

 32 (525) Rents 45,667,235 46,780,731

 33 TOTAL Operation (Enter Total of lines 24 thru 32) 220,618,222 218,026,358

 34 Maintenance

 35 (528) Maintenance Supervision and Engineering 7,609,265 9,205,764

 36 (529) Maintenance of Structures 2,033,706 3,051,702

 37 (530) Maintenance of Reactor Plant Equipment 11,754,828 13,727,332

 38 (531) Maintenance of Electric Plant 15,016,499 15,470,279

 39 (532) Maintenance of Miscellaneous Nuclear Plant 4,289,993 5,116,888

 40 TOTAL Maintenance (Enter Total of lines 35 thru 39) 40,704,291 46,571,965

 41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 261,322,513 264,598,323

 42 C. Hydraulic Power Generation

 43 Operation

 44 (535) Operation Supervision and Engineering

 45 (536) Water for Power

 46 (537) Hydraulic Expenses

 47 (538) Electric Expenses

 48 (539) Miscellaneous Hydraulic Power Generation Expenses

 49 (540) Rents

 50 TOTAL Operation (Enter Total of Lines 44 thru 49)

 51 C. Hydraulic Power Generation (Continued)

 52 Maintenance

 53 (541) Mainentance Supervision and Engineering

 54 (542) Maintenance of Structures

 55 (543) Maintenance of Reservoirs, Dams, and Waterways

 56 (544) Maintenance of Electric Plant

 57 (545) Maintenance of Miscellaneous Hydraulic Plant

 58 TOTAL Maintenance (Enter Total of lines 53 thru 57)

 59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)

FERC FORM NO. 1 (ED. 12-93) Page 320
ELECTRIC 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

If the amount for previous year is not derived from previously reported figures, explain in footnote.

 60 D. Other Power Generation

 61 Operation

 62 (546) Operation Supervision and Engineering 4,848,425 4,733,454

 63 (547) Fuel 430,876,882 485,651,374

 64 (548) Generation Expenses 8,391,866 9,859,505

 65 (549) Miscellaneous Other Power Generation Expenses 59,310,396 87,569,173

 66 (550) Rents

 67 TOTAL Operation (Enter Total of lines 62 thru 66) 503,427,569 587,813,506

 68 Maintenance

 69 (551) Maintenance Supervision and Engineering 431,641 527,323

 70 (552) Maintenance of Structures 989,042 1,048,716

 71 (553) Maintenance of Generating and Electric Plant 26,198,820 25,171,219

 72 (554) Maintenance of Miscellaneous Other Power Generation Plant 5,227,218 11,974,087

 73 TOTAL Maintenance (Enter Total of lines 69 thru 72) 32,846,721 38,721,345

 74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 536,274,290 626,534,851

 75 E. Other Power Supply Expenses

 76 (555) Purchased Power 240,316,470 209,835,470

 77 (556) System Control and Load Dispatching -1,917,184 -933,031

 78 (557) Other Expenses 3,282,363 3,482,412

 79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 241,681,649 212,384,851

 80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 1,400,720,957 1,475,752,009

 81 2. TRANSMISSION EXPENSES

 82 Operation

 83 (560) Operation Supervision and Engineering 2,388,542 899,743

 84

 85 (561.1) Load Dispatch-Reliability 2,103,063 1,684,637

 86 (561.2) Load Dispatch-Monitor and Operate Transmission System 2,341,566 1,948,197

 87 (561.3) Load Dispatch-Transmission Service and Scheduling 736,610 871,968

 88 (561.4) Scheduling, System Control and Dispatch Services 1,797,643 1,881,904

 89 (561.5) Reliability, Planning and Standards Development 618,834 674,513

 90 (561.6) Transmission Service Studies 305,832 205,233

 91 (561.7) Generation Interconnection Studies 303,583 206,181

 92 (561.8) Reliability, Planning and Standards Development Services 1,479,241

 93 (562) Station Expenses 1,005,496 970,761

 94 (563) Overhead Lines Expenses 2,600,189 2,468,793

 95 (564) Underground Lines Expenses 33,037 36,604

 96 (565) Transmission of Electricity by Others 18,827,481 17,009,889

 97 (566) Miscellaneous Transmission Expenses 5,302,721 6,699,447

 98 (567) Rents 6,614,513 33,198,800

 99 TOTAL Operation (Enter Total of lines 83 thru 98) 46,458,351 68,756,670

 100 Maintenance

 101 (568) Maintenance Supervision and Engineering 508,136 220,054

 102 (569) Maintenance of Structures 715,754 1,123,572

 103 (569.1) Maintenance of Computer Hardware

 104 (569.2) Maintenance of Computer Software

 105 (569.3) Maintenance of Communication Equipment 127,583 109,469

 106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant

 107 (570) Maintenance of Station Equipment 5,270,412 4,975,659

 108 (571) Maintenance of Overhead Lines 13,876,015 9,685,381

 109 (572) Maintenance of Underground Lines 116,932 98,238

 110 (573) Maintenance of Miscellaneous Transmission Plant 173,362 899,659

 111 TOTAL Maintenance (Total of lines 101 thru 110) 20,788,194 17,112,032

 112 TOTAL Transmission Expenses (Total of lines 99 and 111) 67,246,545 85,868,702

FERC FORM NO. 1 (ED. 12-93) Page 321
ELECTRIC 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

If the amount for previous year is not derived from previously reported figures, explain in footnote.

 113 3. REGIONAL MARKET EXPENSES

 114 Operation

 115 (575.1) Operation Supervision

 116 (575.2) Day-Ahead and Real-Time Market Facilitation

 117 (575.3) Transmission Rights Market Facilitation

 118 (575.4) Capacity Market Facilitation

 119 (575.5) Ancillary Services Market Facilitation

 120 (575.6) Market Monitoring and Compliance

 121 (575.7) Market Facilitation, Monitoring and Compliance Services

 122 (575.8) Rents

 123 Total Operation (Lines 115 thru 122)

 124 Maintenance

 125 (576.1) Maintenance of Structures and Improvements

 126 (576.2) Maintenance of Computer Hardware

 127 (576.3) Maintenance of Computer Software

 128 (576.4) Maintenance of Communication Equipment

 129 (576.5) Maintenance of Miscellaneous Market Operation Plant

 130 Total Maintenance (Lines 125 thru 129)

 131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)

 132 4. DISTRIBUTION EXPENSES

 133 Operation

 134 (580) Operation Supervision and Engineering 4,172,189 3,966,769

 135 (581) Load Dispatching 1,187,005 1,177,206

 136 (582) Station Expenses 1,204,328 1,014,006

 137 (583) Overhead Line Expenses 1,940,611 2,700,977

 138 (584) Underground Line Expenses 2,304,862 3,267,249

 139 (585) Street Lighting and Signal System Expenses 121,925 254,831

 140 (586) Meter Expenses 6,569,888 3,670,762

 141 (587) Customer Installations Expenses -162,663 -596,934

 142 (588) Miscellaneous Expenses 35,911,273 33,791,179

 143 (589) Rents 511,744 554,148

 144 TOTAL Operation (Enter Total of lines 134 thru 143) 53,761,162 49,800,193

 145 Maintenance

 146 (590) Maintenance Supervision and Engineering 2,156,951 1,089,840

 147 (591) Maintenance of Structures 480,095 793,279

 148 (592) Maintenance of Station Equipment 2,036,021 1,779,004

 149 (593) Maintenance of Overhead Lines 16,194,307 14,128,113

 150 (594) Maintenance of Underground Lines 10,141,361 7,979,839

 151 (595) Maintenance of Line Transformers 2,904,087 3,117,327

 152 (596) Maintenance of Street Lighting and Signal Systems 196,255 342,884

 153 (597) Maintenance of Meters -972

 154 (598) Maintenance of Miscellaneous Distribution Plant 4,102,146 4,235,725

 155 TOTAL Maintenance (Total of lines 146 thru 154) 38,211,223 33,465,039

 156 TOTAL Distribution Expenses (Total of lines 144 and 155) 91,972,385 83,265,232

 157 5. CUSTOMER ACCOUNTS EXPENSES

 158 Operation

 159 (901) Supervision 2,430,710 2,652,510

 160 (902) Meter Reading Expenses 6,645,446 9,023,911

 161 (903) Customer Records and Collection Expenses 37,977,436 37,859,669

 162 (904) Uncollectible Accounts 5,290,371 5,751,502

 163 (905) Miscellaneous Customer Accounts Expenses 492,420 796,111

 164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 52,836,383 56,083,703

FERC FORM NO. 1 (ED. 12-93) Page 322
ELECTRIC 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

If the amount for previous year is not derived from previously reported figures, explain in footnote.

 165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES

 166 Operation

 167 (907) Supervision 825,644 1,909,536

 168 (908) Customer Assistance Expenses 74,898,452 69,636,634

 169 (909) Informational and Instructional Expenses 430,897 458,287

 170 (910) Miscellaneous Customer Service and Informational Expenses 1,012,463 1,398,510

 171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 77,167,456 73,402,967

 172 7. SALES EXPENSES

 173 Operation

 174 (911) Supervision 118

 175 (912) Demonstrating and Selling Expenses 5,007,605 4,116,856

 176 (913) Advertising Expenses 100,000 140,612

 177 (916) Miscellaneous Sales Expenses 4,351,664 4,571,381

 178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 9,459,269 8,828,967

 179 8. ADMINISTRATIVE AND GENERAL EXPENSES

 180 Operation

 181 (920) Administrative and General Salaries 96,475,201 82,438,082

 182 (921) Office Supplies and Expenses 24,365,845 21,307,992

 183 (Less) (922) Administrative Expenses Transferred-Credit 24,303,198 24,567,258

 184 (923) Outside Services Employed 18,840,236 13,319,392

 185 (924) Property Insurance 5,723,043 6,252,520

 186 (925) Injuries and Damages 8,427,023 8,347,123

 187 (926) Employee Pensions and Benefits 101,437,381 85,901,784

 188 (927) Franchise Requirements

 189 (928) Regulatory Commission Expenses 16,886,150 18,863,617

 190 (929) (Less) Duplicate Charges-Cr.

 191 (930.1) General Advertising Expenses 2,759,086 2,198,723

 192 (930.2) Miscellaneous General Expenses -56,055,295 -49,184,536

 193 (931) Rents 9,711,342 7,656,082

 194 TOTAL Operation (Enter Total of lines 181 thru 193) 204,266,814 172,533,521

 195 Maintenance

 196 (935) Maintenance of General Plant 8,219,115 5,972,727

 197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 212,485,929 178,506,248

 198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 1,911,888,924 1,961,707,828

FERC FORM NO. 1 (ED. 12-93) Page 323
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Dynegy Arlington - Tolling Agreement RQ 277,944

 2 Gila River Power - Tolling Agreement RQ 191,940

 3 Salt River Project RQ 11,652

 4 CE Turbo LLC LF N/A N/A N/A

 5 Morgan Stanley Capital Group, Inc. LF N/A N/A N/A

 6 Ajo Improvement Co. (Phelps Dodge) LF N/A N/A N/A

 7 Co-Generation LF N/A N/A N/A

 8 Electrical District #5 LF N/A N/A N/A

 9 Net Inadvertant LF N/A N/A N/A

 10 Citigroup Energy Inc. IF N/A N/A N/A

 11 Macquarie Energy LLC IF N/A N/A N/A

 12 Morgan Stanley Capital Group, Inc. IF N/A N/A N/A

 13 Shell Energy North American (US), L.P IF N/A N/A N/A

 14 WAPA, Desert Southwest Region IF N/A N/A N/A

FERC FORM NO. 1 (ED. 12-90) Page 326

Total
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 AG-1 Contracts SF N/A N/A N/A

 2 Arizona Electric Power Cooperative SF N/A N/A N/A

 3 California Independent System Operator SF N/A N/A N/A

 4 Cagrill Power Markets, LLC SF N/A N/A N/A

 5 Catalyst Paper Snowflake Inc. SF N/A N/A N/A

 6 Central Arizona Water Conservation Dis SF N/A N/A N/A

 7 Citigroup Energy Inc. SF N/A N/A N/A

 8 Constellation Energy Commodities Group SF N/A N/A N/A

 9 DB Energy Trading LLC SF N/A N/A N/A

 10 EDF Trading North America LLC SF N/A N/A N/A

 11 El Paso Electric Company SF N/A N/A N/A

 12 Gila River Power, LLC SF N/A N/A N/A

 13 IBERDROLA Renewables, Inc. SF N/A N/A N/A

 14 Idaho Power Company SF N/A N/A N/A

FERC FORM NO. 1 (ED. 12-90) Page 326.1

Total
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Imperial Irrigation District SF N/A N/A N/A

 2 JP Morgan Ventrues Energy Corporation SF N/A N/A N/A

 3 Los Angeles Dept of Water & Power SF N/A N/A N/A

 4 Macquarie Energy LLC SF N/A N/A N/A

 5 Morgan Stanely Capital Group Inc. SF N/A N/A N/A

 6 Nevada Power Company SF N/A N/A N/A

 7 PacifiCorp SF N/A N/A N/A

 8 Powerex Corp. SF N/A N/A N/A

 9 PPL Energy Plus, LLC SF N/A N/A N/A

 10 Public Service Co of Colorado SF N/A N/A N/A

 11 Public Serivce Co of New Mexico SF N/A N/A N/A

 12 Rainbow Energy Marketing Corporation SF N/A N/A N/A

 13 Salt River Project SF N/A N/A N/A

 14 Sempra Generation SF N/A N/A N/A

FERC FORM NO. 1 (ED. 12-90) Page 326.2

Total
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Shell Energy North America (US), Inc. SF N/A N/A N/A

 2 Sierra Pacific Power Co. SF N/A N/A N/A

 3 Southern California Edison SF N/A N/A N/A

 4 Southwestern Public Service SF N/A N/A N/A

 5 TransAlta Energy Marketing, US, Inc. SF N/A N/A N/A

 6 Tri-State Generation and Transmission SF N/A N/A N/A

 7 Tucson Electric Power Company SF N/A N/A N/A

 8 Twin Eagle Resource Management, LLC SF N/A N/A N/A

 9 UNS Electric, Inc. SF N/A N/A N/A

 10 Valley Electric Association, Inc. SF N/A N/A N/A

 11 WAPA, Desert Southwest Region SF N/A N/A N/A

 12 Aragonne Wind, LLC LU N/A N/A N/A

 13 Glendale Energy LLC LU N/A N/A N/A

 14 High Lonesome Wind Ranch, LLC LU N/A N/A N/A

FERC FORM NO. 1 (ED. 12-90) Page 326.3

Total
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Perrin Ranch Wind LLC LU N/A N/A N/A

 2 RE Ajo 1 LLC LU N/A N/A N/A

 3 RE Bagdad Solar 1 LLC LU N/A N/A N/A

 4 Snowflake Power, LLC LU N/A N/A N/A

 5 SunE AZ 1 LLC LU N/A N/A N/A

 6 SunE AZ 2 LLC LU N/A N/A N/A

 7 Waste Management Renewable Energy, LLC LU N/A N/A N/A

 8 Aguila Irrigation District EX 141 N/A N/A N/A

 9 Buckeye Water Conservation & Drainage EX 155 N/A N/A N/A

 10 City of Azusa Exchange EX N/A N/A N/A

 11 Electric District #6 EX 126 N/A N/A N/A

 12 Electric District #7 EX 128 N/A N/A N/A

 13 Electric District #8 EX 140 N/A N/A N/A

 14 Harqualhala Valley Power District EX 153 N/A N/A N/A

FERC FORM NO. 1 (ED. 12-90) Page 326.4

Total
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Maricopa City Municipal Water Conservt EX 168 N/A N/A N/A

 2 McMullen Valley Water Conservt Dist EX 142 N/A N/A N/A

 3 PafifiCorp Exchange EX 182 N/A N/A N/A

 4 Roosevelt Irrigation District EX 158 N/A N/A N/A

 5 Tonopah Irrigation District EX 143 N/A N/A N/A

 6 AG-1 Contracts OS N/A N/A N/A

 7 Banked Energy OS N/A N/A N/A

 8 California Independent System Operator OS N/A N/A N/A

 9 Cargill Power Markets, LLC OS N/A N/A N/A

 10 Catalyst Paper Snowflake Inc. OS N/A N/A N/A

 11 Central Arizona Water Conservation Dis OS N/A N/A N/A

 12 Constellation Energy Commodities Group OS N/A N/A N/A

 13 EDF Trading North America LLC OS N/A N/A N/A

 14 Gila River Power, LLC OS N/A N/A N/A

FERC FORM NO. 1 (ED. 12-90) Page 326.5

Total
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 JP Morgan Ventures Energy Corporation OS N/A N/A N/A

 2 Los Angeles Dept of Water & Power OS N/A N/A N/A

 3 Options and Hedges OS N/A N/A N/A

 4 PacifiCorp OS N/A N/A N/A

 5 Power Supply Adjustor OS N/A N/A N/A

 6 Powerex Corp. OS N/A N/A N/A

 7 Public Service Co of New Mexico OS N/A N/A N/A

 8 Salt River Project OS N/A N/A N/A

 9 SFAS 133 OS N/A N/A N/A

 10 Shell Energy North America (US), L.P. OS N/A N/A N/A

 11 Southwest Reserve Sharing Group OS N/A N/A N/A

 12 Tri-State Generation and Transmission OS N/A N/A N/A

 13 Twin Eagle Resource Management, LLC OS N/A N/A N/A

 14 WAPA, Desert Southwest Region OS N/A N/A N/A

FERC FORM NO. 1 (ED. 12-90) Page 326.6

Total
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Change in Estimate AD N/A N/A N/A

 2 Prior Years Adjustment AD N/A N/A N/A

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

FERC FORM NO. 1 (ED. 12-90) Page 326.7

Total
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 1,667,663 59,089,200 2,510,948 61,600,148 1

 2,303,284 37,819,038 3,684,614 41,503,652 2

 188,506 1,800,000 5,418,358 1,408,780 8,627,138 3

 65,969 4,301,759 4,301,759 4

 27,600 1,564,806 1,564,806 5

 27 6

 217 7

 80 8

 46,743 9

 471,883 33,427,812 33,427,812 10

 61,662 4,054,277 4,054,277 11

 122,800 6,109,300 6,109,300 12

 174,701 5,164,679 5,164,679 13

 12 434,200 434,200 14

FERC FORM NO. 1 (ED. 12-90) Page 327

 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 75,264 2,413,082 2,413,082 1

 271 8,001 8,001 2

 122,280 2,431,916 3,390,916 5,822,832 3

 27,032 448,141 448,141 4

 193 10,588 10,588 5

 438 12,838 12,838 6

 97,219 3,286,844 3,286,844 7

 203 3,771 3,771 8

 124 2,852 2,852 9

 21,202 475,984 475,984 10

 2,645 59,452 59,452 11

 5,463 164,684 164,684 12

 80 1,200 1,200 13

 109,168 2,126,373 2,126,373 14

FERC FORM NO. 1 (ED. 12-90) Page 327.1

 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 2,980 84,719 84,719 1

 3,667 126,015 126,015 2

 2,294 95,320 95,320 3

 2,244 61,956 61,956 4

 4,980 174,806 174,806 5

 14,950 504,200 504,200 6

 29,330 757,518 757,518 7

 19,274 652,996 652,996 8

 12,088 171,548 171,548 9

 19 1,245 1,245 10

 13,756 413,313 413,313 11

 50,096 573,474 573,474 12

 10,237 364,225 364,225 13

 63,225 2,229,970 2,229,970 14

FERC FORM NO. 1 (ED. 12-90) Page 327.2

 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 998 11,808 11,808 1

 161 5,635 5,635 2

 1,459 27,960 27,960 3

 182 5,553 5,553 4

 10,597 235,499 235,499 5

 898 24,518 24,518 6

 5,103 125,958 125,958 7

 553 8,968 8,968 8

 68 1,557 1,557 9

 25 1,825 1,825 10

 1 11

 278,448 16,686,558 16,686,558 12

 16,535 1,294,000 1,294,000 13

 286,692 14,246,176 14,246,176 14

FERC FORM NO. 1 (ED. 12-90) Page 327.3

 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 199,444 16,743,705 16,743,705 1

 10,362 1,242,550 1,242,550 2

 35,976 4,856,760 4,856,760 3

 112,019 9,390,896 9,390,896 4

 27,469 2,864,150 2,864,150 5

 1,502 91,251 91,251 6

 8,208 642,823 642,823 7

 3,373 541 8

 439 9

 171,396 213,563 -1,109,134 -1,109,134 10

 1,039 608 11

 2,655 2,754 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 -8,382,182 240,316,470
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 4,416 4,591 1

 3,880 1,079 2

 571,391 576,642 -1,458,123 -1,458,123 3

 466 466 4

 135 87 5

 1,158 17,903 17,903 6

 -4,283,780 -4,283,780 7

 1,250 38,756 584,893 623,649 8

 51 2,504 2,504 9

 881 8,584 8,584 10

 1,865 44,995 44,995 11

 400 12,500 12,500 12

 22,943 640,376 640,376 13

 1,423 45,043 45,043 14

FERC FORM NO. 1 (ED. 12-90) Page 327.5

 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 410 13,280 13,280 1

 1,200 49,200 49,200 2

 28,302,133 28,302,133 3

 75 2,250 2,250 4

 -46,262,616 -46,262,616 5

 5,800 192,800 192,800 6

 6,800 141,578 141,578 7

 2,132 67,278 67,278 8

 1,874,032 1,874,032 9

 426 9,139 9,139 10

 977 76,420 76,420 11

 30 7,350 7,350 12

 525 7,280 7,280 13

 154,628 4,616,483 4,616,483 14

FERC FORM NO. 1 (ED. 12-90) Page 327.6

 7,021,543 767,870 807,241 98,708,238 149,990,414 -8,382,182 240,316,470
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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) X An 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) X An 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
TRANSMISSION 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Payment By

(a) (b) (c) (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.

 1 Ajo Improvement Arizona Public Service Co Ajo Improvement FNO

 2 Central Arizona Project Salt River Project Central Arizona Project FNO

 3 Navajo Tribal Utility Authority Tucson Electric Power Navajo Tribal Utility Authority FNO

 4 Public Service of New Mexico Various Various FNO

 5 Southwest Transmission Cooperative Various Various FNO

 6 Arizona Public Service Various Various FNS

 7 Arizona Public Service Pinnacle West Capital Corporation Arizona Public Service Company FNS

 8 Arizona Public Service Arizona Public Service Company Arizona Public Service Company FNS

 9 Arizona Public Service Various Arizona Public Service Company FNS

 10 AkChin DOE WAPA Upper AkChin LFP

 11 PacifiCorp Not Available Not Available LFP

 12 Public Service of New Mexico Not Available Not Available LFP

 13 Salt River Project Not Available Not Available LFP

 14 Shell Energy North America Not Available Not Available LFP

 15 Snowflake White Mountain Power Not Available Not Available LFP

 16 Electrical District No. 2 DOE WAPA Lower Electrical District No. 2 OLF

 17 Luke AFB Main Base DOE WAPA Upper Luke Air Force Base OLF

 18 Marine Corp DOE WAPA Lower Marine Corps Air Station OLF

 19 PacifiCorp Not Available Not Available OLF

 20 Public Service of New Mexico Public Service of New Mexico Public Service of New Mexico OLF

 21 Salt River Project Fringe Salt River Project Salt River Project OLF

 22 San Carlos Indian Irrigation San Carlos Indian Irrigation San Carlos Indian Irrigation OLF

 23 Tucson Electric Power Company Tucson Electric Power Tucson Electric Power OLF

 24 Unit B Irrigation & Drain Arizona Power Authority Unit B Irrigation District OLF

 25 Yuma Cogeneration - Firm Yuma Cogeneration Association San Diego Gas and Electric OLF

 26 Yuma Irrigation District DOE WAPA Lower Yuma Irrigation District OLF

 27 Yuma-Mesa DOE WAPA Lower Yuma-Mesa Irrigation District OLF

 28 AZPS for APS Merchant P-T-P Not Available Not Available SFP

 29 Brookfield Energy Marketing L.P. Not Available Not Available SFP

 30 Citigroup Energy, Inc. Not Available Not Available SFP

 31 Central Arizona Water Conservation Dist. Not Available Not Available SFP

 32 EDF Trading North America, LLC Not Available Not Available SFP

 33 El Paso Electric Company Not Available Not Available SFP

 34 Florida Power & Light (FPL) Not Available Not Available SFP

FERC FORM NO. 1 (ED. 12-90) Page 328

TOTAL
TRANSMISSION 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Payment By

(a) (b) (c) (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.

 1 Gila River Power Not Available Not Available SFP

 2 JP Morgan Ventures Energy Corp. Not Available Not Available SFP

 3 Macquarie Cook Power Inc. Not Available Not Available SFP

 4 Morgan Stanley Not Available Not Available SFP

 5 PacifiCorp Not Available Not Available SFP

 6 PacifiCorp Power Marketing (Iberdrola) Not Available Not Available SFP

 7 Panda Gila River Not Available Not Available SFP

 8 Powerex Not Available Not Available SFP

 9 Public Service of New Mexico Not Available Not Available SFP

 10 Salt River Project Not Available Not Available SFP

 11 Shell Energy North America Not Available Not Available SFP

 12 Southern California Edison Co. Not Available Not Available SFP

 13 Sun Devil Power Holdings, LLC (Wheelback) Not Available Not Available SFP

 14 TransAlta Energy Marketing Not Available Not Available SFP

 15 Tri-State G & T(was Plains G&T) Not Available Not Available SFP

 16 Tucson Electric Power Company Not Available Not Available SFP

 17 Western Area Power Admin. (CRSP) Not Available Not Available SFP

 18 AZPS for APS Merchant P-T-P Not Available Not Available NF

 19 Cargill-Alliant, LLC Not Available Not Available NF

 20 Central Arizona Water Conservation Dist Not Available Not Available NF

 21 Citigroup Energy, Inc. Not Available Not Available NF

 22 EDF Trading North America, LLC Not Available Not Available NF

 23 El Paso Electric Company Not Available Not Available NF

 24 Florida Power & Light Not Available Not Available NF

 25 JP Morgan Ventures Energy Corp. Not Available Not Available NF

 26 Macquarie Cook Power, L.P. Not Available Not Available NF

 27 Morgan Stanley Not Available Not Available NF

 28 Nevada Power Company Not Available Not Available NF

 29 Noble Americas Gas & Power Corp. Not Available Not Available NF

 30 Open Access Technology Int'l Not Available Not Available NF

 31 PacifiCorp Not Available Not Available NF

 32 PacifiCorp Power Marketing (Iberdrola) Not Available Not Available NF

 33 Panda Gila River Not Available Not Available NF

 34 Powerex Not Available Not Available NF

FERC FORM NO. 1 (ED. 12-90) Page 328.1

TOTAL
TRANSMISSION 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

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Payment By

(a) (b) (c) (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.

 1 Public Service of New Mexico Not Available Not Available NF

 2 Salt River Project Merchant Not Available Not Available NF

 3 Sempra Trading Corp Not Available Not Available NF

 4 Shell Energy North America Not Available Not Available NF

 5 Southern California Edison Co. Not Available Not Available NF

 6 Tenaska Power Services Co. Not Available Not Available NF

 7 TransAlta Energy Marketing Not Available Not Available NF

 8 Tri-State G & T(was Plains G&T) Not Available Not Available NF

 9 Tucson Electric Power Company Not Available Not Available NF

 10 Western Area Power Admin. (CRSP) Not Available Not Available NF

 11 Yuma Cogeneration Association Yuma Cogeneration Association San Diego Gas and Electric NF

 12 Imperial Irrigation District Not Available Not Available OS

 13 Salt River Project Schedule Q Pinnacle Peak Ocotillo 230 OS

 14 Other Not Available Not Available AD

 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

TOTAL
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 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.

OATT Cholla Ajo Customers 13,708 13,365 1

OATT West Wing Substation Various 330,329 322,071 2

OATT Saguaro Various 42,282 42,159 3

OATT Various Various 353,517 344,679 4

OATT Various Various 24,196 23,591 5

OATT Various Various 6

OATT Various Various 28,100,857 28,100,858 7

OATT Various Various 793,791 742,561 8

OATT Various Various 9

OATT Maricopa Substation AkChin Customer 35,880 32,184 10

OATT Various Various 7 11

OATT Various Various 160 12

OATT Various Various 771 1,771,651 1,734,554 13

OATT Various Various 135 14

OATT Various Various 14 15

245 Coolidge Substation Casa Grande 8 8 16

162 Pinnacle Peak Sub Luke Substation 5 18,779 18,234 17

166 Gila Substation Marine Corps Air Stn 2 10,409 9,992 18

180/183 Various Various 380 2,714,767 2,714,768 19

73 Palo Verde Four Corners 130 1,025,590 1,025,590 20

3 West Phoenix Sub West Phoenix Sub 8,066 7,324 21

202 Coolidge Substation Westwing Substation 59 54 22

32 Four Corners Saguaro Plant 100 568,810 568,810 23

181 Gila Substation District Customer 23 22 24

198 Riverside Substation North Gila Sub 51 84,206 83,364 25

39 Gila Substation District Pumps 6,180 5,579 26

31 Gila Substation Yuma Mesa Load 198 178 27

OATT Various Various 240,448 240,448 28

OATT Various Various 2,249 2,249 29

OATT Various Various 1,187 1,187 30

OATT Various Various 1,276 1,276 31

OATT Various Various 3,938 3,938 32

OATT Various Various 2,172 2,172 33

OATT Various Various 2,214 2,214 34

FERC FORM NO. 1 (ED. 12-90) Page 329

 1,755 37,339,290 37,225,864
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 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.

OATT Various Various 2,039 2,039 1

OATT Various Various 605 605 2

OATT Various Various 1,807 1,807 3

OATT Various Various 1,920 1,920 4

OATT Various Various 8,877 8,877 5

OATT Various Various 26 26 6

OATT Various Various 10,998 10,998 7

OATT Various Various 13,584 13,584 8

OATT Various Various 4,381 4,381 9

OATT Various Various 566,802 566,802 10

OATT Various Various 301 301 11

OATT Various Various 5,854 5,854 12

OATT Various Various 1,474 1,474 13

OATT Various Various 666 666 14

OATT Various Various 200 200 15

OATT Various Various 30,487 30,487 16

OATT Various Various 256 256 17

OATT Various Various 797 797 18

OATT Various Various 1,303 1,303 19

OATT Various Various 59 59 20

OATT Various Various 1,419 1,419 21

OATT Various Various 905 905 22

OATT Various Various 3,615 3,615 23

OATT Various Various 453 453 24

OATT Various Various 658 658 25

OATT Various Various 811 811 26

OATT Various Various 11,340 11,340 27

OATT Various Various 275 275 28

OATT Various Various 256 256 29

WCRT Various Various 2,345 2,345 30

OATT Various Various 75,567 75,567 31

OATT Various Various 1,541 1,541 32

OATT Various Various 5,375 5,375 33

OATT Various Various 12,192 12,192 34

FERC FORM NO. 1 (ED. 12-90) Page 329.1

 1,755 37,339,290 37,225,864
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 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.

OATT Various Various 4,750 4,750 1

OATT Various Various 260,564 260,564 2

OATT Various Various 150 150 3

OATT Various Various 162 162 4

OATT Various Various 5,002 5,002 5

OATT Various Various 175 175 6

OATT Various Various 22,905 22,905 7

OATT Various Various 12,198 12,198 8

OATT Various Various 100,623 100,623 9

OATT Various Various 310 310 10

198 Riverside Substation North Gila Sub 6,473 6,408 11

OATT Various Various 12

3 Pinnacle Peak Ocotillo 230 13

OATT Various 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 37,225,864
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 FOR OTHERS (Account 456) (Continued)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other 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 3,368 12,085,051 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 1,860 1,416,890 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 26,744 28,449 32

 18,009 18,009 33

 8,307 8,307 34

FERC FORM NO. 1 (ED. 12-90) Page 330

 21,360,890 8,993,243 1,282,324 31,636,457
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 FOR OTHERS (Account 456) (Continued)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other 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 55,278 114,626 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

 15,387 728 16,115 15

 9,552 180,604 190,156 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 60,445 78,703 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 8,993,243 1,282,324 31,636,457
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 FOR OTHERS (Account 456) (Continued)

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other 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 1,245,547 1,354,025 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 73,381 78,598 8

 26,187 565,376 591,563 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 8,993,243 1,282,324 31,636,457
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) X An 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) X An 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

(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

(a) (b)

(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

Page 331

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

(a) (c) (d)

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)

 1 Delivered to Wheeler

 2 Arizona Public Service OS 2,179,220 2,179,220

 3 Salt River Project OLF 190,188 184,649 663,923 663,923

 4 Salt River Project OLF 165,670 160,844 578,332 578,332

 5 Salt River Project OLF 1,199,790 1,175,113 257,750 257,750

 6 Salt River Project OLF 114,365 112,012 240,560 2,389 242,949

 7 Salt River Project OLF 38,886 38,086 140,354 2,904 143,258

 8 Salt River Project LFP 502,816 492,474 1,522,841 221,038 1,743,879

 9 Salt River Project OLF 1,835,637 1,817,464

 10 Department of Energy OS 53,500 53,500

 11 Department of Energy OLF 2,200,495 2,115,862 4,649,909 289,303 4,939,212

 12 Department of Energy NF 5,310 5,106 11,221 698 11,919

 13 San Carlos IIP OLF 68 59 247 1,453 6,096 7,796

 14 Department of Energy LFP 134,675 134,675 1,758,367 203,500 1,961,867

 15 Salt River Project LFP 221,576 217,019 817,251 145,924 140,980 1,104,155

 16 Salt River Project LFP 199,056 190,083

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332

TOTAL 7,195,535 7,014,705 8,597,972 9,339,869 889,640 18,827,481
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

(a) (c) (d)

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)

 1 Delivered to Wheeler

 2 Southwest Trans Coop SFP 530 530

 3

 4 Received from Wheeler

 5 Salt River Project OS 3,979 3,595

 6 Southern Cal Edison LFP 21,259 20,277 150,203 2,156 152,359

 7 Electrical District #2 OLF 270 252

 8 Electrical District #3 OS 3,477 3,477 122,843 122,843

 9 Electrical District #4 OLF 543 493 16,567 16,567

 10 Electrical District #5 OLF 1,378 1,272 1,370 127,541 58 128,969

 11

 12 Other Charges

 13 Bureau of Indian Affair OS 99 99 111,956 547 9,577 122,080

 14 Department of Energy OS 63,980 63,980

 15 Tuscon Electric Power 1,289 1,289 8,404 2,721 11,125

 16 Salt River Project SFP 72,623 72,623 182,283 68,354 250,637

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1

TOTAL 7,195,535 7,014,705 8,597,972 9,339,869 889,640 18,827,481
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

(a) (c) (d)

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)

 1 Other Charges

 2 Public Service of NM OS 3,632 3,632 23,205 2,207 25,412

 3 Department of Energy OS 91,968 41,217 133,185

 4 Department of Energy OS 1,445,925 1,445,925

 5 Department of Energy OS 19,661 19,661 417,681 417,681

 6 Department of Energy OS 258,263 244,059 2,048,958 2,048,958

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2

TOTAL 7,195,535 7,014,705 8,597,972 9,339,869 889,640 18,827,481
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) X An 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) X An 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) X An 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 450.3
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)

Arizona Public Service Company X

04/10/2013 2012/Q4

Line Description Amount

No. (a) (b)

 1 Industry Association Dues 1,545,370

 2 Nuclear Power Research Expenses

 3 Other Experimental and General Research Expenses 299,591

 4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities

 5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 -150,764

 6 Allocation of Parent Company Costs 9,036,560

 7 Bank Fees 511,180

 8 Billed to Others-Services Performed -67,719,234

 9 Communication Service 43,132

 10 Materials & Supplies 178,539

 11 Miscellaneous Payroll -515,454

 12 Outside Services 648,405

 13 Rents/Leases 20,808

 14 Transportation Expense 27,547

 15 Travel 19,025

 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 TOTAL
Name 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

(a) (b) (d)

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)

 1 Intangible Plant 49,960,802 49,960,802

 2 Steam Production Plant 44,058,222 10,098,525 2,135 54,158,882

 3 Nuclear Production Plant 56,948,171 -3,602,881 8,711,828 62,057,118

 4 Hydraulic Production Plant-Conventional -441,067 -441,067

 5 Hydraulic Production Plant-Pumped Storage

 6 Other Production Plant 50,699,038 50,699,038

 7 Transmission Plant 38,077,426 2,552,217 40,629,643

 8 Distribution Plant 111,501,398 679,309 112,180,707

 9 Regional Transmission and Market Operation

 10 General Plant 27,983,496 6,540,011 34,523,507

 11 Common Plant-Electric

 12 TOTAL 328,826,684 6,495,644 68,446,302 403,768,630

RATES

Franchises 302 4.00%

Software 303 10.00% - 50.00%

Misc. Intangibles 303.0 20.00%

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 Charges
Name 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.

(a) (b) (c) (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 337
Name 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

(a) (b) (c)

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.

 1 ACC/RUCO Expenses

 2 Annual Assessment by Arizona Corporation

 3 Commission (ACC) and Annual Assessment by

 4 Residential Utility Consumer Office (RUCO) 6,601,264 6,601,264

 5 Legal and Filing Fees 50,450 50,450

 6 Consulting Fees 125,859 125,859

 7 Payroll and Employee Expense 1,986,354 1,986,354

 8 Est. ACC and RUCO Assessments on Unbilled Rev -62,551 -62,551

 9 Other 8,348 8,348

 10

 11 FERC Expenses

 12 Regulatory Assessment by FERC 2,409,330 2,409,330

 13 Legal and Filing Fees 973,937 973,937

 14 Consulting Fees 89,652 89,652

 15 Payroll and Employee Expenses 184,575 184,575

 16 Other 10,594 10,594

 17

 18 NRC Expenses

 19 NRC License Fees 4,508,338 4,508,338

 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

46 TOTAL 13,456,381 3,429,769 16,886,150
Name 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.

(f) (i) (j) (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 928 6,601,264 4

Electric 928 50,450 5

Electric 928 125,859 6

Electric 928 1,986,354 7

Electric 928 -62,551 8

Electric 928 8,348 9

 10

 11

Electric 928 2,409,330 12

Electric 928 973,937 13

Electric 928 89,652 14

Electric 928 184,575 15

Electric 928 10,594 16

 17

 18

Electric 928 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 351

 16,886,150 46
Name 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

(a) (b)

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

 1 A(1)e RENEWABLES

 2 A(1)e HPS

 3 A(1)e TECH TRANSFER

 4

 5 Total

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

FERC FORM NO. 1 (ED. 12-87) Page 352
Name of Respondent This Report Is:

(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.

 12,405 573,845 5490 586,250 1

 56,949 8,746 5880 65,695 2

 4,947 644 9302 5,591 3

 4

 74,301 583,235 657,536 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

FERC FORM NO. 1 (ED. 12-87) Page 353
Name of Respondent This Report Is:

(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

(a) (b) (c)

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.

 1 Electric

 2 Operation

 3 Production 119,544,671

 4 Transmission 13,918,391

 5 Regional Market

 6 Distribution 37,947,924

 7 Customer Accounts 29,154,033

 8 Customer Service and Informational 2,738,306

 9 Sales 5,281,179

 10 Administrative and General 90,491,342

 11 TOTAL Operation (Enter Total of lines 3 thru 10) 299,075,846

 12 Maintenance

 13 Production 44,638,221

 14 Transmission 3,382,723

 15 Regional Market

 16 Distribution 25,151,804

 17 Administrative and General 3,413,180

 18 TOTAL Maintenance (Total of lines 13 thru 17) 76,585,928

 19 Total Operation and Maintenance

 20 Production (Enter Total of lines 3 and 13) 164,182,892

 21 Transmission (Enter Total of lines 4 and 14) 17,301,114

 22 Regional Market (Enter Total of Lines 5 and 15)

 23 Distribution (Enter Total of lines 6 and 16) 63,099,728

 24 Customer Accounts (Transcribe from line 7) 29,154,033

 25 Customer Service and Informational (Transcribe from line 8) 2,738,306

 26 Sales (Transcribe from line 9) 5,281,179

 27 Administrative and General (Enter Total of lines 10 and 17) 93,904,522

 28 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 375,661,774 375,661,774

 29 Gas

 30 Operation

 31 Production-Manufactured Gas

 32 Production-Nat. Gas (Including Expl. and Dev.)

 33 Other Gas Supply

 34 Storage, LNG Terminaling and Processing

 35 Transmission

 36 Distribution

 37 Customer Accounts

 38 Customer Service and Informational

 39 Sales

 40 Administrative and General

 41 TOTAL Operation (Enter Total of lines 31 thru 40)

 42 Maintenance

 43 Production-Manufactured Gas

 44 Production-Natural Gas (Including Exploration and Development)

 45 Other Gas Supply

 46 Storage, LNG Terminaling and Processing

 47 Transmission

FERC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Classification

(a) (b) (c)

Direct Payroll Allocation of Total 

(d)

Distribution Payroll charged for

Clearing Accounts

DISTRIBUTION OF SALARIES AND WAGES (Continued)

 48 Distribution

 49 Administrative and General

 50 TOTAL Maint. (Enter Total of lines 43 thru 49)

 51 Total Operation and Maintenance

 52 Production-Manufactured Gas (Enter Total of lines 31 and 43)

 53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,

 54 Other Gas Supply (Enter Total of lines 33 and 45)

 55 Storage, LNG Terminaling and Processing (Total of lines 31 thru

 56 Transmission (Lines 35 and 47)

 57 Distribution (Lines 36 and 48)

 58 Customer Accounts (Line 37)

 59 Customer Service and Informational (Line 38)

 60 Sales (Line 39)

 61 Administrative and General (Lines 40 and 49)

 62 TOTAL Operation and Maint. (Total of lines 52 thru 61)

 63 Other Utility Departments

 64 Operation and Maintenance

 65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 375,661,774 375,661,774

 66 Utility Plant

 67 Construction (By Utility Departments)

 68 Electric Plant 134,566,080 134,566,080

 69 Gas Plant

 70 Other (provide details in footnote):

 71 TOTAL Construction (Total of lines 68 thru 70) 134,566,080 134,566,080

 72 Plant Removal (By Utility Departments)

 73 Electric Plant

 74 Gas Plant

 75 Other (provide details in footnote):

 76 TOTAL Plant Removal (Total of lines 73 thru 75)

 77 Other Accounts (Specify, provide details in footnote):

 78 Inventory 235,582 235,582

 79 Deferred Debits 226,810 226,810

 80 Other Revenue 60,237 60,237

 81 Miscellaneous Income Deductions 2,999,313 2,999,313

 82 Palo Verde Generating Station 204,601,975 204,601,975

 83 Four Corners 28,214,887 28,214,887

 84 Cholla-Pacificorp 9,342,440 9,342,440

 85 Yucca 1,874,719 1,874,719

 86 Morgan Pinnacle Peak 629,602 629,602

 87 Hoodoo NU 258,637 258,637

 88 Panda NU 653,335 653,335

 89 Cedar NU 741,324 741,324

 90 Navajo STS 500 KV Line 1,145,070 1,145,070

 91 All Other Billed to Participants 891,290 891,290

 92 Studies 132,474 132,474

 93 Street Lights 584,388 584,388

 94 Miscellaneous Billings 1,480,156 1,480,156

 95 TOTAL Other Accounts 254,072,239 254,072,239

 96 TOTAL SALARIES AND WAGES 764,300,093 764,300,093

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 356
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of X

04/10/2013

2012/Q4

Line

 No.

Description of Item(s) Balance at End of

(a) (b) (c)

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

 1 Energy

 2 Net Purchases (Account 555) 611,091 1,433,022 5,115,282 5,861,588

 3 Net Sales (Account 447) ( 4,446,866) ( 6,900,815) ( 12,211,993) ( 15,871,841)

 4 Transmission Rights

 5 Ancillary Services

 6 Other Items (list separately)

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

 44

 45

( 3,835,775) ( 5,467,793) ( 7,096,711) ( 10,010,253)

FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397

46 TOTAL
Name 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

 1 Scheduling, System Control and Dispatch 15,279,690 mWh 1,839,819 16,465,626 mWh 2,063,701

 2 Reactive Supply and Voltage

 3 Regulation and Frequency Response 15,038,445 mWh 6,957,180 15,038,445 mWh 6,963,348

 4 Energy Imbalance -4,067 mWh -163,501

 5 Operating Reserve - Spinning 15,038,445 mWh 16,091,429 15,038,445 mWh 16,098,362

 6 Operating Reserve - Supplement 15,038,445 mWh 2,035,102 15,038,445 mWh 2,035,315

 7 Other

 8 Total (Lines 1 thru 7) 60,395,025 26,923,530 61,576,894 26,997,225

FERC FORM NO. 1 (New 2-04) Page 398
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 TRANSMISSION SYSTEM PEAK LOAD

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Monthly Peak

MW - Total

(a) (b) (c)

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

 1 January 5,227 13 800 4,149 107 451 160 350

 2 February 4,866 15 800 3,863 101 451 160 281

 3 March 4,380 8 800 3,609 100 451 160 50

 4 Total for Quarter 1 14,473 11,621 308 1,353 480 681

 5 April 5,893 22 1700 4,959 101 451 160 213

 6 May 6,901 31 1700 5,978 107 455 160 191

 7 June 7,646 27 1700 6,834 112 455 160 75

 8 Total for Quarter 2 20,440 17,771 320 1,361 480 479

 9 July 9,137 10 1700 6,799 116 845 1,268 100

 10 August 8,716 8 1700 7,333 108 845 318 102

 11 September 7,030 2 1600 6,143 102 459 318 2

 12 Total for Quarter 3 24,883 20,275 326 2,149 1,904 204

 13 October 6,579 1 1700 5,430 105 457 318 261

 14 November 4,915 5 1900 3,723 58 455 318 351

 15 December 5,226 20 800 4,054 108 455 318 280

 16 Total for Quarter 4 16,720 13,207 271 1,367 954 892

 76,516 62,874 1,225 6,230 3,818 2,256

Total Year to

Date/Year

 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
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 ISO/RTO TRANSMISSION SYSTEM PEAK LOAD

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

Monthly Peak

MW - Total

(a) (b) (c)

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

 1 January

 2 February

 3 March

 4 Total for Quarter 1

 5 April

 6 May

 7 June

 8 Total for Quarter 2

 9 July

 10 August

 11 September

 12 Total for Quarter 3

 13 October

 14 November

 15 December

 16 Total for Quarter 4

Total Year to

Date/Year

 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400a
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 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.

1 SOURCES OF ENERGY

2 Generation (Excluding Station Use):

3 Steam 10,947,566

4 Nuclear 9,292,770

5 Hydro-Conventional

6 Hydro-Pumped Storage

7 Other 7,395,396

8 Less Energy for Pumping

Net Generation (Enter Total of lines 3 27,635,732

through 8)

9

10 Purchases 7,021,543

11 Power Exchanges:

12 Received 767,870

13 Delivered 807,241

14 Net Exchanges (Line 12 minus line 13) -39,371

15 Transmission For Other (Wheeling)

16 Received 37,339,290

17 Delivered 37,225,864

Net Transmission for Other (Line 16 minus 113,426

line 17)

18

19 Transmission By Others Losses -1,538

TOTAL (Enter Total of lines 9, 10, 14, 18 34,729,792

and 19)

20

21 DISPOSITION OF ENERGY

Sales to Ultimate Consumers (Including 28,154,136

Interdepartmental Sales)

22

Requirements Sales for Resale (See 754,164

instruction 4, page 311.)

23

Non-Requirements Sales for Resale (See 3,588,763

instruction 4, page 311.)

24

25 Energy Furnished Without Charge

Energy Used by the Company (Electric 60,706

Dept Only, Excluding Station Use)

26

27 Total Energy Losses 2,172,023

TOTAL (Enter Total of Lines 22 Through 34,729,792

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

(a) (b) (c)

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)

 29 January 2,612,017 295,381 4,113 13 800

 30 February 2,416,865 391,498 3,813 15 800

 31 March 2,291,498 284,960 3,582 8 800

 32 April 2,219,452 171,831 4,912 22 1700

 33 May 2,773,771 339,279 5,897 31 1700

 34 June 3,095,058 229,531 6,750 27 1700

 35 July 3,301,772 329,520 6,696 10 1700

 36 August 3,467,365 333,550 7,207 8 1700

 37 September 3,175,259 531,567 6,036 2 1600

 38 October 3,558,190 475,133 5,339 1 1700

 39 November 2,749,584 211,111 3,680 5 1900

 40 December 3,068,961 230,967 4,005 20 800

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) X An 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
Cholla 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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.

 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Over 50% Outdoor

 3 Year Originally Constructed 1962

 4 Year Last Unit was Installed 1981

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 113.60 0.00

 6 Net Peak Demand on Plant - MW (60 minutes) 120 0

 7 Plant Hours Connected to Load 8441 0

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 116 0

 10 When Limited by Condenser Water 116 0

 11 Average Number of Employees 52 0

 12 Net Generation, Exclusive of Plant Use - KWh 830109058 0

 13 Cost of Plant: Land and Land Rights 895453 0

 14 Structures and Improvements 13307829 0

 15 Equipment Costs 131165663 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 145368945 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 1279.6562 0

 19 Production Expenses: Oper, Supv, & Engr 1288140 0

 20 Fuel 17812415 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 2648737 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 538923 0

 26 Misc Steam (or Nuclear) Power Expenses 1049070 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 1262098 0

 30 Maintenance of Structures 416384 0

 31 Maintenance of Boiler (or reactor) Plant 1974906 0

 32 Maintenance of Electric Plant 200680 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 834292 0

 34 Total Production Expenses 28025645 0

 35 Expenses per Net KWh 0.0338 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Oil Gas Total

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons Bbls MCF

 38 Quantity (Units) of Fuel Burned 470500 0 4241 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 9238 0 843693 00 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 36.935 0.000 5.727 0.000 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 37.801 0.000 6.783 0.000 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 2.046 0.000 8.039 2.048 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.021 0.000 0.084 0.021 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 10475.908 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402
Four Corners 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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 Steam

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Over 50% Outdoor

 3 Year Originally Constructed 1963

 4 Year Last Unit was Installed 1970

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 190.10

 6 Net Peak Demand on Plant - MW (60 minutes) 0 174

 7 Plant Hours Connected to Load 0 7147

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 0 170

 10 When Limited by Condenser Water 0 170

 11 Average Number of Employees 0 52

 12 Net Generation, Exclusive of Plant Use - KWh 0 1062437484

 13 Cost of Plant: Land and Land Rights 0 12746

 14 Structures and Improvements 0 19711280

 15 Equipment Costs 0 94828727

 16 Asset Retirement Costs 0 20640912

 17 Total Cost 0 135193665

 18 Cost per KW of Installed Capacity (line 17/5) Including 0 711.1713

 19 Production Expenses: Oper, Supv, & Engr 0 488042

 20 Fuel 0 23560355

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 2791988

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 459202

 26 Misc Steam (or Nuclear) Power Expenses 0 2210675

 27 Rents 0 127366

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 546090

 30 Maintenance of Structures 0 222221

 31 Maintenance of Boiler (or reactor) Plant 0 2851388

 32 Maintenance of Electric Plant 0 194891

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 1230884

 34 Total Production Expenses 0 34683102

 35 Expenses per Net KWh 0.0000 0.0326

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) total Coal Gas Total

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons MCF

 38 Quantity (Units) of Fuel Burned 00 0 675960 90700 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 8751 1008732 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 32.800 5.563 0.000

 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 33.947 6.767 0.000

 42 Average Cost of Fuel Burned per Million BTU 2.031 0.000 0.000 1.940 6.708 1.976

 43 Average Cost of Fuel Burned per KWh Net Gen 0.021 0.000 0.000 0.022 0.075 0.022

 44 Average BTU per KWh Net Generation 10423.891 0.000 0.000 0.000 0.000 11221.209

FERC FORM NO. 1 (REV. 12-03) Page 402.1
Four Corners 5 Ocotillo 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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 Steam Steam

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Over 50% Outdoor Over 50% Outdoor

 3 Year Originally Constructed 1969 1960

 4 Year Last Unit was Installed 1970 1960

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 122.72 113.60

 6 Net Peak Demand on Plant - MW (60 minutes) 119 104

 7 Plant Hours Connected to Load 7306 834

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 116 110

 10 When Limited by Condenser Water 116 110

 11 Average Number of Employees 21 10

 12 Net Generation, Exclusive of Plant Use - KWh 712468716 40416000

 13 Cost of Plant: Land and Land Rights 10042 154669

 14 Structures and Improvements 6322010 2403680

 15 Equipment Costs 93604943 31073748

 16 Asset Retirement Costs 1281645 0

 17 Total Cost 101218640 33632097

 18 Cost per KW of Installed Capacity (line 17/5) Including 824.7934 296.0572

 19 Production Expenses: Oper, Supv, & Engr 163233 0

 20 Fuel 14297959 1741104

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 1554745 132822

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 106330 786324

 26 Misc Steam (or Nuclear) Power Expenses 538284 221813

 27 Rents 75695 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 187790 0

 30 Maintenance of Structures 97031 228100

 31 Maintenance of Boiler (or reactor) Plant 2201115 122780

 32 Maintenance of Electric Plant 586049 388448

 33 Maintenance of Misc Steam (or Nuclear) Plant 683118 197962

 34 Total Production Expenses 20491349 3819353

 35 Expenses per Net KWh 0.0288 0.0945

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Gas Total Gas Total

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons MCF MCF

 38 Quantity (Units) of Fuel Burned 404970 15380 0 477510 0 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 9155 1009558 0 1021082 0 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 33.859 5.908 0.000 2.997 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 35.033 7.188 0.000 3.646 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 1.913 7.120 1.924 3.571 3.571 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.020 0.074 0.020 0.043 0.043 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 10429.785 0.000 12063.960 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.2
Navajo Yucca 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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 Steam Units 1,2,3 Comb. Turbine

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Over 50% Outdoor Over 50% Outdoor

 3 Year Originally Constructed 1974 1971

 4 Year Last Unit was Installed 1976 2008

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 337.34 23.60

 6 Net Peak Demand on Plant - MW (60 minutes) 319 21

 7 Plant Hours Connected to Load 8784 279

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 315 19

 10 When Limited by Condenser Water 315 0

 11 Average Number of Employees 0 1

 12 Net Generation, Exclusive of Plant Use - KWh 1637996004 3602000

 13 Cost of Plant: Land and Land Rights 25111 0

 14 Structures and Improvements 30481164 214413

 15 Equipment Costs 235774584 2843435

 16 Asset Retirement Costs 1865912 0

 17 Total Cost 268146771 3057848

 18 Cost per KW of Installed Capacity (line 17/5) Including 794.8858 129.5698

 19 Production Expenses: Oper, Supv, & Engr 3058704 29887

 20 Fuel 39486174 372523

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 1946285 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 550354 42494

 26 Misc Steam (or Nuclear) Power Expenses 2584999 23227

 27 Rents 85176 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 1211907 0

 30 Maintenance of Structures 243128 365

 31 Maintenance of Boiler (or reactor) Plant 5139557 0

 32 Maintenance of Electric Plant 1151156 100732

 33 Maintenance of Misc Steam (or Nuclear) Plant 716227 164

 34 Total Production Expenses 56173667 569392

 35 Expenses per Net KWh 0.0343 0.1581

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Oil Total Oil Gas Total

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons Bbls Bbls MCF

 38 Quantity (Units) of Fuel Burned 783043 2902 0 0 59200 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 10763 137147 0 0 1018209 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 49.310 135.158 0.000 0.000 2.933 0.000

 41 Average Cost of Fuel per Unit Burned 49.693 198.048 0.000 0.000 6.293 0.000

 42 Average Cost of Fuel Burned per Million BTU 2.309 34.382 2.340 0.000 6.180 6.180

 43 Average Cost of Fuel Burned per KWh Net Gen 0.024 0.354 0.024 0.000 0.103 0.103

 44 Average BTU per KWh Net Generation 0.000 0.000 10300.449 0.000 0.000 16734.592

FERC FORM NO. 1 (REV. 12-03) Page 402.3
Yucca 5 Yucca 6

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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 Comb. Turbine Comb. Turbine

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Over 50% Outdoor Over 50% Outdoor

 3 Year Originally Constructed 2007 2007

 4 Year Last Unit was Installed 2008 2008

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 60.50 60.50

 6 Net Peak Demand on Plant - MW (60 minutes) 48 48

 7 Plant Hours Connected to Load 1550 1668

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 48 48

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 3 2

 12 Net Generation, Exclusive of Plant Use - KWh 54593000 59993000

 13 Cost of Plant: Land and Land Rights 0 0

 14 Structures and Improvements 869473 862522

 15 Equipment Costs 35986928 35568803

 16 Asset Retirement Costs 0 0

 17 Total Cost 36856401 36431325

 18 Cost per KW of Installed Capacity (line 17/5) Including 609.1967 602.1707

 19 Production Expenses: Oper, Supv, & Engr 1645167 0

 20 Fuel 3567452 3851379

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 23897 23520

 26 Misc Steam (or Nuclear) Power Expenses 112551 285483

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 39 0

 30 Maintenance of Structures 5531 6078

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 571645 172965

 33 Maintenance of Misc Steam (or Nuclear) Plant 197670 112061

 34 Total Production Expenses 6123952 4451486

 35 Expenses per Net KWh 0.1122 0.0742

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Oil Gas Total Oil Gas Total

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Bbls MCF Bbls MCF

 38 Quantity (Units) of Fuel Burned 0 561420 0 0 609530 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0 1015477 0 0 1015750 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 2.962 0.000 0.000 2.945 0.000

 41 Average Cost of Fuel per Unit Burned 0.000 6.354 0.000 0.000 6.319 0.000

 42 Average Cost of Fuel Burned per Million BTU 0.000 6.257 6.257 0.000 6.221 6.221

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.065 0.065 0.000 0.064 0.064

 44 Average BTU per KWh Net Generation 0.000 0.000 10442.896 0.000 0.000 10320.037

FERC FORM NO. 1 (REV. 12-03) Page 402.4
Saguaro 3 Ocotillo 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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 Comb. Turbine Comb. Turbine

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Over 50% Outdoor Over 50% Outdoor

 3 Year Originally Constructed 2002 1972

 4 Year Last Unit was Installed 2002 1973

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 78.30 53.10

 6 Net Peak Demand on Plant - MW (60 minutes) 83 55

 7 Plant Hours Connected to Load 307 97

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 79 55

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 0 2

 12 Net Generation, Exclusive of Plant Use - KWh 14574000 2357000

 13 Cost of Plant: Land and Land Rights 0 0

 14 Structures and Improvements 560621 194358

 15 Equipment Costs 28973193 10124086

 16 Asset Retirement Costs 0 0

 17 Total Cost 29533814 10318444

 18 Cost per KW of Installed Capacity (line 17/5) Including 377.1879 194.3210

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 1173821 278340

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 187741

 26 Misc Steam (or Nuclear) Power Expenses 0 42218

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 18331 28277

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 251022 1044217

 33 Maintenance of Misc Steam (or Nuclear) Plant 540 8430

 34 Total Production Expenses 1443714 1589223

 35 Expenses per Net KWh 0.0991 0.6743

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas Total Gas Total

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF MCF

 38 Quantity (Units) of Fuel Burned 185190 0 0 46490 0 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1033290 0 0 1019337 0 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 2.954 0.000 0.000 2.791 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 6.338 0.000 0.000 5.987 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 6.134 6.134 0.000 5.874 5.874 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.081 0.081 0.000 0.118 0.118 0.000

 44 Average BTU per KWh Net Generation 0.000 13129.889 0.000 0.000 20105.643 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.5
Sundance West Phoenix 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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 Comb. Turbine Combined Cycle

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Over 50% Outdoor Over 50% Outdoor

 3 Year Originally Constructed 2002 1976

 4 Year Last Unit was Installed 2002 2003

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 605.00 132.00

 6 Net Peak Demand on Plant - MW (60 minutes) 443 170

 7 Plant Hours Connected to Load 1399 1745

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 420 88

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 17 2

 12 Net Generation, Exclusive of Plant Use - KWh 134675000 76032120

 13 Cost of Plant: Land and Land Rights 681252 3885

 14 Structures and Improvements 12686199 2558391

 15 Equipment Costs 264063531 43256969

 16 Asset Retirement Costs 0 0

 17 Total Cost 277430982 45819245

 18 Cost per KW of Installed Capacity (line 17/5) Including 458.5636 347.1155

 19 Production Expenses: Oper, Supv, & Engr 537 83929

 20 Fuel 8212742 6122691

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 1641630 0

 26 Misc Steam (or Nuclear) Power Expenses 1413326 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 484

 30 Maintenance of Structures 253995 6936

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 2436535 1400847

 33 Maintenance of Misc Steam (or Nuclear) Plant 28566 123081

 34 Total Production Expenses 13987331 7737968

 35 Expenses per Net KWh 0.1039 0.1018

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas Total Gas Total

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF MCF

 38 Quantity (Units) of Fuel Burned 1370040 0 0 843760 0 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1011435 0 0 1018997 0 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 2.794 0.000 0.000 3.382 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 5.995 0.000 0.000 7.256 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 5.927 5.927 0.000 7.121 7.121 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.061 0.061 0.000 0.081 0.081 0.000

 44 Average BTU per KWh Net Generation 0.000 10289.259 0.000 0.000 11308.234 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.6
West Phoenix 5 Redhawk 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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 Combined Cycle Combined Cycle

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Over 50% Outdoor Over 50% Outdoor

 3 Year Originally Constructed 2003 2002

 4 Year Last Unit was Installed 2003 2002

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 569.60 573.10

 6 Net Peak Demand on Plant - MW (60 minutes) 536 546

 7 Plant Hours Connected to Load 6155 6856

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 506 492

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 35 19

 12 Net Generation, Exclusive of Plant Use - KWh 1963239000 2244065000

 13 Cost of Plant: Land and Land Rights 18896 1107373

 14 Structures and Improvements 13538246 12102894

 15 Equipment Costs 262222835 251963343

 16 Asset Retirement Costs 0 0

 17 Total Cost 275779977 265173610

 18 Cost per KW of Installed Capacity (line 17/5) Including 484.1643 462.7004

 19 Production Expenses: Oper, Supv, & Engr 2167141 0

 20 Fuel 89388355 101618301

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 2234916 1800377

 26 Misc Steam (or Nuclear) Power Expenses 2910613 2614505

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 5044 212783

 30 Maintenance of Structures 225973 156406

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 5482408 4429149

 33 Maintenance of Misc Steam (or Nuclear) Plant 725473 1495314

 34 Total Production Expenses 103139923 112326835

 35 Expenses per Net KWh 0.0525 0.0501

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas Total Gas Total

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF MCF

 38 Quantity (Units) of Fuel Burned 14790940 0 0 16153590 0 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1018191 0 0 1017351 0 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.945 0.000 0.000 2.932 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 8.463 0.000 0.000 6.291 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 8.311 8.311 0.000 6.184 6.184 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.064 0.064 0.000 0.045 0.045 0.000

 44 Average BTU per KWh Net Generation 0.000 7668.909 0.000 0.000 7325.597 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.7
Palo Verde 3

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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 Nuclear

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Under 50% Outdoor

 3 Year Originally Constructed 1988

 4 Year Last Unit was Installed 1988

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 408.33 0.00

 6 Net Peak Demand on Plant - MW (60 minutes) 398 0

 7 Plant Hours Connected to Load 7798 0

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 382 0

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 211 0

 12 Net Generation, Exclusive of Plant Use - KWh 2937257125 0

 13 Cost of Plant: Land and Land Rights 1642236 0

 14 Structures and Improvements 290284551 0

 15 Equipment Costs 732644411 0

 16 Asset Retirement Costs -8312963 0

 17 Total Cost 1016258235 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 2488.8160 0

 19 Production Expenses: Oper, Supv, & Engr 8352554 0

 20 Fuel 26210259 0

 21 Coolants and Water (Nuclear Plants Only) 3654858 0

 22 Steam Expenses 3890274 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 3111482 0

 26 Misc Steam (or Nuclear) Power Expenses 11168026 0

 27 Rents 15222412 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 3733107 0

 30 Maintenance of Structures 716136 0

 31 Maintenance of Boiler (or reactor) Plant 4640017 0

 32 Maintenance of Electric Plant 5722578 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 1574827 0

 34 Total Production Expenses 87996530 0

 35 Expenses per Net KWh 0.0300 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Nuclear

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Kg Uranium

 38 Quantity (Units) of Fuel Burned 456 0 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 66707 0 0 00 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 2937.399 0.000 0.000 0.000 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 57453.439 0.000 0.000 0.000 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 0.861 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.009 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 10359.961 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.8
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Arizona Public Service Company End of

X

04/10/2013 2012/Q4

Line

 No.

Item

(a) (b) (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

 2 Type of Constr (Conventional, Outdoor, Boiler, etc)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 6 Net Peak Demand on Plant - MW (60 minutes) 0 0

 7 Plant Hours Connected to Load 0 0

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 0 0

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 0 0

 12 Net Generation, Exclusive of Plant Use - KWh 0 0

 13 Cost of Plant: Land and Land Rights 0 0

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.9
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

Cholla 2 Cholla 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

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

1978 1980 3

1981 1981 4

288.90 0.00 312.30 5

272 0 275 6

8468 0 7542 7

0 0 0 8

260 0 271 9

260 0 271 10

60 0 56 11

1812482722 0 1638310135 12

1964889 0 2488397 13

25793191 0 34728979 14

291280738 0 366822956 15

0 0 0 16

319038818 0 404040332 17

1104.3227 0 1293.7571 18

1383012 0 1340357 19

40078919 0 34686565 20

0 0 0 21

4572444 0 4074320 22

0 0 0 23

0 0 0 24

458600 0 429753 25

1430071 0 1454167 26

0 0 0 27

0 0 0 28

1571931 0 1533628 29

376989 0 217035 30

4007070 0 5812222 31

396614 0 3695382 32

1110577 0 3004376 33

55386227 0 56247805 34

0.0306 0.0000 0.0343 35

Coal Oil Gas Total Coal Oil Gas 36

Tons Bbls MCF Tons Bbls MCF 37

1075015 1343 0 0 0 0 926089 1542 0 38

9220 130770 0 0 0 0 9215 159034 0 39

36.389 112.675 0.000 0.000 0.000 0.000 36.555 153.294 0.000 40

37.133 141.820 0.000 0.000 0.000 0.000 37.192 186.236 0.000 41

2.014 25.822 0.000 2.021 0.000 0.000 2.018 27.882 0.000 42

0.022 0.283 0.000 0.022 0.000 0.000 0.021 0.291 0.000 43

0.000 0.000 0.000 10941.575 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

Four Corners 2 Four Corners 3 Four Corners 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

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

1963 1964 1969 3

1970 1970 1970 4

190.10 253.40 122.72 5

175 225 119 6

6907 7193 7566 7

0 0 0 8

170 220 116 9

170 220 116 10

61 50 29 11

1071680867 1415151700 696659764 12

15265 17936 8057 13

17719039 18719696 8443688 14

123532875 144754360 71483054 15

20640912 26745008 1274468 16

161908091 190237000 81209267 17

851.6996 750.7380 661.7444 18

287744 715113 197266 19

23569867 31620793 13966000 20

0 0 0 21

2790384 2795760 1571846 22

0 0 0 23

0 0 0 24

459040 459161 106330 25

2073094 2009602 570778 26

127366 127366 75695 27

0 0 0 28

640541 761635 172854 29

202557 223836 68676 30

4532374 5020985 1620021 31

1175837 876630 324717 32

1609083 1733293 572786 33

37467887 46344174 19246969 34

0.0350 0.0327 0.0276 35

Coal Gas Total Coal Gas Total Coal Gas Total 36

Tons MCF Tons MCF Tons MCF 37

678280 68350 0 869040 115760 0 398200 23160 0 38

8748 1009305 0 8752 1011757 0 9202 1008895 0 39

32.913 5.657 0.000 34.467 6.314 0.000 33.607 5.652 0.000 40

34.056 6.882 0.000 35.363 7.681 0.000 34.673 6.876 0.000 41

1.947 6.818 1.975 2.020 7.592 2.063 1.884 6.815 1.900 42

0.022 0.076 0.022 0.022 0.082 0.022 0.020 0.072 0.020 43

0.000 0.000 11137.570 0.000 0.000 10831.602 0.000 0.000 10553.374 44

FERC FORM NO. 1 (REV. 12-03) Page 403.1
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

Ocotillo 2 Saguaro 1 Saguaro 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

1960 1954 1955 3

1960 1955 1955 4

113.60 125.00 125.00 5

108 0 0 6

608 0 0 7

0 0 0 8

110 110 100 9

110 110 100 10

10 1 0 11

29854000 0 0 12

136915 7886 44461 13

2388266 1816308 2015847 14

27135560 25932243 27179540 15

0 0 0 16

29660741 27756437 29239848 17

261.0981 222.0515 233.9188 18

0 26524 26524 19

1211197 162 0 20

0 0 0 21

98111 0 0 22

0 0 0 23

0 0 0 24

786319 1016 1016 25

163846 201894 0 26

0 0 0 27

0 0 0 28

0 1225 1225 29

0 10295 10295 30

150925 35623 35623 31

441152 12394 12788 32

146228 111065 70875 33

2997778 400198 158346 34

0.1004 0.0000 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) Page 403.2
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

Yucca 2 Yucca 3 Yucca 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

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

1971 1973 1974 3

2008 2008 2008 4

23.60 72.40 72.40 5

21 52 50 6

272 875 40 7

0 0 0 8

19 55 54 9

0 0 0 10

0 1 1 11

3480000 27260000 612000 12

0 0 0 13

85001 254014 172109 14

2484030 11072328 7627523 15

0 0 0 16

2569031 11326342 7799632 17

108.8572 156.4412 107.7297 18

0 29887 0 19

370260 3299047 0 20

0 0 0 21

0 0 0 22

0 0 0 23

0 0 0 24

1241 17829 954 25

13575 22356 0 26

0 0 0 27

0 0 0 28

0 0 0 29

353 2762 62 30

0 0 0 31

23459 167235 23865 32

949 12319 0 33

409837 3551435 24881 34

0.1178 0.1303 0.0407 35

Oil Gas Total Oil Gas Total Oil Gas Total 36

Bbls MCF Bbls MCF Bbls MCF 37

0 56510 0 443 419850 0 2217 0 0 38

0 1018032 0 138260 1016403 0 138221 0 0 39

0.000 3.054 0.000 70.163 3.220 0.000 70.163 0.000 0.000 40

0.000 6.552 0.000 149.939 6.908 0.000 149.939 0.000 0.000 41

0.000 6.436 6.436 25.821 6.796 6.910 25.828 0.000 25.828 42

0.000 0.106 0.106 0.407 0.107 0.109 0.543 0.000 0.543 43

0.000 0.000 16531.322 0.000 0.000 15748.696 0.000 0.000 21029.867 44

FERC FORM NO. 1 (REV. 12-03) Page 403.3
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

Douglas Saguaro 1 Saguaro 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

1972 1972 1973 3

1972 2002 2002 4

26.10 53.10 53.10 5

17 54 50 6

11 50 51 7

0 0 0 8

16 55 55 9

0 0 0 10

0 0 0 11

131000 651000 1382000 12

9557 0 0 13

103679 713925 1039357 14

2177814 8619612 9669073 15

0 0 0 16

2291050 9333537 10708430 17

87.7797 175.7728 201.6653 18

0 0 0 19

54233 33043 247619 20

0 0 0 21

0 0 0 22

0 0 0 23

0 0 0 24

62 0 0 25

858 67056 67056 26

0 0 0 27

0 0 0 28

0 0 0 29

0 819 1738 30

0 0 0 31

28246 50378 1324015 32

16095 139429 183 33

99494 290725 1640611 34

0.7595 0.4466 1.1871 35

Oil Total Gas Total Gas Total 36

Bbls MCF MCF 37

704 0 0 18980 0 0 26680 0 0 38

138602 0 0 1028451 0 0 1034445 0 0 39

56.805 0.000 0.000 0.811 0.000 0.000 4.326 0.000 0.000 40

77.036 0.000 0.000 1.741 0.000 0.000 9.281 0.000 0.000 41

13.234 13.234 0.000 1.693 1.693 0.000 8.972 8.972 0.000 42

0.414 0.414 0.000 0.051 0.051 0.000 0.179 0.179 0.000 43

0.000 31283.847 0.000 0.000 29984.639 0.000 0.000 19970.333 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403.4
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

Ocotillo 2 West Phoenix 1 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)

Comb. Turbine Comb. Turbine Comb. Turbine 1

Over 50% Outdoor Over 50% Outdoor Over 50% Outdoor 2

1973 1972 1973 3

1973 1973 1973 4

53.10 53.10 53.10 5

53 50 22 6

65 49 2 7

0 0 0 8

55 55 55 9

0 0 0 10

2 1 1 11

1756000 1165000 46000 12

0 6294 0 13

547191 786747 127593 14

15919691 18422932 7661752 15

0 0 0 16

16466882 19215973 7789345 17

310.1108 361.8827 146.6920 18

0 123142 4862 19

230119 162741 4796 20

0 0 0 21

0 0 0 22

0 0 0 23

0 0 0 24

189197 78168 3086 25

31185 1637 65 26

0 0 0 27

0 0 0 28

0 0 0 29

20887 0 74110 30

0 0 0 31

2189832 2499856 1123205 32

0 21472 0 33

2661220 2887016 1210124 34

1.5155 2.4781 26.3070 35

Gas Total Gas Total Gas Total 36

MCF MCF MCF 37

35920 0 0 68600 0 0 1090 0 0 38

1024749 0 0 1022507 0 0 1009174 0 0 39

2.986 0.000 0.000 1.106 0.000 0.000 2.051 0.000 0.000 40

6.406 0.000 0.000 2.372 0.000 0.000 4.400 0.000 0.000 41

6.252 6.252 0.000 2.320 2.320 0.000 4.360 4.360 0.000 42

0.131 0.131 0.000 0.140 0.140 0.000 0.104 0.104 0.000 43

0.000 20961.845 0.000 0.000 60209.442 0.000 0.000 23913.043 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403.5
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

West Phoenix 2 West Phoenix 3 West Phoenix 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

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

1976 1976 2001 3

2003 2003 2003 4

132.00 132.00 135.60 5

0 79 105 6

1522 1192 1220 7

0 0 0 8

88 88 117 9

0 0 0 10

1 5 8 11

65046570 68734020 96940000 12

3866 4590 32909 13

2550695 4370537 5405861 14

42322786 50067655 77730957 15

0 0 0 16

44877347 54442782 83169727 17

339.9799 412.4453 613.3461 18

71802 75873 512398 19

5306431 4906711 5374887 20

0 0 0 21

0 0 0 22

0 0 0 23

0 0 0 24

0 0 359811 25

0 0 0 26

0 0 0 27

0 0 0 28

0 273 234 29

5934 6271 8844 30

0 0 0 31

302930 625520 694511 32

366001 125466 373091 33

6053098 5740114 7323776 34

0.0931 0.0835 0.0755 35

Gas Total Gas Total Gas Total 36

MCF MCF MCF 37

721150 0 0 688840 0 0 954080 0 0 38

1018956 0 0 1019600 0 0 1019920 0 0 39

3.430 0.000 0.000 3.320 0.000 0.000 2.626 0.000 0.000 40

7.358 0.000 0.000 7.123 0.000 0.000 5.634 0.000 0.000 41

7.221 7.221 0.000 6.986 6.986 0.000 5.524 5.524 0.000 42

0.082 0.082 0.000 0.071 0.071 0.000 0.055 0.055 0.000 43

0.000 11296.829 0.000 0.000 10218.244 0.000 0.000 10038.013 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403.6
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

Redhawk 2 Palo Verde 1 Palo Verde 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 Nuclear Nuclear 1

Over 50% Outdoor Under 50% Outdoor Under 50% Outdoor 2

2002 1986 1986 3

2002 1988 1988 4

567.20 408.33 408.33 5

539 390 395 6

7551 8784 7957 7

0 0 0 8

492 382 382 9

0 0 0 10

27 246 246 11

2429675000 3341312830 3014199744 12

1077407 1772137 1076968 13

10823210 289468786 178067451 14

246097398 778466197 497849985 15

0 -13440695 -7857443 16

257998015 1056266425 669136961 17

454.8625 2586.7960 1638.7161 18

0 8414816 8528438 19

112763622 30538102 30275951 20

0 3684242 3653761 21

0 2422510 3502178 22

0 0 0 23

0 0 0 24

1786943 2977479 2817154 25

2830754 10516159 11232745 26

0 15222412 15222412 27

0 0 0 28

212783 1455311 2420848 29

160530 668910 648661 30

0 1990217 5124595 31

1256248 2913620 6380302 32

1480912 1167310 1547858 33

120491792 81971088 91354903 34

0.0496 0.0245 0.0303 35

Gas Total Nuclear Nuclear 36

MCF Kg Uranium Kg Uranium 37

17661470 0 0 517 0 0 465 0 0 38

1017678 0 0 66706 0 0 66706 0 0 39

2.976 0.000 0.000 0.000 0.000 0.000 2958.417 0.000 0.000 40

6.385 0.000 0.000 59113.631 0.000 0.000 65137.588 0.000 0.000 41

6.274 6.274 0.000 0.886 0.000 0.000 0.976 0.000 0.000 42

0.046 0.046 0.000 0.009 0.000 0.000 0.010 0.000 0.000 43

0.000 7394.382 0.000 10314.248 0.000 0.000 10286.661 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403.7
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

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) Page 403.8
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load

Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.

547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

report period and other physical and operating characteristics of plant.

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) Page 403.9
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) X An 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
 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)

Arizona Public Service Company X

04/10/2013 2012/Q4

Line

 No.

Item FERC Licensed Project No.

(a) (b) (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.

 1 Kind of Plant (Run-of-River or Storage)

 2 Plant Construction type (Conventional or Outdoor)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total installed cap (Gen name plate Rating in MW) 0.00 0.00

 6 Net Peak Demand on Plant-Megawatts (60 minutes) 0 0

 7 Plant Hours Connect to Load 0 0

 8 Net Plant Capability (in megawatts)

 9 (a) Under Most Favorable Oper Conditions 0 0

 10 (b) Under the Most Adverse Oper Conditions 0 0

 11 Average Number of Employees 0 0

 12 Net Generation, Exclusive of Plant Use - Kwh 0 0

 13 Cost of Plant

 14 Land and Land Rights 0 0

 15 Structures and Improvements 0 0

 16 Reservoirs, Dams, and Waterways 0 0

 17 Equipment Costs 0 0

 18 Roads, Railroads, and Bridges 0 0

 19 Asset Retirement Costs 0 0

 20 TOTAL cost (Total of 14 thru 19) 0 0

 21 Cost per KW of Installed Capacity (line 20 / 5) 0.0000 0.0000

 22 Production Expenses

 23 Operation Supervision and Engineering 0 0

 24 Water for Power 0 0

 25 Hydraulic Expenses 0 0

 26 Electric Expenses 0 0

 27 Misc Hydraulic Power Generation Expenses 0 0

 28 Rents 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Reservoirs, Dams, and Waterways 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Hydraulic Plant 0 0

 34 Total Production Expenses (total 23 thru 33) 0 0

 35 Expenses per net KWh 0.0000 0.0000

FERC FORM NO. 1 (REV. 12-03) Page 406
 0 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.

(d) (e) (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) Page 407
FERC 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)

 2 Year Originally Constructed

 3 Year Last Unit was Installed

 4 Total installed cap (Gen name plate Rating in MW)

 5 Net Peak Demaind on Plant-Megawatts (60 minutes)

 6 Plant Hours Connect to Load While Generating

 7 Net Plant Capability (in megawatts)

 8 Average Number of Employees

 9 Generation, Exclusive of Plant Use - Kwh

 10 Energy Used for Pumping

 11 Net Output for Load (line 9 - line 10) - Kwh

 12 Cost of Plant

 13 Land and Land Rights

 14 Structures and Improvements

 15 Reservoirs, Dams, and Waterways

 16 Water Wheels, Turbines, and Generators

 17 Accessory Electric Equipment

 18 Miscellaneous Powerplant Equipment

 19 Roads, Railroads, and Bridges

 20 Asset Retirement Costs

 21 Total cost (total 13 thru 20)

 22 Cost per KW of installed cap (line 21 / 4)

 23 Production Expenses

 24 Operation Supervision and Engineering

 25 Water for Power

 26 Pumped Storage Expenses

 27 Electric Expenses

 28 Misc Pumped Storage Power generation Expenses

 29 Rents

 30 Maintenance Supervision and Engineering

 31 Maintenance of Structures

 32 Maintenance of Reservoirs, Dams, and Waterways

 33 Maintenance of Electric Plant

 34 Maintenance of Misc Pumped Storage Plant

 35 Production Exp Before Pumping Exp (24 thru 34)

 36 Pumping Expenses

 37 Total Production Exp (total 35 and 36)

 38 Expenses per KWh (line 37 / 9)

FERC FORM NO. 1 (REV. 12-03) Page 408
FERC 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:

(c) (e)

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) Page 409
Name 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

(a) (b) (c)

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.

 1 Solar Plants

 2 Flagstaff 1997 1.31 32 9,896,231

 3 Star 1998 0.19 564 1,540,761

 4 Tempe 1998 12,817

 5 Glendale Airport 1999 0.07 124 114,593

 6 Gilbert 2001 0.12 241 77,374

 7 Scottsdale Covered Parking 1999 0.29 630 557,305

 8 Municipal Rooftops 1999 64,174

 9 Yuma 2002 0.17 379 324,235

 10 Prescott Earu 2002 443 57,377

 11 Prescott 2001 2.90 4,959 1,927,250

 12 Red Rock 2005 1.00 846,413

 13 Phoenix 1998 0.08 100 29,053

 14 Off-Grid Facilities 1996

 15 Hyder Phase 1 2011 30.00 39,252 74,989,914

 16 Cotton Center 2011 17.00 46,172 80,741,132

 17 Paloma 2011 17.00 42,843 66,150,605

 18 US Airways Center 2011 0.18 296 1,350,091

 19 Chase Field 2011 0.06 98 1,284,717

 20 Chino Valley 2012 19.00 6,292 90,709,604

 21 APS Solar for Schools 2012 6.38 2,858 29,931,901

 22 Total Solar Operation/Maintenance 95.75 145,283 360,605,547

 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 410
Name 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. (g) (h) (i) (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 1,224,819 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 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) X An 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
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 LINE STATISTICS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

(a) (b) (c) (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.

 1 PALO VERDE KYRENE 500.00 500.00 (3) STEEL (A) 74.80 1

 2 PALO VERDE WESTWING #2 500.00 500.00 (3) STEEL (A) 45.00 1

 3 FOUR CORNERS COLORADO RIVER 500.00 500.00 (3) STEEL 366.00 1

 4 NAVAJO PLANT WESTWING 500.00 500.00 (3) STEEL (A) 256.00 1

 5 NAVAJO PLANT MOENKOPI 500.00 500.00 (3) STEEL (A) 76.00 1

 6 MOENKOPI WESTWING 500.00 500.00 (3) STEEL (A) 180.00 1

 7 CHOLLA SAGUARO 500.00 500.00 (3) STEEL 206.00 1

 8 PALO VERDE WESTWING 500.00 500.00 (3) STEEL (A) 47.00 1

 9 PALO VERDE NORTH GILA 500.00 500.00 (3) STEEL (A) 120.00 1

 10 WESTWING MEAD 500.00 500.00 (3) STEEL (A) 242.70 1

 11 MEAD MARKET PLACE 500.00 500.00 (3) STEEL (A) 13.30 1

 12 KYRENE/PALO VERDE JOJOBA SUB 500.00 500.00 (3) STEEL 0.25 1

 13 GILA RIVER JOJOBA SWITCHYARD 500.00 500.00 (3) STEEL 18.50 2

 14 PALO VERDE RUDD 500.00 500.00 (3) STEEL (A) 35.68 1

 15 PALO VERDE HASSAYAMPA 500.00 500.00 (3) STEEL (A) 3.10 1

 16 MORGAN PINNACLE PEAK 500.00 500.00 (3) STEEL (A) 27.00 6.00 1

 17 WESTWING DUGAS LOOP 500.00 500.00 (3) STEEL 1

 18 FOUR CORNERS PINNACLE PEAK 345.00 345.00 (3) STEEL (C) 566.00 12.00 2

 19 YAVAPAI TAP IN & OUT 230.00 230.00 (1) STEEL 1.30 2

 20 WESTWING EL SOL 230.00 345.00 (3) STEEL (D) 12.77 1

 21 CHOLLA PLANT FLAGSTAFF 230.00 230.00 (2) WOOD 88.14 1

 22 LIBERTY GILA BEND 230.00 230.00 (3) STEEL (D) 6.00 1

 23 LIBERTY GILA BEND 230.00 230.00 (1) WOOD 12.00 1

 24 LIBERTY GILA BEND 230.00 230.00 (2) WOOD 28.00 1

 25 COCONINO VERDE 230.00 230.00 (2) WOOD 32.68 1

 26 VERDE WILLOW LAKE 230.00 230.00 (2) WOOD 34.30 1

 27 ROUND VALLEY SELIGMAN 230.00 230.00 (2) WOOD 36.19 1

 28 PINNACLE PEAK OCOTILLO 230.00 230.00 (3) STEEL 51.20 2

 29 EL SOL AGUA FRIA 230.00 230.00 (3) STEEL 5.65 1

 30 AGUA FRIA GRAND TERMINAL 230.00 230.00 (1) STEEL 10.02 1

 31 OCOTILLO PLANT LINCOLN STREET 230.00 230.00 (3) STEEL 10.30 10.30 2

 32 OCOTILLO PLANT LINCOLN STREET 230.00 230.00 (4) U.G. 1.00

 33 OCOTILLO PLANT SRP TAP KYRENE SUB 230.00 230.00 (1) STEEL 6.50 2

 34 OCOTILLO PLANT 68TH ST & SALT RIVER 230.00 230.00 (3) STEEL 1.60 1

 35 LINCOLN STREET WEST PHOENIX PLANT 230.00 230.00 (3) STEEL 5.50 1

FERC FORM NO. 1 (ED. 12-87) Page 422

36 TOTAL 5,031.80 881.15 80
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 LINE STATISTICS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

(a) (b) (c) (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.

 1 SANTA ROSA SAGUARO PLANT 230.00 230.00 (2) WOOD 61.50 1

 2 PINNACLE PEAK-OCOTILLO CACTUS SUB TAP 230.00 230.00 (1) STEEL 3.20 2

 3 PINNACLE PEAK/LONE REACH SUB TAP 230.00 230.00 (1) STEEL 0.12 1

 4 PINNACLE PEAK/LONE REACH SUB 230.00 230.00 (4) U.G. 0.63 1

 5 GILA BEND/LIBERTY PANDA SWITCHYARD 230.00 230.00 (1) STEEL 0.25 1

 6 SRP-PINNACLE PEAK DEER VALLEY TAP 230.00 230.00 (1) STEEL 3.30 2

 7 LINCOLN STREET COUNTRY CLUB 230.00 230.00 (4) U.G. 3.50 1

 8 SUNNYSLOPE COUNTRY CLUB 230.00 230.00 (4) U.G. 7.50 1

 9 GRAND TERMINAL COUNTRY CLUB 230.00 230.00 (4) U.G. 2.50 1

 10 SANTA ROSA CASA GRANDE 230.00 230.00 (2) WOOD 14.95 1

 11 CASA GRANDE SAGUARO 230.00 230.00 (1) WOOD 6.74 1

 12 CASA GRANDE SAGUARO 230.00 230.00 (2) WOOD 38.97 1

 13 WESTWING-EL SOL SURPRISE 230.00 230.00 (1) STEEL 11.25 1

 14 DEER VALLEY ALEXANDER 230.00 230.00 (1) STEEL 7.60 1

 15 PINNACLE PEAK SUNNYSLOPE 230.00 230.00 (1) STEEL 16.70 1

 16 OCOTILLO SANTA ROSA 230.00 230.00 (2) WOOD 36.30 1

 17 ROUND VALLEY/SELIGMAN FORT ROCK 230.00 230.00 (2) WOOD 1.67 1

 18 WHITE TANKS WEST PHOENIX 230.00 230.00 (1) STEEL 12.00 2

 19 EL SOL WHITE TANKS 230.00 230.00 (3) STEEL 9.00 1

 20 PINNACLE PEAK LONE PEAK 230.00 230.00 (3) STEEL 11.90 1

 21 MEADOWBROOK SUNNYSLOPE 230.00 230.00 (4) U.G. 0.16 1

 22 MEADOWBROOK COUNTRY CLUB 230.00 230.00 (4) U.G. 0.17 1

 23 RUDD LIBERTY 230.00 230.00 (1) STEEL 20.48 1

 24 PALO VERDE NORTH GILA TAP 230.00 230.00 (1) STEEL 3.30 2

 25 PALO VERDE KYRENE TAP 230.00 230.00 (1) STEEL 3.30 2

 26 MORGAN RACEWAY TAP 230.00 230.00 (3) STEEL 0.75 1

 27 TUBA CITY TAP POWELL SUB 69.00 230.00 (2) WOOD 60.00 1

 28 SAGUARO PLANT SAN MANUEL 115.00 230.00 (2) WOOD 41.50 1

 29 ORACLE SAN MANUEL 115.00 115.00 (2) WOOD 21.06 1

 30 ADAMS MURAL 115.00 115.00 (2) WOOD 47.15 1

 31 SANTA ROSA ASARCO 115.00 115.00 (2) WOOD 11.00 1

 32 ASARCO VISTA 115.00 115.00 (2) WOOD 3.81 1

 33 ASARCO VISTA 115.00 115.00 (1) WOOD 3.02 1

 34 WILLOW LAKE BAGDAD 115.00 115.00 (2) WOOD 49.00 1

 35 UNDERGROUND 69.00 69.00 19.63

FERC FORM NO. 1 (ED. 12-87) Page 422.1

36 TOTAL 5,031.80 881.15 80
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 LINE STATISTICS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No.

(a) (b) (c) (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.

 1 OVERHEAD 69.00 69.00 2,698.04 30.58 1

 2 RELATED TRANSMISSION 1.64

 3 EHV 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 80
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 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

Land Construction and Maintenance Rents Total

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.

1780 ACSR 19,901,128 19,901,128 1

1780 ACSR 5,971,160 5,971,160 2

2156 ACSR 2,321,510 39,917,115 42,238,625 3

2156 ACSR 83,716 8,665,938 8,749,654 4

2156 ACSR 1,208,159 1,208,159 5

2156 ACSR 305,120 5,316,391 5,621,511 6

2156 ACSR 948,062 60,305,879 61,253,941 7

1780 ACSR 429,281 5,151,452 5,580,733 8

2156 ACSR 147,179 4,540,896 4,688,075 9

1590 KCM 1,175,680 17,090,839 18,266,519 10

1590 KCM 50,610 626,769 677,379 11

954 ACSR 12

1780 ACSR 13

1780 ACSR 12,237,938 29,540,970 41,778,908 14

1780 ACSR 194,922 776,503 971,425 15

1780 ACSR 15,619,054 33,366,026 48,985,080 16

2156 ACSR 3,178,473 3,178,473 17

795 ACSR 1,220,788 30,459,920 31,680,708 18

954 ACSR 947,577 947,577 19

795 ACSR 424,643 3,423,589 3,848,232 20

795 ACSR 143,124 3,146,892 3,290,016 21

1272 ACSR 132,588 1,550,628 1,683,216 22

1272 ACSR 148,578 1,358,866 1,507,444 23

1272 ACSR 370,615 3,309,278 3,679,893 24

795 ACSR 35,944 2,144,411 2,180,355 25

795 ACSR 53,050 3,298,468 3,351,518 26

795 ACSR 8,969 2,097,188 2,106,157 27

795 AA 12,276,358 7,704,155 19,980,513 28

1431 AA 220,297 536,958 757,255 29

1361 ACAR 112,180 3,218,246 3,330,426 30

1431 AA 820,160 6,759,382 7,579,542 31

2000 KC 1,826,611 1,826,611 32

954 ACSR 1,931,778 3,881,596 5,813,374 33

954A/1113A 17,978 17,978 34

1113 AA 37,261 3,275,987 3,313,248 35

FERC FORM NO. 1 (ED. 12-87) Page 423

 121,583,860 947,997,886 1,069,581,746 19,430,487 14,467,225 6,614,513 40,512,225 36
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 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

Land Construction and Maintenance Rents Total

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.

954A/1113A 1,565,968 3,080,996 4,646,964 1

954 AA 286,973 1,324,874 1,611,847 2

954 ACSR 1,743,515 203,127 1,946,642 3

1750 CU 142,671 667,687 810,358 4

1272 ACSR 5

954 AA 78,389 2,785,385 2,863,774 6

1750 CU 1,021,582 6,141,784 7,163,366 7

1750 CU 85,094 5,672,649 5,757,743 8

1750 CU 42,236 1,663,288 1,705,524 9

1272 ACSR 541,442 3,775,970 4,317,412 10

1272 ACSR 78,429 823,686 902,115 11

1272 ACSR 519,018 6,665,096 7,184,114 12

954 ACSR 381,847 1,203,882 1,585,729 13

954 AA 933,461 4,485,834 5,419,295 14

1431A/1361 ACSR 127,241 4,389,119 4,516,360 15

795R/1113A 352,384 6,736,913 7,089,297 16

795 AA 39,196 39,196 17

954 SSAC 7,389,772 16,026,636 23,416,408 18

954 ACSR 1,026,511 6,251,970 7,278,481 19

954 ACSR 3,687,735 7,736,796 11,424,531 20

1750 ACSR 618,139 618,139 21

1750 ACSR 857,317 857,317 22

1780 ACSR 8,241,786 13,488,478 21,730,264 23

954 AA 374,911 374,911 24

954 AA 383,526 383,526 25

2156 ACSS 6,693,880 14,299,725 20,993,605 26

954 ACSR 2,380,164 2,380,164 27

954 ACSR 46,640 1,599,074 1,645,714 28

556 ACSR 74,058 2,462,446 2,536,504 29

556 ACSR 435,137 1,994,131 2,429,268 30

795 ACSR 93,110 433,334 526,444 31

795 ACSR 18,029 392,494 410,523 32

795 ACSR 12,019 229,551 241,570 33

795 ACSR 220,846 2,952,806 3,173,652 34

 35,954,746 35,954,746 35

FERC FORM NO. 1 (ED. 12-87) Page 423.1

 121,583,860 947,997,886 1,069,581,746 19,430,487 14,467,225 6,614,513 40,512,225 36
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 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

Land Construction and Maintenance Rents Total

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.

 34,273,061 469,742,518 504,015,579 1

 21,621 5,328,484 5,350,105 2

 315,726 315,726 3

 19,430,487 14,467,225 6,614,513 40,512,225 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

 121,583,860 947,997,886 1,069,581,746 19,430,487 14,467,225 6,614,513 40,512,225 36
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) X An 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) X An 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

(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.

(a) (b) (c) (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

 1 BISCUIT FLATS PIONEER/GATEWAY 0.52 STEEL 13.00 2 2

 2 WILLOW LAKE/LONESOME WELLFIELD TAP 0.35 STEEL 6.00 2 2

 3 YOUNGS CANYON SANDVIG 9.35 STEEL 12.00 1 1

 4 INTERSTATE 17 RELOCATE CORDES JUNCTION -0.44 STEEL 13.00 1 1

 5 WALDRIP MARINE AIR/32ND STREET 0.72 STEEL 14.00 2 2

 6 OLD HOME MANOR GRANITE CREEK 0.03 STEEL 2.00 2 2

 7 POPLAR WASH/WILHOIT KIRKLAND JUNCTION 0.05 STEEL 1.00 1 1

 8 WALDRIP MARINE AIR/SOUTH O'NEIL 2.18 STEEL 12.00 1 1

 9 PADRE/SUNSHINE TWIN ARROWS 1.29 STEEL 12.00 2 2

 10 BAJA WALDRIP PHASE 3 1.55 STEEL 17.00 1 1

 11 BAJA WALDRIP PHASE 4 2.14 STEEL 16.00 1 1

 12 BAJA WALDRIP PHASE 5 & TAP 1.70 STEEL 16.00 1 1

 13 BAJA WALDRIP PHASE 5 & TAP 1.04 STEEL 17.00 2 2

 14 FESTIVAL RANCH MCMICKEN/FARMER 0.72 STEEL 12.00 1 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

 41

 42

 43

 21.20 163.00 20 20

FERC FORM NO. 1 (REV. 12-03) Page 424

44 TOTAL
Total

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.

(h) (j) (k) (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

795 ACSS 45/7 69 366,595 151,128 517,723 1

795 ACSS 45/7 69 465,417 199,464 664,881 2

795 ACSS 45/7 69 2,592,025 1,110,868 3,702,893 3

795 AL-ACSS 37 - 45/7 69 18,969 8,129 27,098 4

795 ACSS 45/7 69 746,111 319,762 1,065,873 5

795 AL 37 69 387,450 166,050 553,500 6

795 AL 37 69 189,637 81,273 270,910 7

795 ACSS 45/7 69 390,319 167,280 557,599 8

795 ACSS 45/7 69 15,123 6,481 21,604 9

795 ACSS 45/7 69 676,109 115,772 791,881 10

795 ACSS 45/7 69 571,075 244,747 815,822 11

795 ACSS 45/7 69 1,310,275 561,546 1,871,821 12

795 ACSS 45/7 69 13

3/0 ACSR 6/1 69 476,453 204,194 680,647 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

 8,205,558 3,336,694

FERC FORM NO. 1 (REV. 12-03) Page 425

 11,542,252 44
Name 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

(a) (b) (c)

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).

 1 ACOMA-SCOTTSDALE D 69.00 12.00

 2 ADAMS-BENSON T 115.00

 3 ADOBE-PHOENIX D 69.00 12.00

 4 AGUA FRIA SWYD-GLENDALE T 230.00 69.00

 5 AGUILA-AGUILA D 69.00 12.00

 6 AJO-AJO D 69.00 21.00

 7 ALEXANDER-PHOENIX T 69.00

 8 ALTADENA-SCOTTSDALE D 69.00 12.00

 9 ANTELOPE-PRESCOTT D 69.00 12.00

 10 ARABY-YUMA D 69.00 12.00

 11 ARICA-ELOY D 69.00 12.00

 12 ARLINGTON-MARICOPA COUNTY D 69.00 12.00

 13 ARROWHEAD-GLENDALE D 69.00 12.00

 14 ARROYO-PHOENIX D 69.00 12.00

 15 ASARCO PIT-CASA GRANDE D 69.00 12.00

 16 ASHFORK-ASHFORK D 69.00 12.00

 17 AZTEC-AZTEC D 69.00 12.00

 18 BACON-N.W. OF SNOWFLAKE D 69.00 21.00

 19 BAGDAD-BAGDAD T 115.00 12.00

 20 BAGDAD-115KV CAP.-BAGDAD T 115.00

 21 BAJA-SAN LUIS D 69.00 12.00

 22 BALD MOUNTAIN-PRESCOTT VALLEY D 69.00 12.00

 23 BASELINE-BUCKEYE D 69.00 12.00

 24 BEARDSLEY-SURPRISE D 69.00 12.00

 25 BELL-PEORIA D 69.00 12.00

 26 BISCUIT FLATS-PHOENIX D 69.00

 27 BLACK MESA #2-GRAY MOUNTAIN D 69.00

 28 BLACK BEAK (BOUSE APA)-PARKER T 161.00 69.00

 29 BLACK BEAK (BOUSE APA)-PARKER D 69.00 12.00

 30 BLUE RIDGE-BLUE RIDGE D 69.00 21.60

 31 BLUE WATER-N. OF PARKER D 34.50 12.00

 32 BONNYBROOK-FLORENCE D 115.00 12.00

 33 BOOTHILL-E. OF TOMBSTONE D 115.00 21.00

 34 BOULEVARD-SCOTTSDALE D 69.00 12.00

 35 BUCKEYE-BUCKEYE T 230.00 69.00

 36 BUCKEYE-BUCKEYE D 69.00 12.00

 37 BUFFALO-PHOENIX D 69.00 12.00

 38 BUNYAN-NW. OF GILA BEND D 69.00 12.00

 39 BUTTE-TEMPE D 69.00 12.00

 40 CACTUS-SCOTTSDALE T 230.00 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426
Name 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

(a) (b) (c)

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).

 1 CACTUS-SCOTTSDALE D 69.00 12.00

 2 CALDERWOOD-PEORIA D 69.00 12.00

 3 CAMELBACK-SCOTTSDALE D 69.00 12.00

 4 CAMERON-CAMERON D 69.00 12.00

 5 CANAL-PHOENIX D 69.00 12.00

 6 CAPITAL BUTTE-SEDONA D 69.00 12.00

 7 CASA GRANDE-CASA GRANDE T 230.00 69.00 12.00

 8 CASA GRANDE-CASA GRANDE D 230.00 12.00

 9 CASA GRANDE-CASA GRANDE D 69.00 12.00

 10 CAVE CREEK-CAVE CREEK D 69.00 12.00

 11 CEDAR MOUNTAIN-WILLIAMS T 500.00

 12 CENTURY-SCOTTSDALE D 69.00 12.00

 13 CHANDLER-CHANDLER D 69.00 12.00

 14 CHAPARRAL-SCOTTSDALE D 69.00 12.00

 15 CHERYL-PHOENIX D 69.00 12.00

 16 CHILDS-CAMP VERDE D 69.00

 17 CHINO VALLEY-CHINO VALLEY D 69.00 12.00

 18 CHOLLA-JOSEPH CITY A,T 525.00 345.00

 19 CHOLLA-JOSEPH CITY A,T 525.00

 20 CHOLLA-JOSEPH CITY A,T 345.00 230.00

 21 CHOLLA-JOSEPH CITY A,T 345.00 69.00

 22 CHOLLA-JOSEPH CITY A,T 230.00 69.00

 23 CHOLLA-JOSEPH CITY D 69.00 12.00

 24 CIELO GRANDE-PHOENIX D 69.00 12.00

 25 CLINIC - SCOTTSDALE D 69.00 12.00

 26 COCONINO-FLAGSTAFF T 230.00 69.00

 27 COCONINO-FLAGSTAFF D 69.00 12.00

 28 COCOPAH-W. OF YUMA D 69.00 12.00

 29 COLDWATER-GOODYEAR D 69.00 12.00

 30 COLORADO-N. OF PARKER D 69.00 12.00

 31 COLTER-AVONDALE D 69.00 12.00

 32 CONLEY-SNOWFLAKE T 69.00

 33 COOLIDGE-N. OF COOLIDGE D 12.40

 34 COPPER CANYON-N. OF CAMP VERDE D 69.00 12.00

 35 CORDES-CORDES JUNCTION D 69.00 12.00

 36 CORNVILLE-CORNVILLE D 69.00 12.00

 37 COTTON CENTER-N. OF GILA BEND D 69.00 12.00

 38 COTTONWOOD-COTTONWOOD D 69.00 12.00

 39 COTTONWOOD-COTTONWOOD D

 40 COUNTRY CLUB-PHOENIX D 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

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).

 1 COUNTRY CLUB-PHOENIX T 230.00 69.00

 2 COUNTY LINE-TONOPAH D 69.00 12.00

 3 CROSSROADS-N. OF PARKER D 34.50 12.00

 4 DALE-SCOTTSDALE D 69.00 12.00

 5 DALE-SCOTTSDALE D 69.00

 6 DAVENPORT- E. OF WILLIAMS D 69.00 12.00

 7 DEADMAN WASH-PHOENIX D 69.00 12.00

 8 DEADMAN WASH-PHOENIX D 69.00

 9 DEER VALLEY-PHOENIX T 230.00 69.00 12.00

 10 DEER VALLEY-PHOENIX D 69.00 12.00

 11 DEL RIO-PEORIA D 69.00 12.00

 12 DELANO-PRESCOTT D 69.00 12.00

 13 DESERT RIDGE-SCOTTSDALE D 69.00 12.00

 14 DESERT SANDS - YUMA T 69.00

 15 DESERT SKY-BUCKEYE D 69.00 12.00

 16 DESERT SPRINGS-PHOENIX D 69.00 12.00

 17 DEWEY-N. OF DEWEY D 69.00 12.00

 18 DIXILETA-N. OF SCOTTSDALE D 69.00 12.00

 19 DON LUIS-BISBEE D 69.00 12.00

 20 DOUBLETREE-PHOENIX D 69.00 12.00

 21 DOVE VALLEY-PHOENIX D 69.00 12.00

 22 DOWNING-SCOTTSDALE D 69.00 12.00

 23 DRAKE-PAULDEN D 69.00

 24 DRY LAKE SUB D 69.00 7.20

 25 DUGAS-MAYER T 525.00 69.00

 26 DUGAS-MAYER T

 27 DURANGO-PHOENIX D 69.00 12.00

 28 DYSART-SURPRISE D 69.00 12.00

 29 EAGLE EYE-W. OF AGUILA T 230.00 69.00

 30 EAST END-SCOTTSDALE D 69.00 12.00

 31 EASTERN OFFICE-PHOENIX D 69.00 12.00

 32 EASTGATE-CASA GRANDE D 69.00 12.00

 33 EHRENBERG-EHRENBERG D 33.00 12.00

 34 EL SOL-YOUNGTOWN T 230.00 69.00

 35 EL SOL-YOUNGTOWN D 69.00 12.00

 36 ELDEN-FLAGSTAFF D 69.00 12.00

 37 ENCANTO-PHOENIX D 69.00 12.00

 38 ESTRELLITA-GOODYEAR D 69.00 12.00

 39 EVANS CHURCHILL-PHOENIX D 69.00 12.00

 40 FAIRVIEW-N. OF DOUGLAS D 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

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).

 1 FARMER - SURPRISE T 69.00

 2 FESTIVAL RANCH-BUCKEYE D 69.00 12.00

 3 FILLMORE-PHOENIX D 69.00 12.00

 4 FISH SAWMILL-N. OF FLAGSTAFF D 69.00 12.00

 5 FLORES-CONGRESS D 69.00 12.00

 6 FLYING E-WICKENBURG D 69.00 12.00

 7 FOOTHILLS-YUMA D 69.00 12.00

 8 FORTIETH PLACE-PHOENIX D 69.00 12.00

 9 FOUR CORNERS-FRUITLAND,NM A,T 525.00 345.00

 10 FOUR CORNERS-FRUITLAND,NM A,T 345.00 230.00

 11 FOUR CORNERS-FRUITLAND,NM A,T 230.00 69.00

 12 GARFIELD-PHOENIX D 69.00 12.00

 13 GARLAND PRAIRIE-E. OF WILLIAMS D 69.00 12.00

 14 GATEWAY - PHOENIX D 69.00 12.00

 15 GAVILAN PEAK-PHOENIX T 230.00 69.00

 16 GAVILAN PEAK-PHOENIX D 69.00 12.00

 17 GILA BEND-GILA BEND T 230.00 69.00

 18 GILA BEND-GILA BEND D 69.00 12.00

 19 GILBERT-GILBERT D 69.00 12.00

 20 GILLESPIE#1-N. OF GILA BEND D 69.00 12.00

 21 GLENDALE-GLENDALE D 230.00 12.00

 22 GRAND CANYON-GRAND CANYON D 69.00 12.00

 23 GRANITE CREEK - CHINO VALLEY T 69.00

 24 GRANITE REEF - SCOTTSDALE D 69.00 12.00

 25 GRAY MOUNTAIN-S. OF CAMERON D 69.00 12.00

 26 GREENBRIER-GLENDALE D 69.00 12.00

 27 GREENWAY-GLENDALE D 69.00 12.00

 28 GREYBEARS-CHINO VALLEY D 69.00 12.00

 29 GRISWOLD-PHOENIX D 69.00 12.00

 30 HAMBLIN D 69.00 7.20

 31 HANKS-N. OF FLAGSTAFF D 69.00 12.00

 32 HAPPY VALLEY TEMP-PEORIA D 69.00 12.00

 33 HARBOR-PHOENIX D 69.00 12.00

 34 HARQUAHALA-TONOPAH D 69.00 12.00

 35 HASHKNIFE-HEBER D 69.00

 36 HATFIELD-PEORIA D 69.00 12.00

 37 HAVASU- PARKER D 69.00 12.00

 38 HAYDEN-HAYDEN D 69.00 21.00

 39 HAYES GULCH-GLOBE D 69.00 21.00

 40 HEARN-SURPRISE D 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

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).

 1 HEDGEPETH HILLS-PHOENIX D 69.00 12.00

 2 HOHOKAM-TEMPE D 69.00 12.00

 3 HONEYWELL-PHOENIX D 69.00 12.00

 4 HOODOO WASH-YUMA T 500.00

 5 HORN-HORN D 69.00 12.00

 6 HOWARD-MESA D 69.00 12.00

 7 HUMBUG-PEORIA D 69.00 12.00

 8 HYDER-HYDER D 69.00 12.00

 9 INDIAN BEND-PHOENIX D 69.00 12.00

 10 INDIANOLA-PHOENIX D 69.00 12.00

 11 IVALON-YUMA D 69.00 12.00

 12 JACKSON STREET-PHOENIX D 69.00 12.00

 13 JAVELINA-SURPRISE D 69.00 12.00

 14 JOMAX-SCOTTSDALE D 69.00 12.00

 15 KACHINA-KACHINA VILLAGE D 69.00 12.00

 16 KEAMS CANYON-W. OF KEAMS CANYON D 69.00 21.00

 17 KEARNY-KEARNY D 21.00

 18 KIRKLAND JUNCTION-SE. OF KIRKLAND D 69.00 12.00

 19 LAGUNA-YUMA D 69.00 12.00

 20 LE BARRON HILL-FLAGSTAFF D 69.00 7.20

 21 LEROUX-N. OF HOLBROOK D 69.00 12.00

 22 LEUPP JUNCTION-W. OF WINSLOW D 69.00 21.00

 23 LIBERTY IRON-PHOENIX D 69.00

 24 LINCOLN STREET (230kV)-PHOENIX T 230.00 69.00 12.00

 25 LINCOLN STREET NORTH-PHOENIX D 69.00 12.00

 26 LINCOLN STREET WEST-PHOENIX D 69.00 12.00

 27 LITCHFIELD-LITCHFIELD PARK D 69.00 12.00

 28 LOMA VISTA-PHOENIX D 69.00 12.00

 29 LONE PEAK-PHOENIX T 230.00 69.00

 30 LONE PEAK-PHOENIX D 69.00 12.00

 31 LONESOME VALLY-PRESCOTT D 69.00 12.00

 32 LOOKOUT-PHOENIX D 69.00 12.00

 33 MAGNOLIA - STANTON D 69.00 7.20

 34 MARINE AIR BASE-YUMA D 69.00 12.00

 35 MARINETTE-SUN CITY D 69.00 12.00

 36 MARTINEZ WASH-WICKENBURG D 69.00 7.20

 37 MAZATAL-RYE D 69.00 12.00

 38 MC GUIREVILLE-MC GUIREVILLE D 69.00 12.00

 39 MCCORMICK-SCOTTSDALE D 69.00 12.00

 40 MCDOWELL-PHOENIX D 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

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).

 1 MCMICKEN-SURPRISE D 69.00 12.00

 2 MEADOWBROOK-PHOENIX T 230.00 69.00

 3 MEADOWBROOK-PHOENIX D 69.00 12.00

 4 MERIDIAN-GLENDALE D 69.00

 5 MERRILL-FLORENCE D 69.00 12.00

 6 METRO-PHOENIX D 69.00 12.00

 7 MILLER WASH-VALLE D 69.00 7.20

 8 MILLIGAN-ELOY T 230.00 69.00

 9 MILLIGAN TEMP-ELOY D 69.00 12.00

 10 MINGUS-JEROME D 69.00 7.20

 11 MITTRY D 69.00 12.00

 12 MOENKOPI-CAMERON T 525.00

 13 MOENKOPI-CAMERON T 525.00

 14 MONTE CRISTO-PHOENIX D 69.00 12.00

 15 MOON VALLEY-PHOENIX D 69.00 12.00

 16 MORGAN-PEORIA T 525.00 230.00 34.50

 17 MORRISTOWN-MORRISTOWN D 69.00 12.00

 18 MOUNTAIN VIEW-SUN CITY D 69.00 12.00

 19 MT. FLOYD-MT. FLOYD D 4.16 12.00

 20 MUMMY MOUNTAIN-PARADISE VALLEY D 69.00 12.00

 21 MUNDS PARK-S. OF FLAGSTAFF D 69.00 21.00

 22 MURAL-E. OF LOWELL D 69.00 12.00

 23 MURAL-E. OF LOWELL T 115.00 69.00

 24 NADASY-N. OF WILLIAMS D 69.00 7.20

 25 NAVAJO-PAGE A,T 500.00

 26 NAVAJO-PAGE A,T 500.00

 27 NAVAJO ARMY DEPOT-FLAGSTAFF D 69.00 12.00

 28 NEW RIVER-NEW RIVER D 69.00 12.00

 29 NEWMAN PARK-S. OF FLAGSTAFF D 69.00 7.20

 30 NORTH GILA-YUMA T 500.00

 31 NORTH GILA-YUMA T 500.00

 32 NORTH GILA-YUMA T 345.00 69.00

 33 NORTH VALLEY-PHOENIX D 69.00 12.00

 34 OAK CREAK-OAK CREEK D 69.00 12.00

 35 OBERLIN TEMP-WITTMAN D 69.00 12.00

 36 OCOTILLO-TEMPE A,T 230.00 69.00

 37 OCOTILLO-TEMPE A,T

 38 OCOTILLO-TEMPE A,T 69.00

 39 OLD HOME MANOR-CHINO VALLEY D 69.00

 40 ORANGEWOOD-PHOENIX D 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

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).

 1 ORMES-CORDES JUNCTION D 2.40 4.16

 2 OSBORNE TANK D 69.00 12.00

 3 PADRE - E. OF ANGELL D 69.00 12.00

 4 PALM VALLEY-GOODYEAR T 230.00 69.00

 5 PALM VALLEY-GOODYEAR D 69.00 12.00

 6 PALOMA-W. OF GILA BEND D 69.00 12.00

 7 PALOMINAS-PALOMINAS D 69.00 12.00

 8 PANDA - GILA BEND A,T 230.00

 9 PAPAGO BUTTE-SCOTTSDALE D 69.00 12.00

 10 PARADISE-PHOENIX D 69.00 12.00

 11 PARKS-PARKS D 69.00 12.00

 12 PATTERSON-OUT OF BUCKEYE D 69.00 12.00

 13 PATTON-OUT OF MORRISTON D 69.00 12.00

 14 PAULDEN-PAULDEN D 69.00 12.00

 15 PEBBLECREEK-GOODYEAR D 69.00 12.00

 16 PEORIA-PEORIA D 69.00 12.00

 17 PERRYVILLE-N.E. OF BUCKEYE D 69.00 12.00

 18 PICKET-SUPERIOR D 115.00 12.00

 19 PIMA-GOODYEAR D 69.00 12.00

 20 PINAL-GLOBE T 115.00 69.00

 21 PINAL-GLOBE D 69.00 21.00

 22 PINE SPRINGS-W. OF WILLIAMS D 69.00 7.20

 23 PINNACLE PEAK-PHOENIX T 500.00 230.00

 24 PINNACLE PEAK-PHOENIX T 345.00 230.00

 25 PINNACLE PEAK-PHOENIX T 230.00 69.00

 26 PIONEER-PHOENIX D 69.00 12.00

 27 PLANET-NE. OF PARKER D 69.00 12.00

 28 PLEASANT-GLENDALE D 69.00 12.00

 29 POLAND JUNCTION NW. OF MAYER D 69.00 12.00

 30 POLK-PHOENIX D 69.00 12.00

 31 POLLOCK-SW. OF ASHFORK D 69.00 12.00

 32 POPLAR WASH-PEEPLES VALLEY D 69.00 7.20

 33 PREACHER CANYON-PAYSON T 345.00 69.00

 34 PREACHER CANYON-PAYSON D 69.00 21.00

 35 PRESCOTT CHINO WELLS-CHINO VALEY D 69.00 7.20

 36 PRESCOTT CITY-PRESCOTT D 69.00 12.00

 37 PYRAMID PEAK-GLENDALE D 69.00 12.00

 38 QUAIL SPRINGS-SE. OF COTTONWOOD D 69.00 12.00

 39 QUARTZSITE-QUARTZSITE D 69.00 12.00

 40 QUECHAN-YUMA D 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name 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

(a) (b) (c)

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).

 1 RACEWAY-PEORIA T 230.00 69.00

 2 RAINBOW VALLEY-SE. OF BUCKEYE D 69.00 12.00

 3 RAINTREE-SCOTTSDALE D 69.00 12.00

 4 RAMON ASO-RED LAKE, N. OF WILLIAMS D 69.00 12.40

 5 RAWHIDE-SCOTTSDALE D 69.00 12.00

 6 REACH-SCOTTSDALE T 230.00 69.00

 7 RED LAKE-E. OF WILLIAMS D 69.00 21.00

 8 REDONDO-YUMA D 69.00 12.00

 9 REIDHEAD-SNOWFLAKE D 69.00 7.20

 10 RINCON-WICKENBURG D 69.00 7.20

 11 RIO VISTA-SUN CITY D 69.00 12.00

 12 RIVERSIDE-YUMA D 69.00 12.00

 13 ROAD RUNNER-PHOENIX D 69.00 12.00

 14 ROBBINS BUTTE-OUT OF BUCKEYE D 69.00 7.20

 15 ROCK SPRINGS-ROCK SPRINGS D 69.00 12.00

 16 ROGERS LAKE-SW. OF FLAGSTAFF D 69.00 7.20

 17 ROSE GARDEN-PHOENIX D 69.00 12.00

 18 ROUND VALLEY T 230.00

 19 SADDLE MTN-W. OF TONOPAH D 69.00 12.00

 20 SADDLEBROOK-ORACLE JUNCTION T 115.00

 21 SAGE VALLEY-VALLE D 69.00 12.00

 22 SAGUARO 525kV-RED ROCK A,T 500.00 115.00

 23 SAGUARO 230kv-RED ROCK A,T 230.00 115.00

 24 SAGUARO 115kV-RED ROCK A,T 115.00 12.50

 25 SALOME-S.E. OF SALOME D 69.00 12.00

 26 SAN LUIS-SAN LUIS D 69.00 12.00

 27 SAN LUIS (MEXICO CONN.)-SAN LUIS D 69.00 34.50

 28 SAN MANUEL-SAN MANUEL D 115.00 46.00

 29 SAN MANUEL-SAN MANUEL D 115.00 12.00

 30 SAN PEDRO-W. OF DOUGLAS D 69.00 12.00

 31 SANDVIG-FLAGSTAFF D 69.00 12.00

 32 SANGUINETTI-YUMA T 69.00

 33 SANTA ROSA-SE. OF MARICOPA T 230.00 69.00

 34 SARIVAL-GOODYEAR D 69.00 12.00

 35 SEDONA-SEDONA D 69.00 12.00

 36 SELIGMAN COMPRESSER STATION-SELIGMAN D 230.00 4.20

 37 SEXTON-E. OF STANFIELD D 69.00

 38 SHAW-PHOENIX D 69.00 12.00

 39 SHEA-SCOTTSDALE D 69.00 12.00

 40 SHERMAN STREET-PHOENIX D 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name 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

(a) (b) (c)

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).

 1 SHOW LOW-SHOW LOW D 69.00 12.00

 2 SHOW LOW-SHOW LOW D 69.00

 3 SHUMWAY-SHOW LOW D 69.00 12.00

 4 SHUMWAY-SHOW LOW D 69.00

 5 SKUNK CREEK-GLENDALE D 69.00 12.00

 6 SNOWFLAKE-SNOWFLAKE D 69.00 12.00

 7 SOLANA-GILA BEND D 69.00 12.00

 8 SONORA D 69.00 12.00

 9 SOUTH O'NEIL - YUMA T 69.00

 10 SPANISH GARDENS-SURPRISE D 69.00 12.00

 11 SPIDER WEB-S. OF GRAY MOUNTAIN D 69.00 2.30

 12 STAGECOACH-SCOTTSDALE D 69.00 12.00

 13 STANTON-S. OF YARNELL D 69.00 7.20

 14 STARDUST-SUN CITY WEST D 69.00 12.00

 15 STOUT-PHOENIX D 69.00 12.00

 16 STRAWBERRY-STRAWBERRY D 69.00 21.00

 17 STURM RUGER-N. OF PRESCOTT D 69.00 4.16

 18 STURM RUGER-N. OF PRESCOTT D 69.00 12.40

 19 SUGARLOAF-SNOWFLAKE T 525.00 69.00

 20 SUNDOG-PRESCOTT D 69.00 12.00

 21 SUNNYSLOPE-PHOENIX T 230.00 69.00

 22 SUNNYSLOPE-PHOENIX D 69.00 12.00

 23 SUNSHINE-WINSLOW D 69.00 12.00

 24 SURPRISE-SURPRISE T 230.00 69.00

 25 SURPRISE-SURPRISE D 69.00 12.00

 26 SWITZER CANYON-FLAGSTAFF D 69.00 12.00

 27 SYCAMORE-DUGAS D 69.00 7.20

 28 TABLE MESA-NEW RIVER D 69.00 7.20

 29 TAPCO-E. OF CLARKDALE D 69.00 2.40

 30 TARTESSO-BUCKEYE D 69.00 12.00

 31 TAT MOMOLI-CASA GRANDE T 230.00

 32 TEMPE-TEMPE D 69.00 12.00

 33 TENTH STREET-YUMA D 69.00 12.00

 34 THAYER-THAYER D 69.00 12.00

 35 THIRTY-SECOND STREET-YUMA D 69.00 12.00

 36 THOMPSON PEAK-SCOTTSDALE D 69.00 12.00

 37 TOLTEC-ARIZONA CITY D 69.00 12.00

 38 TONALEA-TUBA CITY D 69.00 12.00

 39 TONOPAH-TONOPAH D 69.00 12.00

 40 TONTO-PAYSON D 69.00 21.00

FERC FORM NO. 1 (ED. 12-96) Page 426.8
Name 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

(a) (b) (c)

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).

 1 TONTO-PAYSON D

 2 TUBA CITY-TUBA CITY D 69.00 12.00

 3 TURF-PHOENIX D 69.00 12.00

 4 TUSAYAN-TUSAYAN D 69.00 12.00

 5 TUSAYAN-TUSAYAN D 69.00

 6 TUTHILL-BUCKEYE D 69.00 12.00

 7 TWENTY-THIRD STREET-PHOENIX D 69.00 12.00

 8 TWIN ARROWS - FLAGSTAFF T 69.00

 9 UNION HILLS-PHOENIX D 69.00 12.00

 10 UTTING-SE. OF BOUSE D 69.00 12.00

 11 VALENCIA-BUCKEYE D 69.00 12.00

 12 VALLE-WILLIAMS D 69.00 21.00

 13 VALLEY FARMS-FLORENCE T 115.00 69.00

 14 VALLEY FARMS-FLORENCE D 69.00 12.00

 15 VARNEY-SURPRISE D 69.00 12.00

 16 VERDE-CLARKDALE T 230.00 69.00

 17 VICKSBURG-S. OF VICKSBURG JUNCTION D 69.00 12.00

 18 VISTA-CASA GRANDE D 69.00 12.00

 19 WADDELL-SURPRISE D 69.00 12.00

 20 WALDRIP - YUMA T 69.00

 21 WATSON-BUCKEYE D 69.00 12.00

 22 WELCH-E. OF ASHBROOK D 69.00 2.40

 23 WELLFIELD - PRESCOTT VALLEY D 69.00

 24 WEST PHOENIX-PHOENIX T 230.00 69.00

 25 WEST PHOENIX-PHOENIX D 69.00 12.40

 26 WESTBROOK-PEORIA D 69.00 12.00

 27 WESTWING-SUN CITY T 525.00 230.00

 28 WESTWING-SUN CITY T 525.00

 29 WESTWING-SUN CITY T 525.00

 30 WESTWING-SUN CITY T 230.00

 31 WESTWING-SUN CITY T 69.00 12.00

 32 WESTWING-SUN CITY T 230.00 69.00

 33 WHITE SPAR-PRESCOTT D 69.00 12.00

 34 WHITE TANKS-AVONDALE T 230.00 69.00

 35 WHY-WHY D 69.00 21.00

 36 WICKENBURG-WICKENBURG D 69.00 12.00

 37 WILD BURRO-NEW RIVER D 69.00 7.20

 38 WILD FLOWER-GOODYEAR D 69.00 12.00

 39 WILHOIT-PRESCOTT D 69.00 12.00

 40 WILLIAMS-WILLIAMS D 69.00 12.00

FERC FORM NO. 1 (ED. 12-96) Page 426.9
Name 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

(a) (b) (c)

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).

 1 WILLOW LAKE-PRESCOTT T 230.00 115.00

 2 WILLOW LAKE-PRESCOTT T 230.00 69.00

 3 WINONA-WINONA D 69.00 12.00

 4 WINSLOW-WINSLOW D 69.00 12.00

 5 WINTERSBURG-WINTERSBURG D 69.00 12.00

 6 WOODRUFF-HOLBROOK D 69.00 21.00

 7 WOODY MOUNTAIN-FLAGSTAFF D 69.00 12.00

 8 WUPATKI-FLAGSTAFF D 69.00 12.00

 9 YALE-PHOENIX D 69.00 12.00

 10 YARNELL-YARNELL D 69.00 12.00

 11 YAVAPAI-CHINO VALLEY T 525.00 230.00

 12 YAVAPAI-CHINO VALLEY T 230.00 69.00

 13 YORKSHIRE-PHOENIX D 69.00 12.00

 14 YUCCA-YUMA T 161.00 69.00

 15 YUMA PALMS TEMP-YUMA D 69.00 12.00

 16 ZENIFF-SNOWFLAKE D 69.00

 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 426.10
Name 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

Number of Units No.

(f) (g) (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 capacitor bank-69kv 1 48 4

 20 1 capacitor bank-69kv 1 5 5

 9 1 6

capacitor bank-69kv 1 48 7

 83 2 8

 20 1 9

 57 2 capacitor bank-69kv 1 14 10

 20 1 capacitor bank-12kv 2 4 11

 12 1 12

 83 2 capacitor bank-69kv 1 22 13

 42 1 14

 9 1 15

 9 1 16

 16 1 17

 3 1 18

 28 1 19

capacitor bank-115kv 4 40 20

 20 1 capacitor bank-69kv 1 14 21

 83 2 capacitor bank -12kv 2 10 22

 40 2 capacitor bank-69kv 2 22 23

 20 1 24

 83 2 25

capacitor bank-69kv 1 14 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 capacitor bank-69kv 1 10 38

 167 4 39

 522 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427
Name 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

Number of Units No.

(f) (g) (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 capacitor bank-69kv 1 48 1

 41 1 2

 125 3 3

 2 1 4

 83 2 5

 40 2 capacitor bank-12kV 4 14 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 capacitor bank 500kv 1 395 18

reactor 500kV 4 125 19

 203 1 capacitor bank 345kv 2 870 20

 143 1 21

 150 2 22

 9 1 23

 83 2 capacitor bank -12kV 2 7 24

 40 2 capacitor bank -12kV 2 7 25

 355 2 26

 40 2 capacitor bank-69kv 2 36 27

 83 2 cap bank 69kv 1 14 28

 83 2 cap bank 69kv 1 29 29

 9 1 30

 83 2 31

 32

 33

 41 2 capacitor bank-12kv 4 12 34

 20 1 35

 20 1 capacitor bank 69kv 1 7 36

 40 2 37

 40 2 capacitor bank-69kV 1 11 38

capacitor bank-12kV 2 6 39

 125 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

Number of Units No.

(f) (g) (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 capacity bank-69kV 2 14 2

 20 1 3

 83 2 capacitor bank-12kv 2 7 4

capacitor bank 69kV 1 29 5

 3 1 6

 83 2 capacitor bank -12kv 2 7 7

capacitor - 69kv 1 29 8

 564 3 9

 125 3 capacitor bank-69kV 1 48 10

 18 1 11

 40 2 12

 83 2 capacitor bank-12kv 2 10 13

 14

 4 1 15

 83 2 capacitor bank-12kv 2 10 16

 40 2 capacitor bank-69kv 1 14 17

 83 2 capacitor bank-12kv 2 7 18

 20 1 19

 42 1 20

 83 2 capacitor bank-12kv 2 4 21

 123 3 capacitor bank-69kv 1 48 22

capacitor bank-69kv 3 22 23

 1 24

 269 3 4 shunt reactor 1 190 25

capacitor bank-525kv 1 372 26

 83 2 capacitor bank-12kV 2 7 27

 125 3 28

 100 2 29

 41 1 capacitor bank-12kV 2 5 30

 41 1 capacitor bank-12kV 1 4 31

 41 1 capacitor bank-12kV 2 14 32

 20 1 33

 376 2 34

 83 2 capacitor bank-69kv 1 48 35

 40 2 36

 83 2 37

 41 1 capacitor bank-12kv 1 4 38

 83 2 capacitor bank-12kv 4 10 39

 41 1 capacitor bank-12kv 4 10 40

FERC FORM NO. 1 (ED. 12-96) Page 427.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

Number of Units No.

(f) (g) (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 capacitor bank-69kv 1 29 3

 1 2 4

 20 1 capacitor bank-69kv 1 7 5

 20 1 capacitor bank-69kv 2 22 6

 83 2 capacitor bank-69kv 2 29 7

 83 2 capacitor bank-12kv 2 7 8

 1025 3 1 reactor 525kv 3 125 9

 1325 2 1 reactor 345kV 4 155 10

 106 2 11

 167 4 capacitor bank 12kv 4 10 12

 10 1 13

 42 14

 188 1 15

 41 1 16

 200 2 17

 40 2 capacitor bank-69kv 2 30 18

 83 2 capacitor bank 12kv 2 7 19

 20 1 capacitor bank-69kv 1 14 20

 100 2 21

 9 1 22

 23

 41 1 24

 1 2 25

 41 1 26

 125 3 capacitor bank-12kV 3 11 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 427.3
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

Number of Units No.

(f) (g) (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 capacitor bank-69kv 1 29 1

 20 1 capacitor bank-12kv 2 5 2

 83 2 3

 4

 10 1 5

 1 6

 40 2 7

 9 1 8

 83 2 capacitor bank-12kV 2 7 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 capacitor bank-69kV 2 29 19

 1 20

 20 1 21

 6 1 22

 23

 188 1 24

 83 2 capacitor bank-69kV 1 35 25

 167 4 capacitor bank-12kv 8 19 26

 83 2 27

 83 2 28

 376 2 29

 41 1 30

 40 2 31

 83 2 32

 1 33

 83 2 capacitor bank-12kV 2 7 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 427.4
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

Number of Units No.

(f) (g) (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 capacitor bank-69kV 1 48 3

 4

 41 1 capacitor bank-69kv 2 14 5

 125 3 capacitor bank -12kv 4 10 6

 1 7

 188 1 1 8

 20 1 9

 1 2 10

 7 1 11

capacitor bank 525kv 4 1,540 12

shunt reactor 525kv 10 646 13

 83 2 14

 83 2 15

 600 1 16

 9 1 capacitor bank-69kv 1 11 17

 83 2 capacitor bank-69kv 1 48 18

 3 1 19

 83 2 20

 9 1 21

 9 1 capacitor bank-12kv 4 10 22

 50 1 23

 1 24

shunt reactor-525kv 2 382 25

capacitor bank 525kV 2 1,207 26

 6 1 27

 20 1 28

 1 29

shunt reactor 4 184 30

capacitor bank 500kv 1 489 31

 509 6 1 32

 83 2 33

 40 2 capacitor bank 12kv 2 10 34

 16 1 35

 355 2 36

capacitor bank 230kv 2 318 37

capacitor bank 69kv 1 48 38

 39

 125 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Arizona Public Service Company X

04/10/2013

2012/Q4

Line

Number of Units No.

(f) (g) (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 capacitor bank-12kV 2 7 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 shunt reactor - 525V 1 190 23

 2025 3 1 24

 752 4 capacitor bank 230kv 3 159 25

 83 2 26

 4 1 27

 20 1 28

 9 1 29

 40 2 capacitor bank-69kV 2 29 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 capacitor bank-69kv 2 22 38

 16 1 39

 83 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.6
Name 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

Number of Units No.

(f) (g) (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 capacitor bank-69kV 1 48 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 capacitor bank-69kv 1 7 19

 20

 1 21

 1450 2 reactor 525kV 1 42 22

 896 2 1 23

 22 1 2 capacitor bank-115kv 2 49 24

 20 1 capacitor bank-69kv 2 7 25

 40 2 capacitor bank-69kv 1 7 26

 20 1 capacitor bank-34.5k 1 4 27

 65 4 28

 138 5 capacitor bank-115kV 4 112 29

 6 1 30

 32 2 31

 32

 355 2 capacitor bank 230kv 2 94 33

 83 2 capacitor bank-69kV 2 29 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 427.7
Name 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

Number of Units No.

(f) (g) (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 capacitor bank-12kv 4 10 1

capacitor bank-69kV 3 29 2

 9 1 capacitor bank-12kv 2 6 3

capacitor bank-69kV 2 14 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 capacitor bank-69kv 1 14 19

 40 2 capacitor bank-69kv 1 7 20

 355 2 21

 83 2 capacitor bank-69kv 1 43 22

 2 3 23

 564 3 capacitor bank-69kv 1 53 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 capacitor bank 69kv 2 14 37

 1 2 38

 16 1 capacitor bank-69kv 1 10 39

 40 2 capacitor bank-69kv 1 7 40

FERC FORM NO. 1 (ED. 12-96) Page 427.8
Name 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

Number of Units No.

(f) (g) (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.

capacitor bank-21.6 4 10 1

 20 1 capacitor bank - 12V 2 6 2

 83 2 3

 9 1 capacitor bank-12kv 6 7 4

capacitor bank-69kV 1 7 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 capacitor bank-69kV 4 29 16

 20 1 17

 83 2 capacitor bank-12kv 4 14 18

 41 1 19

 20

 83 2 21

 1 22

 20 1 23

 564 3 capacitor bank-69kv 1 35 24

 166 3 capacitor bank-12kV 4 10 25

 41 1 26

 4500 9 2 27

reactor 525kV 3 571 28

capacitor bank 525kv 1 390 29

reactor 230kV 2 212 30

 41 1 31

 376 2 32

 40 2 capacitor bank-12kv 4 12 33

 376 2 34

 3 1 35

 36 2 capacitor bank-69kv 1 12 36

 1 37

 83 2 38

 3 1 39

 17 2 capacitor bank-69kv 1 6 40

FERC FORM NO. 1 (ED. 12-96) Page 427.9
Name 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

Number of Units No.

(f) (g) (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 reactor 230kV 1 25 1

 376 2 2

 3 1 3

 20 2 4

 18 1 5

 4 1 6

 18 1 capacitor bank 69kv 1 7 7

 1 8

 83 2 capacitor bank-12kv 4 10 9

 9 1 10

 672 2 11

 100 1 12

 20 1 13

 84 1 capacitor bank-69kv 1 25 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) X An 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) X An 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) X An 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 450.3
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

(a) (b) (c) (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 Pinnacle West Capital Corporation 438 222,200,000

 3 Share of estimated income taxes Pinnacle West Capital Corporation 236 1,196,491

 4 Share of withholding and payroll taxes Pinnacle West Capital Corporation 236,241,408 224,633,281

 5 Share of other post retirement benefits

 6 contributions Pinnacle West Capital Corporation 228.3 86,733,806

 7 Share of employee benefits

 8 (excluding pension & OPEB contributions) Pinnacle West Capital Corporation 228.3,925,926 131,538,698

 9 Employee payroll deductions Pinnacle West Capital Corporation 143,232,242 58,403,066

 10 Shared services Pinnacle West Capital Corporation various 25,554,514

 11 Compensation paid in stock Pinnacle West Capital Corporation various 36,538,598

 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 Pinnacle West Capital Corporation 228.3 30,375,306

 23 Shared services Pinnacle West Capital Corporation various 11,336,921

 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) X An 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

FERC FORM NO. 1 (ED. 12-95) Index 2
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

FERC FORM NO. 1 (ED. 12-95) Index 3
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

FERC FORM NO. 1 (ED. 12-90) Index 4
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

FERC FORM NO. 1 (ED. 12-90) Index 5