Edgar Filing: ARIZONA PUBLIC SERVICE CO

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File
Number

Exact Name of Each Registrant as specified in its
charter; State of Incorporation; Address; and
Telephone Number

IRS Employer
Identification No.

1-8962

PINNACLE WEST CAPITAL CORPORATION

(an Arizona corporation)

400 North Fifth Street, P.O. Box 53999

Phoenix, Arizona 85072-3999

(602) 250-1000

86-0512431

1-4473

ARIZONA PUBLIC SERVICE COMPANY

(an Arizona corporation)

400 North Fifth Street, P.O. Box 53999

Phoenix, Arizona 85072-3999

(602) 250-1000

86-0011170

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PINNACLE WEST CAPITAL CORPORATION		Yes x No o
ARIZONA PUBLIC SERVICE COMPANY		Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PINNACLE WEST CAPITAL CORPORATION		Yes x No o
ARIZONA PUBLIC SERVICE COMPANY		Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

PINNACLE WEST CAPITAL CORPORATION

Large accelerated filer x	Accelerated filer o

Non-accelerated filer o	Smaller reporting company o

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer o	Accelerated filer o

Non-accelerated filer x	Smaller reporting company o

Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act Rule 12b-2).

PINNACLE WEST CAPITAL CORPORATION		Yes o No x
ARIZONA PUBLIC SERVICE COMPANY		Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

PINNACLE WEST CAPITAL CORPORATION		Number of shares of common stock, no par value, outstanding as of October 29, 2012: 109,699,804
ARIZONA PUBLIC SERVICE COMPANY		Number of shares of common stock, $2.50 par value, outstanding as of October 29, 2012: 71,264,947

Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

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TABLE OF CONTENTS

			Page

Forward-Looking Statements			2
Part I			3
	Item 1.	Financial Statements	3
		Pinnacle West Capital Corporation	3
		Arizona Public Service Company	44
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	75
	Item 4.	Controls and Procedures	75

Part II			77
	Item 1.	Legal Proceedings	77
	Item 1A.	Risk Factors	77
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	77
	Item 5.	Other Information	78
	Item 6.	Exhibits	80
Signatures			83

This combined Form 10-Q is separately provided by Pinnacle West Capital Corporation (“Pinnacle West”) and Arizona Public Service Company (“APS”). Any use of the words “Company,” “we,” and “our” refer to Pinnacle West. Each registrant is providing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is providing any information that does not relate to such registrant, and therefore makes no representation as to any such information. The information required with respect to each company is set forth within the applicable items. Item 1 of this report includes Condensed Consolidated Financial Statements of Pinnacle West and Condensed Consolidated Financial Statements of APS. Item 1 also includes Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS, and Supplemental Notes, which only relate to APS’s Condensed Consolidated Financial Statements.

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FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (“2011 Form 10-K”), Part II, Item 1A of this report and in Part I, Item 2 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, these factors include, but are not limited to:

· our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;

· variations in demand for electricity, including those due to weather, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation;

· power plant and transmission system performance and outages;

· volatile fuel and purchased power costs;

· fuel and water supply availability;

· our ability to achieve timely and adequate rate recovery of our costs, including returns on debt and equity capital;

· regulatory and judicial decisions, developments and proceedings;

· new legislation or regulation, including those relating to environmental requirements and nuclear plant operations;

· our ability to meet renewable energy and energy efficiency mandates and recover related costs;

· risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;

· competition in retail and wholesale power markets;

· the duration and severity of the economic decline in Arizona and current real estate market conditions;

· the cost of debt and equity capital and the ability to access capital markets when required;

· changes to our credit ratings;

· the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

· the liquidity of wholesale power markets and the use of derivative contracts in our business;

· potential shortfalls in insurance coverage;

· new accounting requirements or new interpretations of existing requirements;

· generation, transmission and distribution facility and system conditions and operating costs;

· the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our region;

· the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations;

· technological developments affecting the electric industry; and

· restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission (“ACC”) orders.

These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our 2011 Form 10-K and in Part II, Item 1A of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars and shares in thousands, except per share amounts)

	Three Months Ended September 30,
	2012			2011

OPERATING REVENUES	$	1,109,475		$	1,124,841
OPERATING EXPENSES
Fuel and purchased power	302,894			337,896
Operations and maintenance	220,729			210,035
Depreciation and amortization	100,353			106,350
Taxes other than income taxes	36,507			34,223
Other expenses	1,022			1,320
Total	661,505			689,824
OPERATING INCOME	447,970			435,017
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	5,708			7,378
Other income (Note 11)	420			441
Other expense (Note 11)	(5,696		)	(3,052		)
Total	432			4,767
INTEREST EXPENSE
Interest charges	52,242			62,034
Allowance for borrowed funds used during construction	(3,830		)	(6,939		)
Total	48,412			55,095
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	399,990			384,689
INCOME TAXES	147,116			131,416
INCOME FROM CONTINUING OPERATIONS	252,874			253,273
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(7) and $6,216 (Note 13)	(11		)	9,512
NET INCOME	252,863			262,785
Less: Net income attributable to noncontrolling interests (Note 7)	8,040			7,426
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	244,823		$	255,359

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		109,555			109,128
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,655			109,861

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	2.23		$	2.25
Net income attributable to common shareholders — basic	2.23			2.34
Income from continuing operations attributable to common shareholders — diluted	2.21			2.24
Net income attributable to common shareholders — diluted	2.21			2.32

DIVIDENDS DECLARED PER SHARE	$	—		$	—

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	244,834		$	245,838
Discontinued operations, net of tax	(11		)	9,521
Net income attributable to common shareholders	$	244,823		$	255,359

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended September 30,
	2012			2011

NET INCOME	$	252,863		$	262,785

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $47 and $10,055	(72		)	(15,402		)
Reclassification of net realized loss, net of tax benefit of $19,543 and $23,361	29,935			35,783
Pension and other postretirement benefits activity, net of tax expense of $640 and $489	980			750
Total other comprehensive income	30,843			21,131

COMPREHENSIVE INCOME	283,706			283,916
Less: Comprehensive income attributable to noncontrolling interests	8,040			7,426

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	275,666		$	276,490

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars and shares in thousands, except per share amounts)

	Nine Months Ended September 30,
	2012			2011

OPERATING REVENUES	$	2,608,682		$	2,573,487

OPERATING EXPENSES
Fuel and purchased power	783,926			793,952
Operations and maintenance	647,628			675,654
Depreciation and amortization	301,068			319,550
Taxes other than income taxes	120,271			112,002
Other expenses	5,323			4,536
Total	1,858,216			1,905,694
OPERATING INCOME	750,466			667,793
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	15,639			18,697
Other income (Note 11)	1,357			2,630
Other expense (Note 11)	(12,433		)	(7,921		)
Total	4,563			13,406
INTEREST EXPENSE
Interest charges	162,209			183,251
Allowance for borrowed funds used during construction	(10,428		)	(14,371		)
Total	151,781			168,880
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	603,248			512,319
INCOME TAXES	219,160			176,229
INCOME FROM CONTINUING OPERATIONS	384,088			336,090
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(1,047) and $7,121 (Note 13)	(1,595		)	10,860
NET INCOME	382,493			346,950
Less: Net income attributable to noncontrolling interests (Note 7)	23,582			20,041
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	358,911		$	326,909

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,449			109,003
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	110,420			109,683

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	3.29		$	2.90
Net income attributable to common shareholders — basic	3.28			3.00
Income from continuing operations attributable to common shareholders — diluted	3.26			2.88
Net income attributable to common shareholders — diluted	3.25			2.98

DIVIDENDS DECLARED PER SHARE	$	1.575		$	1.575

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	360,515		$	316,001
Discontinued operations, net of tax	(1,604		)	10,908
Net income attributable to common shareholders	$	358,911		$	326,909

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Nine Months Ended September 30,
	2012			2011

NET INCOME	$	382,493		$	346,950

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $14,817 and $16,113	(22,696		)	(24,679		)
Reclassification of net realized loss, net of tax benefit of $34,361 and $39,213	52,632			60,065
Pension and other postretirement benefits activity, net of tax expense of $1,797 and $1,853	2,752			2,838
Total other comprehensive income	32,688			38,224

COMPREHENSIVE INCOME	415,181			385,174
Less: Comprehensive income attributable to noncontrolling interests	23,582			20,041

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	391,599		$	365,133

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	September 30, 2012			December 31, 2011
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	79,479		$	33,583
Customer and other receivables	365,309			284,183
Accrued unbilled revenues	136,425			125,239
Allowance for doubtful accounts	(4,297		)	(3,748		)
Materials and supplies (at average cost)	219,026			204,387
Fossil fuel (at average cost)	31,234			22,000
Deferred income taxes	95,487			130,571
Income tax receivable (Note 6)	—			6,466
Assets from risk management activities (Note 8)	26,257			30,264
Deferred fuel and purchased power regulatory asset (Note 3)	67,910			27,549
Other regulatory assets (Note 3)	53,960			69,072
Other current assets	28,062			26,904
Total current assets	1,098,852			956,470

INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 8)	38,449			49,322
Nuclear decommissioning trust (Note 15)	566,960			513,733
Other assets	62,428			64,588
Total investments and other assets	667,837			627,643

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	14,116,015			13,753,971
Accumulated depreciation and amortization	(4,901,833		)	(4,709,991		)
Net	9,214,182			9,043,980
Construction work in progress	587,826			496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	129,962			132,864
Intangible assets, net of accumulated amortization	152,665			170,571
Nuclear fuel, net of accumulated amortization	139,873			118,098
Total property, plant and equipment	10,224,508			9,962,258

DEFERRED DEBITS
Regulatory assets (Note 3)	1,250,792			1,352,079
Income tax receivable (Note 6)	69,953			68,633
Other	148,344			143,935
Total deferred debits	1,469,089			1,564,647

TOTAL ASSETS	$	13,460,286		$	13,111,018

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	September 30, 2012			December 31, 2011
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	231,151		$	326,987
Accrued taxes (Note 6)	190,188			120,289
Accrued interest	50,890			54,872
Current maturities of long-term debt	90,360			477,435
Customer deposits	76,853			72,176
Liabilities from risk management activities (Note 8)	56,263			53,968
Regulatory liabilities (Note 3)	96,362			88,362
Other current liabilities	157,281			148,616
Total current liabilities	949,348			1,342,705

LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities	3,281,531			2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	57,420			65,547
Total long-term debt less current maturities	3,338,951			3,019,054

DEFERRED CREDITS AND OTHER
Deferred income taxes	2,115,316			1,925,388
Regulatory liabilities (Note 3)	746,754			737,332
Liability for asset retirements	294,524			279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,206,150			1,268,910
Liabilities from risk management activities (Note 8)	81,244			82,495
Customer advances	105,941			116,805
Coal mine reclamation	118,601			117,896
Unrecognized tax benefits (Note 6)	69,791			72,270
Other	248,082			217,934
Total deferred credits and other	4,986,403			4,818,673

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

EQUITY (Note 9)
Common stock, no par value	2,456,107			2,444,247
Treasury stock	(1,440		)	(4,717		)
Total common stock	2,454,667			2,439,530
Retained earnings	1,721,050			1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(62,695		)	(65,447		)
Derivative instruments	(56,780		)	(86,716		)
Total accumulated other comprehensive loss	(119,475		)	(152,163		)
Total shareholders’ equity	4,056,242			3,821,850
Noncontrolling interests (Note 7)	129,342			108,736
Total equity	4,185,584			3,930,586

TOTAL LIABILITIES AND EQUITY	$	13,460,286		$	13,111,018

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	382,493		$	346,950
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of energy-related products and services business	—			(10,404		)
Depreciation and amortization including nuclear fuel	360,570			370,107
Deferred fuel and purchased power	51,533			30,965
Deferred fuel and purchased power amortization	(91,894		)	(121,018		)
Allowance for equity funds used during construction	(15,639		)	(18,697		)
Deferred income taxes	206,501			131,582
Change in derivative instruments fair value	(943		)	1,861
Changes in current assets and liabilities:
Customer and other receivables	(76,697		)	(47,410		)
Accrued unbilled revenues	(11,186		)	(80,877		)
Materials, supplies and fossil fuel	(23,873		)	(25,532		)
Other current assets	(10,035		)	(1,581		)
Accounts payable	(69,776		)	29,340
Accrued taxes and income tax receivable — net	76,365			89,534
Other current liabilities	17,071			30,300
Change in margin and collateral accounts — assets	1,980			33,591
Change in margin and collateral accounts — liabilities	114,579			85,785
Change in unrecognized tax benefits	(3,554		)	12,123
Change in other long-term assets	(15,205		)	(10,678		)
Change in other long-term liabilities	37,181			74,565
Net cash flow provided by operating activities	929,471			920,506

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(670,684		)	(643,261		)
Contributions in aid of construction	41,451			36,351
Allowance for borrowed funds used during construction	(10,428		)	(14,371		)
Proceeds from sale of energy-related products and services business	—			45,111
Proceeds from nuclear decommissioning trust sales	295,126			405,637
Investment in nuclear decommissioning trust	(308,063		)	(417,957		)
Proceeds from sale of life insurance policies	—			55,444
Other	(520		)	(1,246		)
Net cash flow used for investing activities	(653,118		)	(534,292		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	351,081			470,353
Repayment of long-term debt	(421,703		)	(228,457		)
Short-term borrowings and payments — net	—			(16,600		)
Dividends paid on common stock	(167,074		)	(166,197		)
Common stock equity issuance	9,684			14,953
Distributions to noncontrolling interests	(2,630		)	(2,610		)
Other	185			(3,132		)
Net cash flow provided by (used for) financing activities	(230,457		)	68,310

NET INCREASE IN CASH AND CASH EQUIVALENTS	45,896			454,524

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	33,583			110,188

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	79,479		$	564,712
Supplemental disclosure of cash flow information Cash paid during the period for:
Income taxes, net of (refunds)	$	(651	)	$	5,676
Interest, net of amounts capitalized	$	152,582		$	163,250

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Consolidation and Nature of Operations

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS and El Dorado Investment Company (“El Dorado”) and formerly SunCor Development Company (“SunCor”) and APS Energy Services Company, Inc. (“APSES”). See Note 13 for discussion of the bankruptcy filing of SunCor and the sale of APSES. Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station (“Palo Verde”) sale leaseback variable interest entities (“VIEs”) (see Note 7 for further discussion). 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.

Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. These condensed consolidated financial statements and notes have been prepared consistently with the 2011 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.

See Note 16 for discussion of amended guidance on the presentation of comprehensive income.

The following tables show the impact of the reclassifications to prior year (previously reported) amounts (dollars in thousands):

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Statement of Income for the Three Months Ended September 30, 2011	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassifications to conform to current year presentation
Operating Revenues
Regulated electricity segment	$	1,124,049		$	(1,124,049	)	$	—
Other revenues	792			(792		)	—
Operating revenues	—			1,124,841			1,124,841

Statement of Income for the Nine Months Ended September 30, 2011	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassifications to conform to current year presentation
Operating Revenues
Regulated electricity segment	$	2,570,692		$	(2,570,692	)	$	—
Other revenues	2,795			(2,795		)	—
Operating revenues	—			2,573,487			2,573,487

Statement of Cash Flows for the Nine Months Ended September 30, 2011	As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassifications to conform to current year presentation
Cash Flows from Investing Activities
Proceeds from sale of commercial real estate investments	$	1,100		$	(1,100	)	$	—
Other	(2,346		)	1,100			(1,246		)

2. Long-Term Debt and Liquidity Matters

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

Pinnacle West

At September 30, 2012, Pinnacle West’s $200 million credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At September 30, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

APS

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.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 we remarketed these bonds. Currently, the interest rate on these bonds is reset daily by a remarketing agent. The daily rate at September 30, 2012 was 0.20% per annum. Additionally, the bonds are supported by a letter of credit. These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at September 30, 2012 and were classified as current maturities of long-term debt on our Condensed 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 Condensed Consolidated Balance Sheets at September 30, 2012 and were classified as current maturities of long-term debt on our Condensed 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. The bonds were reflected as long-term debt on our Condensed Consolidated Balance Sheets as of September 30, 2012.

At September 30, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, and a $500 million facility that matures in November 2016. 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 September 30, 2012, APS had no outstanding borrowings or outstanding letters of credit under these credit facilities, nor did it have any commercial paper borrowings.

See “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

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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. See Note 14 for discussion of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

	As of September 30, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Pinnacle West	$	125	$	125	$	125	$	123
APS	3,304		3,817		3,371		3,803
Total	$	3,429	$	3,942	$	3,496	$	3,926

Debt Provisions

An 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 September 30, 2012, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.2 billion, and total capitalization was approximately $7.4 billion. APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same. Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

3. 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 purchased power costs (“Base Fuel Rate”)) from $0.03757 to $0.03207 per kilowatt-hour (“kWh”); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff (“RES”) surcharge to base rates in an estimated amount of $36.8 million.

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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 the related closure of Units 1-3 of the Four Corners Power Plant (“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 Power Supply Adjustor (“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 Adjustor 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 to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

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· 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

· 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.

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On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requesting 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, (i) own an additional 100 megawatts (“MW”) under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility-owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015. In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications. Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $92.8 million to $102.4 million. The budget range stems from options related to distributed energy. The first option involves no new incentives for distributed energy. The second option would offer incentives for residential photovoltaic distributed energy beginning where 2012 incentives end and stepping down gradually based upon market participation. APS’s filing also proposed a system of establishing compliance with distributed energy requirements that depends upon tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. Further, APS described its Community Solar program, a utility-owned 25 MW program that will be split into 3 to 7 separate projects throughout communities in APS’s service territory (this is the 25 MW program described in clause (iv) of the preceding paragraph). APS expects a decision from the ACC around year end.

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 is to be amortized over a three-year period, which ends 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.

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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 this year, APS intends to file a supplement to its plan that will include a proposed budget for 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 following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2012 and 2011 (dollars in millions):

	Nine Months Ended September 30,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(52		)	(31		)
Amounts credited to customers	92			121
Ending balance	$	68		$	32

The PSA rate for the PSA year beginning February 1, 2012 is negative $0.0042 per kWh as compared to negative $0.0057 per kWh for the prior year. Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.

Transmission Rates and Transmission Cost Adjustor. In July 2008, the United States Federal Energy Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 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

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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.

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. 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 Southern California Edison’s (“SCE”) 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. On October 1, 2012, APS filed 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 expects a decision from FERC before the end of 2012. We believe these costs 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.

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Regulatory Assets and Liabilities

The detail of regulatory assets is as follows (dollars in millions):

	September 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	939	$	—	$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity	3		91		3		81
Deferred fuel and purchased power — mark-to-market (Note 8)	11		16		43		34
Transmission vegetation management	9		25		9		32
Coal reclamation	8		26		2		35
Palo Verde VIEs (Note 7)	—		37		—		35
Deferred compensation	—		35		—		33
Deferred fuel and purchased power (a)	68		—		28		—
Tax expense of Medicare subsidy	2		17		2		18
Loss on reacquired debt	1		18		1		19
Income taxes — investment tax credit basis adjustment	1		17		—		15
Pension and other postretirement benefits deferral	8		15		—		12
Demand side management (a)	—		—		7		1
Other	11		15		2		14
Total regulatory assets (b)	$	122	$	1,251	$	97	$	1,352

(a) See “Cost Recovery Mechanisms” discussion above.

(b) 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.”

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The detail of regulatory liabilities is as follows (dollars in millions):

	September 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	28	$	328	$	22	$	349
Asset retirement obligations	—		258		—		225
Renewable energy standard (b)	47		—		54		—
Income taxes — change in rates	—		59		—		59
Spent nuclear fuel	9		38		5		44
Deferred gains on utility property	2		13		2		14
Income taxes- deferred investment tax credit	1		35		1		30
Demand side management (b)	8		—		—		—
Other	1		16		4		16
Total regulatory liabilities	$	96	$	747	$	88	$	737

(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.

(b) See “Cost Recovery Mechanisms” discussion above.

4. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date 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 14 for the fair value discussion of plan assets held in our retirement and other benefit plans.

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred as a regulatory asset for future recovery, pursuant to an ACC regulatory order. We deferred pension and other postretirement benefit costs of approximately $3 million for the three months ended September 30, 2011, and approximately $14 million and $9 million for the nine months ended September 30, 2012 and 2011, respectively. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset in July 2012. We amortized approximately $2 million for the three and nine months ended September 30, 2012. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):

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	Pension Benefits												Other Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost - benefits earned during the period	$	16		$	14		$	48		$	43		$	7		$	5		$	20		$	17
Interest cost on benefit obligation	30			31			90			94			12			12			35			35
Expected return on plan assets	(35		)	(33		)	(106		)	(100		)	(12		)	(10		)	(34		)	(31		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	11			7			33			19			5			4			15			11
Net periodic benefit cost	$	22		$	19		$	66		$	57		$	12		$	11		$	36		$	32
Portion of cost charged to expense	$	12		$	7		$	25		$	22		$	7		$	4		$	13		$	12

Contributions

We have contributed $65 million to our pension plan year to date in 2012. The minimum contributions for the pension plan due in 2013 and 2014 under the recently enacted Moving Ahead for Progress in the 21st Century Act (MAP-21) are estimated to be zero and $89 million, respectively. However, we are currently evaluating future expected contributions considering the pension plan’s current funded status, discount rates, interest rates, investment returns and actual contributions made in prior years, among other factors, to determine the level to which future contributions may exceed these new minimum funding levels. The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year.

5. Business Segments

Pinnacle West’s only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and related activities and includes electricity generation, transmission and distribution.

Financial data for the three and nine months ended September 30, 2012 and 2011 and at September 30, 2012 and December 31, 2011 is provided as follows (dollars in millions):

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	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Operating revenues:
Regulated electricity segment	$	1,109		$	1,124	$	2,607		$	2,571
All other	—			1		2			2
Total	$	1,109		$	1,125	$	2,609		$	2,573

Net income attributable to common shareholders:
Regulated electricity segment	$	246		$	246	$	364		$	318
All other (a)	(1		)	9		(5		)	9
Total	$	245		$	255	$	359		$	327

	As of September 30, 2012		As of December 31, 2011
Assets:
Regulated electricity segment	$	13,426	$	13,068
All other (a)	34		43
Total	$	13,460	$	13,111

(a) All other activities relate to APSES, SunCor, Pinnacle West and El Dorado. See Note 13 for discussion of discontinued operations.

6. Income Taxes

The $70 million long-term income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009. This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt. Further clarification of the timing is expected from the IRS within the next twelve months.

Net Income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 7). As a result, there is no income tax expense associated with the VIEs recorded on the Condensed Consolidated Statements of Income.

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009. At this time, a reasonable estimate of the range of possible change in the uncertain tax position cannot be made. However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

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.

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As of September 30, 2012, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2007.

7. 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 2012 to 2015 related to these leases. The lease agreements include fixed rate renewal periods, which gives APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for the three and nine months ended September 30, 2012 of $8 million and $24 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at September 30, 2012 and December 31, 2011 include the following amounts relating to the VIEs (in millions):

	September 30, 2012		December 31, 2011
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation	$	130	$	133
Current maturities of long-term debt	26		31
Palo Verde sale leaseback lessor notes long-term debt excluding current maturities	57		66
Equity — Noncontrolling interests	129		108

Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the United States Nuclear Regulatory Commission (“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 September 30, 2012, APS would have been required to pay the noncontrolling equity participants approximately $142 million and assume $83 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

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For regulatory ratemaking purposes the leases continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

8. 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 Condensed Consolidated 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 accounting hedges. This discontinuation is due to changes in PSA recovery (see Note 3), 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 other comprehensive income (“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 14 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

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significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.

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 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of September 30, 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	8,517	gigawatt hours
Gas	155	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 three and nine months ended September 30, 2012 and 2011 (dollars in thousands):

	Financial Statement	Three Months Ended September 30,						Nine Months Ended September 30,
Commodity Contracts	Location	2012			2011			2012			2011

Loss Recognized in OCI on Derivative Instruments (Effective Portion)	Other comprehensive loss - derivative instruments	$	(119	)	$	(25,457	)	$	(37,513	)	$	(40,792	)
Loss Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion Realized) (a)	Fuel and purchased power	(49,478		)	(59,144		)	(86,993		)	(99,278		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Fuel and purchased power	—			17			117			(147		)

(a) During the nine months ended September 30, 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 third quarter of 2012 and in the 2011 periods related to discontinued cash flow hedges.

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During the next twelve months, we estimate that a net loss of $51 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 three and nine months ended September 30, 2012 and 2011 (dollars in thousands):

	Financial Statement	Three Months Ended September 30,					Nine Months Ended September 30,
Commodity Contracts	Location	2012		2011			2012		2011

Net Gain Recognized in Income	Operating revenues	$	258	$	81		$	19	$	1,085

Net Gain (Loss) Recognized in Income	Fuel and purchased power	12,870		(13,219		)	13,860		(25,138		)
Total		$	13,128	$	(13,138	)	$	13,879	$	(24,053	)

Fair Values of Derivative Instruments in the Condensed Consolidated 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 Condensed Consolidated Balance Sheets. These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of September 30, 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			Other (b)			Total
Current Assets	$	—		$	57,165		$	320	$	—		$	(31,228	)	$	26,257
Investments and Other Assets	—			47,868			—		—			(9,419		)	38,449
Total Assets	—			105,033			320		—			(40,647		)	64,706

Current Liabilities	(1,092		)	(117,325		)	43,480		(13,145		)(a)	31,819			(56,263		)
Deferred Credits and Other	(4,523		)	(103,173		)	17,033		—			9,419			(81,244		)
Total Liabilities	(5,615		)	(220,498		)	60,513		(13,145		)	41,238			(137,507		)
Total	$	(5,615	)	$	(115,465	)	$	60,833	$	(13,145	)	$	591		$	(72,801	)

(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.

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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			Other (b)			Total
Current Assets	$	7,287		$	76,162		$	1,630	$	—		$	(54,815	)	$	30,264
Investments and Other Assets	3,804			58,273			—		—			(12,755		)	49,322
Total Assets	11,091			134,435			1,630		—			(67,570		)	79,586

Current Liabilities	(82,195		)	(124,028		)	107,228		(11,145		)(a)	56,172			(53,968		)
Deferred Credits and Other	(68,137		)	(92,880		)	65,768		—			12,754			(82,495		)
Total Liabilities	(150,332		)	(216,908		)	172,996		(11,145		)	68,926			(136,463		)
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 82% of Pinnacle West’s $65 million of risk management assets as of September 30, 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 consolidated 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).

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The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2012 (dollars in millions):

	September 30, 2012
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	226
Cash Collateral Posted	60
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	104

(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.

9. Changes in Equity

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2012 and 2011 (dollars in thousands):

	Three Months Ended September 30, 2012								Three Months Ended September 30, 2011
	Common Shareholders			Noncontrolling Interests		Total			Common Shareholders			Noncontrolling Interests			Total

Beginning balance, July 1	$	3,778,035		$	121,302	$	3,899,337		$	3,613,705		$	101,905		$	3,715,610

Net income	244,823			8,040		252,863			255,359			7,426			262,785
Other comprehensive income	30,843			—		30,843			21,131			—			21,131
Total comprehensive income	275,666			8,040		283,706			276,490			7,426			283,916

Issuance of capital stock	2,365			—		2,365			3,789			—			3,789
Reissuance (purchase) of treasury stock - net	(82		)	—		(82		)	537			—			537
Other (primarily stock compensation)	258			—		258			(436		)	—			(436		)
Net capital activities by noncontrolling interests	—			—		—			—			(421		)	(421		)
Ending balance, September 30	$	4,056,242		$	129,342	$	4,185,584		$	3,894,085		$	108,910		$	4,002,995

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	Nine Months Ended September 30, 2012									Nine Months Ended September 30, 2011
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total

Beginning balance, January 1	$	3,821,850		$	108,736		$	3,930,586		$	3,683,327		$	91,899		$	3,775,226

Net income	358,911			23,582			382,493			326,909			20,041			346,950
Other comprehensive income	32,688			—			32,688			38,224			—			38,224
Total comprehensive income	391,599			23,582			415,181			365,133			20,041			385,174

Issuance of capital stock	7,590			—			7,590			20,854			—			20,854
Reissuance (purchase) of treasury stock - net	3,277			—			3,277			(2,993		)	—			(2,993		)
Other (primarily stock compensation)	4,270			—			4,270			(606		)	—			(606		)
Dividends on common stock	(172,344		)	—			(172,344		)	(171,630		)	—			(171,630		)
Net capital activities by noncontrolling interests	—			(2,976		)	(2,976		)	—			(3,030		)	(3,030		)
Ending balance, September 30	$	4,056,242		$	129,342		$	4,185,584		$	3,894,085		$	108,910		$	4,002,995

10. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

APS currently estimates it will incur $122 million (in 2010 dollars) 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 September 30, 2012, APS had a regulatory liability of $47 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance

The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, 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 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 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

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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 and exclusions.

Contractual Obligations

As of September 30, 2012, our contractual obligations for renewable energy credits increased approximately $215 million from December 31, 2011 as discussed in the 2011 Form 10-K. As of September 30, 2012, the updated contractual obligations related to our renewable energy credits are as follows (dollars in millions):

Year	2012		2013		2014		2015		2016		Thereafter		Total
Renewable Energy Credits	$	46	$	39	$	44	$	44	$	44	$	573	$	790

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. FERC rejected a market-wide remedy approach and instead directed that buyers seeking refunds must demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.

The first phase of the hearing is currently expected to commence in April 2013. Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

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, the United States Environmental Protection Agency (“EPA”) advised APS that the 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.

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APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with the 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 we cannot accurately estimate our total expenditures.

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 Ninth Circuit Court of Appeals in November 2009. On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.

On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants. However, the Court left open the issue of whether such claims may be available under state law. 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. 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 kilovolt (“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

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regional outages was restored by approximately 3:25AM on September 9. APS has an internal review of the September 8 events underway.

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 cannot predict the timing, results or potential impacts of any further inquiries into 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.

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 Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s New Source Performance Standards (“NSPS”) program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD 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. APS believes the claims in this matter are without merit and will vigorously defend against them. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2012, approximately $76 million of letters of credit were outstanding to support existing variable interest rate pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal of and interest on 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 obligations to certain equity participants in the Palo Verde sale leaseback transactions (see Note 7 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire in 2015 and totaled approximately $42 million at September 30, 2012. Additionally, APS has issued letters of credit to support collateral obligations under certain natural gas tolling contracts and hedge contracts entered into with third parties. At September 30, 2012, $65 million of such letters of credit were outstanding. Two of these letters of credit will expire in 2013 and one will expire in 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

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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.

11. Other Income and Other Expense

The following table provides detail of other income and other expense for the three and nine months ended September 30, 2012 and 2011 (dollars in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Other income:
Interest income	$	307		$	429		$	1,018		$	1,364
Investment gains — net	—			—			—			1,249
Miscellaneous	113			12			339			17
Total other income	$	420		$	441		$	1,357		$	2,630

Other expense:
Non-operating costs	$	(1,645	)	$	(1,807	)	$	(5,885	)	$	(4,925	)
Investment losses — net	(2,254		)	(57		)	(2,366		)	—
Miscellaneous	(1,797		)	(1,188		)	(4,182		)	(2,996		)
Total other expense	$	(5,696	)	$	(3,052	)	$	(12,433	)	$	(7,921	)

12. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2012 and 2011:

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012			2011
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	2.23	$	2.25	$	3.29		$	2.90
Income (loss) from discontinued operations	—		0.09		(0.01		)	0.10
Earnings per share — basic	$	2.23	$	2.34	$	3.28		$	3.00

Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	2.21	$	2.24	$	3.26		$	2.88
Income (loss) from discontinued operations	—		0.08		(0.01		)	0.10
Earnings per share — diluted	$	2.21	$	2.32	$	3.25		$	2.98

Performance shares (which are contingently issuable) and restricted stock unit awards increased average diluted common shares outstanding by approximately 1,100,000 shares and 733,000 shares for the three months ended September 30, 2012 and 2011, respectively, and by approximately 971,000 shares and 680,000 shares for the nine months ended September 30, 2012 and 2011, respectively.

13. Discontinued Operations

SunCor — In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations, or cash flows. All activity for the income statement for the three and nine months ended September 30, 2012 and prior comparative period income statement amounts are included in discontinued operations.

APSES — On August 19, 2011, Pinnacle West sold its investment in APSES. The sale resulted in an after-tax gain from discontinued operations of approximately $10 million. Prior-period income statement amounts related to the sale of APSES and the associated revenues and costs are reflected in discontinued operations.

The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2012 and 2011 (dollars in millions):

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	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012			2011
Revenue:
SunCor	$	—	$	1		$	—		$	4
APSES	—		11			—			36
Total revenue	$	—	$	12		$	—		$	40

Income (loss) before taxes:
SunCor	$	—	$	(2	)	$	(3	)	$	(2	)
APSES	—		18			—			20
Total income (loss) before taxes	$	—	$	16		$	(3	)	$	18

Income (loss) after taxes:
SunCor	$	—	$	(1	)	$	(2	)	$	(1	)
APSES	—		10			—			12
Total income (loss) after taxes	$	—	$	9		$	(2	)	$	11

14. 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 the funds’ net asset values (“NAV”).

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

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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 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 in the 2011 Form 10-K 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 market 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 broker quotes are not available, the primary valuation technique used to calculate 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

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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 NAV, which is 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 assess these valuations and verify that pricing can be supported by actual recent market transactions. Additionally, we obtain and review independent audit reports on the trustee’s operating controls and valuation processes. See Note 15 for additional discussion about our nuclear decommissioning trust.

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Fair Value Tables

The following table presents the fair value at September 30, 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 September 30, 2012
Assets
Nuclear decommissioning trust:
U.S. commingled equity funds	$	—	$	204		$	—		$	—		$	204
Fixed income securities:
U.S. Treasury	93		—			—			—			93
Cash and cash equivalent funds	—		13			—			(3		)(b)	10
Corporate debt	—		79			—			—			79
Mortgage-backed securities	—		83			—			—			83
Municipality bonds	—		86			—			—			86
Other	—		12			—			—			12
Subtotal nuclear decommissioning trust	93		477			—			(3		)	567
Cash equivalents	46		—			—			—			46
Risk management activities — derivative instruments:
Commodity contracts	—		45			60			(40		)(c)	65
Total	$	139	$	522		$	60		$	(43	)	$	678

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(116	)	$	(110	)	$	88	(c)	$	(138	)

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

(b) Represents nuclear decommissioning trust net pending securities sales and purchases.

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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
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		)(b)	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
Risk management activities — derivative instruments:
Commodity contracts	—		70			74			(64		)(c)	80
Total	$	69	$	516		$	74		$	(65	)	$	594

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(241	)	$	(125	)	$	229	(c)	$	(137	)

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

(b) Represents nuclear decommissioning trust net pending securities sales and purchases.

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long term nature of the quote 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 3).

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position generally if the price of the underlying commodity increases we would expect the net fair value

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of contracts related to that commodity to increase, and 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 Level 3 instruments.

Risk Management Activities — Derivative Instruments: Commodity Contracts

	September 30, 2012 Fair Value (millions)				Valuation	Significant
Commodity Contracts	Assets		Liabilities		Technique	Unobservable Input	Range
Electricity:
Forward Contracts (a)	$	57	$	81	Discounted cash flows	Electricity forward price (per MWh)(b)	$22.00 - $63.71

Option Contracts	—		27		Option model	Electricity forward price (per MWh)(b)	$30.50 - $92.37

						Natural gas forward price (per mmbtu)(c)	$2.98 - $4.38
						Implied electricity price volatilities	16% - 57%
						Implied natural gas price volatilities	17% - 42%
Natural Gas:
Forward Contracts (a)	3		2		Discounted cash flows	Natural gas forward price (per mmbtu)(c)	$2.98 - $4.61
Total	$	60	$	110

(a) Includes swaps and physical and financial contracts.

(b) MWh means megawatt-hour, one million watts per hour.

The following table shows the changes in fair value for our risk management activities assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2012 and 2011 (dollars in millions):

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	Three Months Ended September 30,						Nine Months Ended September 30,
Commodity Contracts	2012			2011			2012			2011
Net derivative balance at beginning of period	$	(45	)	$	(47	)	$	(51	)	$	(38	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			1			2			2
Included in OCI	—			2			(2		)	1
Deferred as a regulatory asset or liability	(3		)	2			4			(4		)
Settlements	(1		)	6			(1		)	10
Transfers into Level 3 from Level 2	(4		)	—			(2		)	(4		)
Transfers from Level 3 into Level 2	3			(2		)	—			(5		)
Net derivative balance at end of period	$	(50	)	$	(38	)	$	(50	)	$	(38	)

Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—		$	—		$	1

Amounts included in earnings are recorded in either regulated electricity segment revenue or regulated electricity segment 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 transfers in or out of Level 1 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.

Nonrecurring Fair Value Measurements

For the periods ended September 30, 2012 and 2011, we had no assets or liabilities measured at fair value on a nonrecurring basis.

Financial Instruments Not Carried at Fair Value

The carrying value of our net accounts receivable, accounts payable and any 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 2.

15. Nuclear Decommissioning Trust

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 domestic 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 Condensed Consolidated Balance Sheets. See Note 14 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

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with the regulatory treatment for decommissioning trust funds, we have recorded deferred realized and unrealized gains and losses on investment securities in other regulatory liabilities or assets. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2012 and December 31, 2011 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
September 30, 2012
Equity securities	$	204		$	68	$	—
Fixed income securities	366			27		—
Net payables (a)	(3		)	—		—
Total	$	567		$	95	$	—

(a) Net payables relate to pending securities sales and purchases.

	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 realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Realized gains	$	1		$	3		$	5		$	6
Realized losses	(1		)	(1		)	(3		)	(4		)
Proceeds from the sale of securities (a)	84			106			295			406

(a) Proceeds are reinvested in the trust.

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The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2012 is as follows (dollars in millions):

	Fair Value
Less than one year	$	22
1 year - 5 years	94
5 years - 10 years	103
Greater than 10 years	147
Total	$	366

16. New Accounting Standards

During the first quarter of 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 14), but did not impact our financial statement results.

During the first quarter of 2012, we also adopted amended guidance on the presentation of comprehensive income. As a result of the amended guidance, we have changed our format for presenting comprehensive income. Previously, components of comprehensive income were presented within changes of equity. Due to the amended guidance, we now present comprehensive income in a new financial statement titled “Condensed Consolidated Statements of Comprehensive Income”. The adoption of this guidance changed our format for presenting comprehensive income, but did not impact our financial statement results.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended September 30,
	2012			2011

ELECTRIC OPERATING REVENUES	$	1,108,623		$	1,124,057

OPERATING EXPENSES
Fuel and purchased power	302,894			337,897
Operations and maintenance	218,403			207,967
Depreciation and amortization	100,329			106,326
Income taxes	153,797			145,230
Taxes other than income taxes	36,255			33,854
Total	811,678			831,274
OPERATING INCOME	296,945			292,783

OTHER INCOME (DEDUCTIONS)
Income taxes	3,170			9,422
Allowance for equity funds used during construction	5,708			7,377
Other income (Note S-2)	815			617
Other expense (Note S-2)	(3,352		)	(3,045		)
Total	6,341			14,371

INTEREST EXPENSE
Interest on long-term debt	48,841			56,314
Interest on short-term borrowings	1,334			2,846
Debt discount, premium and expense	1,070			1,164
Allowance for borrowed funds used during construction	(3,830		)	(6,938		)
Total	47,415			53,386

NET INCOME	255,871			253,768

Less: Net income attributable to noncontrolling interests (Note 7)	8,040			7,435

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	247,831		$	246,333

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended September 30,
	2012			2011

NET INCOME	$	255,871		$	253,768

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $47 and $10,057	(72		)	(15,400		)
Reclassification of net realized loss, net of tax benefit of $19,547 and $23,366	29,931			35,778
Pension and other postretirement benefits activity, net of tax expense of $568 and $431	869			660
Total other comprehensive income	30,728			21,038

COMPREHENSIVE INCOME	286,599			274,806
Less: Comprehensive income attributable to noncontrolling interests	8,040			7,435

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	278,559		$	267,371

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Nine Months Ended September 30,
	2012			2011

ELECTRIC OPERATING REVENUES	$	2,606,458		$	2,570,737

OPERATING EXPENSES
Fuel and purchased power	783,926			793,952
Operations and maintenance	640,596			669,170
Depreciation and amortization	300,997			319,477
Income taxes	233,679			193,485
Taxes other than income taxes	119,499			110,892
Total	2,078,697			2,086,976
OPERATING INCOME	527,761			483,761

OTHER INCOME (DEDUCTIONS)
Income taxes	6,906			9,647
Allowance for equity funds used during construction	15,639			18,697
Other income (Note S-2)	2,343			3,828
Other expense (Note S-2)	(11,969		)	(11,288		)
Total	12,919			20,884

INTEREST EXPENSE
Interest on long-term debt	150,416			165,805
Interest on short-term borrowings	5,283			7,675
Debt discount, premium and expense	3,182			3,485
Allowance for borrowed funds used during construction	(10,428		)	(14,371		)
Total	148,453			162,594

NET INCOME	392,227			342,051

Less: Net income attributable to noncontrolling interests (Note 7)	23,573			20,089

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	368,654		$	321,962

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

	Nine Months Ended September 30,
	2012			2011

NET INCOME	$	392,227		$	342,051

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit of $14,820 and $16,116	(22,693		)	(24,676		)
Reclassification of net realized loss, net of tax benefit of $34,367 and $39,221	52,625			60,056
Pension and other postretirement benefits activity, net of tax expense of $1,409 and $1,794	2,158			2,746
Total other comprehensive income	32,090			38,126

COMPREHENSIVE INCOME	424,317			380,177
Less: Comprehensive income attributable to noncontrolling interests	23,573			20,089

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	400,744		$	360,088

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	September 30,			December 31,
	2012			2011
ASSETS

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	14,112,149		$	13,750,105
Accumulated depreciation and amortization	(4,898,234		)	(4,706,462		)
Net	9,213,915			9,043,643

Construction work in progress	587,826			496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	129,962			132,864
Intangible assets, net of accumulated amortization	152,510			170,416
Nuclear fuel, net of accumulated amortization	139,873			118,098
Total property, plant and equipment	10,224,086			9,961,766

INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)	566,960			513,733
Assets from risk management activities (Note 8)	38,449			49,322
Other assets	31,071			30,551
Total investments and other assets	636,480			593,606

CURRENT ASSETS
Cash and cash equivalents	53,774			19,873
Customer and other receivables	363,681			280,100
Accrued unbilled revenues	136,425			125,239
Allowance for doubtful accounts	(4,297		)	(3,748		)
Materials and supplies (at average cost)	219,026			204,387
Fossil fuel (at average cost)	31,234			22,000
Deferred fuel and purchased power regulatory asset (Note 3)	67,910			27,549
Other regulatory assets (Note 3)	53,960			69,072
Deferred income taxes	44,115			111,503
Income tax receivable	3,644			2,869
Assets from risk management activities (Note 8)	26,257			30,264
Other current assets	28,055			26,486
Total current assets	1,023,784			915,594

DEFERRED DEBITS
Regulatory assets (Note 3)	1,250,792			1,352,079
Income tax receivable (Note 6)	70,348			69,028
Unamortized debt issue costs	23,410			21,181
Other	121,785			118,983
Total deferred debits	1,466,335			1,561,271

TOTAL ASSETS	$	13,350,685		$	13,032,237

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

	September 30,			December 31,
	2012			2011
LIABILITIES AND EQUITY

CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,716,994			1,510,740
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(36,728		)	(38,886		)
Derivative instruments	(56,773		)	(86,705		)
Total shareholder equity	4,181,351			3,943,007
Noncontrolling interests (Note 7)	129,342			108,399
Total equity (Note S-1)	4,310,693			4,051,406
Long-term debt less current maturities	3,156,531			2,828,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	57,420			65,547
Total capitalization	7,524,644			6,945,460

CURRENT LIABILITIES
Current maturities of long-term debt	90,360			477,435
Accounts payable	223,185			322,047
Accrued taxes (Note 6)	176,764			113,930
Accrued interest	50,545			54,611
Customer deposits	76,853			72,176
Liabilities from risk management activities (Note 8)	56,263			53,968
Regulatory liabilities (Note 3)	96,362			88,362
Other current liabilities	131,974			140,185
Total current liabilities	902,306			1,322,714

DEFERRED CREDITS AND OTHER
Deferred income taxes	2,134,571			1,952,608
Regulatory liabilities (Note 3)	746,754			737,332
Liability for asset retirements	294,524			279,643
Liabilities for pension and other postretirement benefits (Note 4)	1,162,964			1,222,542
Liabilities from risk management activities (Note 8)	81,244			82,495
Customer advances	105,941			116,805
Coal mine reclamation	118,601			117,896
Unrecognized tax benefits (Note 6)	69,589			72,073
Other	209,547			182,669
Total deferred credits and other	4,923,735			4,764,063

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

TOTAL LIABILITIES AND EQUITY	$	13,350,685		$	13,032,237

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	392,227		$	342,051
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	360,499			369,999
Deferred fuel and purchased power	51,533			30,965
Deferred fuel and purchased power amortization	(91,894		)	(121,018		)
Allowance for equity funds used during construction	(15,639		)	(18,697		)
Deferred income taxes	231,225			135,789
Change in derivative instruments fair value	(943		)	1,861
Changes in current assets and liabilities:
Customer and other receivables	(79,152		)	(50,147		)
Accrued unbilled revenues	(11,186		)	(80,877		)
Materials, supplies and fossil fuel	(23,873		)	(25,532		)
Other current assets	(11,221		)	(3,836		)
Accounts payable	(72,802		)	42,257
Accrued taxes	62,834			86,032
Other current liabilities	112			18,931
Change in margin and collateral accounts – assets	1,980			33,591
Change in margin and collateral accounts – liabilities	114,579			85,785
Change in other long-term assets	(18,505		)	(10,198		)
Change in other long-term liabilities	32,897			96,140
Net cash flow provided by operating activities	922,671			933,096
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(670,684		)	(637,181		)
Contributions in aid of construction	41,451			36,351
Allowance for borrowed funds used during construction	(10,428		)	(14,371		)
Proceeds from sale of life insurance policies	—			44,183
Proceeds from nuclear decommissioning trust sales	295,126			405,637
Investment in nuclear decommissioning trust	(308,063		)	(417,957		)
Other	(520		)	(2,346		)
Net cash flow used for investing activities	(653,118		)	(585,684		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	351,081			295,353
Repayment of long-term debt	(421,703		)	(13,457		)
Dividends paid on common stock	(162,400		)	(171,600		)
Noncontrolling interests	(2,630		)	(2,610		)
Net cash flow provided by (used for) financing activities	(235,652		)	107,686
NET INCREASE IN CASH AND CASH EQUIVALENTS	33,901			455,098
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	19,873			99,937
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	53,774		$	555,035
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid	$	—		$	7,493
Interest, net of amounts capitalized	$	149,338		$	158,011

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.

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Certain notes to APS’s Condensed Consolidated Financial Statements are combined with the Notes to Pinnacle West’s Condensed Consolidated Financial Statements. Listed below are the Condensed Consolidated Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS’s Condensed Consolidated Financial Statements. In addition, listed below are the Supplemental Notes that are required disclosures for APS and should be read in conjunction with Pinnacle West’s Condensed Consolidated Notes.

	Condensed Consolidated Note Reference	APS’s Supplemental Note Reference
Consolidation and Nature of Operations	Note 1	—
Long-Term Debt and Liquidity Matters	Note 2	—
Regulatory Matters	Note 3	—
Retirement Plans and Other Benefits	Note 4	—
Business Segments	Note 5	—
Income Taxes	Note 6	—
Palo Verde Sale Leaseback Variable Interest Entities	Note 7	—
Derivative Accounting	Note 8	—
Changes in Equity	Note 9	Note S-1
Commitments and Contingencies	Note 10	—
Other Income and Other Expense	Note 11	Note S-2
Earnings Per Share	Note 12	—
Discontinued Operations	Note 13	—
Fair Value Measurements	Note 14	—
Nuclear Decommissioning Trust	Note 15	—
New Accounting Standards	Note 16	—

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-1. Changes in Equity

The following tables show APS’s changes in shareholder equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2012 and 2011 (dollars in thousands):

	Three Months Ended September 30, 2012						Three Months Ended September 30, 2011
	Shareholder Equity		Noncontrolling Interests		Total		Shareholder Equity		Noncontrolling Interests		Total

Beginning balance, July 1	$	3,902,791	$	121,302	$	4,024,093	$	3,746,067	$	101,128	$	3,847,195

Net income	247,831		8,040		255,871		246,333		7,435		253,768
OCI	30,728		—		30,728		21,038		—		21,038
Total comprehensive income	278,559		8,040		286,599		267,371		7,435		274,806

Other	1		—		1		3		1		4
Ending balance, September 30	$	4,181,351	$	129,342	$	4,310,693	$	4,013,441	$	108,564	$	4,122,005

	Nine Months Ended September 30, 2012									Nine Months Ended September 30, 2011
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total

Beginning balance, January 1	$	3,943,007		$	108,399		$	4,051,406		$	3,824,953		$	91,084		$	3,916,037

Net income	368,654			23,573			392,227			321,962			20,089			342,051
OCI	32,090			—			32,090			38,126			—			38,126
Total comprehensive income	400,744			23,573			424,317			360,088			20,089			380,177

Dividends on common stock	(162,400		)	—			(162,400		)	(171,600		)	—			(171,600		)
Net capital activities by noncontrolling interests	—			(2,630		)	(2,630		)	—			(2,610		)	(2,610		)
Other	—			—			—			—			1			1
Ending balance, September 30	$	4,181,351		$	129,342		$	4,310,693		$	4,013,441		$	108,564		$	4,122,005

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-2. Other Income and Other Expense

The following table provides detail of APS’s other income and other expense for the three and nine months ended September 30, 2012 and 2011 (dollars in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Other income:
Interest income	$	61		$	93		$	244		$	312
Investment gains – net	—			—			—			1,418
Miscellaneous	754			524			2,099			2,098
Total other income	$	815		$	617		$	2,343		$	3,828

Other expense:
Non-operating costs (a)	$	(2,007	)	$	(1,922	)	$	(6,690	)	$	(6,136	)
Asset dispositions	(248		)	(215		)	(666		)	(1,038		)
Miscellaneous	(1,097		)	(908		)	(4,613		)	(4,114		)
Total other expense	$	(3,352	)	$	(3,045	)	$	(11,969	)	$	(11,288	)

(a) As defined by the FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery).

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ITEM 2

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Notes that appear in Item 1 of this report. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Part I, Item 1A of the 2011 Form 10-K.

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most 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. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.

Areas of Business Focus

Operational Performance, Reliability and Recent Developments.

Nuclear. APS operates and is a joint owner of the Palo Verde Nuclear Generating Station. APS management is working closely with regulators and others in the nuclear industry to analyze the lessons learned and address any rulemaking or improvements resulting from the March 2011 events impacting the Fukushima Daiichi Nuclear Power Station in Japan.

Coal and Related Environmental Matters. APS is a joint owner of three coal-fired power plants and acts as operating agent for two of the plants. APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning greenhouse gas emissions. Concern over climate change and other emission-related issues could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades for these plants. APS is closely monitoring its long-range capital management plans, understanding that any resulting regulation and legislation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to fund any such equipment upgrades.

SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the plant. On November 8, 2010, APS and SCE entered into an asset purchase agreement (“APA”), providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The purchase price is $294 million, subject to certain adjustments. Completion of the purchase by APS is subject to the receipt of approvals by the ACC, the California Public Utility Commission (“CPUC”) and the FERC. On March 29, 2012, the CPUC issued an order approving the sale. On April 18, 2012, the ACC voted to allow APS to move forward with the purchase, with a condition that the transaction may not close prior to December 1, 2012. The APA provides that the purchase price will be reduced by $7.5 million for each month between October 1, 2012 and the closing date. The ACC reserved the right to review the prudence of the transaction for cost recovery purposes in a future proceeding if the purchase closes. The ACC also

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authorized an accounting deferral of certain costs associated with the purchase until any such cost recovery proceeding concludes. The FERC application seeking authorization for the transaction was filed in May 2012, and a decision is expected before the end of November 2012. Closing is also conditioned on the negotiation and execution of a new coal supply contract on terms reasonably acceptable to APS. Negotiations concerning the coal supply contract are continuing.

APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also requires the approval of the U.S. Department of the Interior (“DOI”), as does a related federal rights-of-way grant which the Four Corners participants will pursue. A federal environmental review is underway as part of the DOI review process.

APS has announced that, if APS’s purchase of SCE’s interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2 and 3 at the plant. APS owns 100% of Units 1-3. These events will change the plant’s overall generating capacity from 2,100 MW to 1,540 MW and APS’s entitlement from the plant from 791 MW to 970 MW. When the ACC approved APS moving forward with the purchase of Units 4 and 5, it also approved the recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3. The Settlement Agreement in APS’s most recent retail rate case allows APS to seek a rate adjustment to reflect the Four Corners transaction should the transaction close (see Note 3).

APS cannot predict whether, and if so, when, all of the conditions necessary to consummate the purchase of SCE’s interest will be met such that closing can occur.

Transmission and Delivery. APS’s 2012 Ten-Year Transmission Plan filed with the ACC in January 2012 projects that it will invest approximately $550 million in new transmission projects (115 kV and above) over the next ten years, adding 269 miles of new lines. The first three years of these additions are included in the capital expenditures table presented in the “Liquidity and Capital Resources” section below along with other transmission costs for upgrades and replacements. APS is working closely with regulators to identify and plan for transmission needs resulting from the current focus on renewable energy. APS is also working to establish and expand smart grid technology throughout its service territory designed to provide long-term benefits both to APS and its customers. APS is piloting and deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations and the number of customers that experience outages, and facilitate cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

Renewable Energy. The ACC approved the RES in 2006. The renewable energy requirement is 3.5% of retail electric sales in 2012 and increases annually until it reaches 15% in 2025. In the settlement agreement related to the 2008 retail rate case, APS agreed to exceed the RES standards, committing to 1,700 gigawatt-hours (“GWh”) of new renewable resources to be in service by year-end 2015 in addition to its 2008 renewable resource commitments. Taken together, APS’s commitment is estimated to be 3,400 GWh, or approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year. A component of the RES is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

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On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $92.8 million to $102.4 million. The budget range stems from options related to distributed energy. The first option involves no new incentives for distributed energy. The second option would offer incentives for residential photovoltaic distributed energy beginning where 2012 incentives end and stepping down gradually based upon market participation. APS’s filing also proposed a system of establishing compliance with distributed energy requirements that depends upon tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. Further, APS described its Community Solar Program, a utility-owned 25 MW program that will be split into 3 to 7 separate projects throughout communities in APS’s service territory. APS expects a decision from the ACC around year end.

The following table summarizes APS’s renewable energy sources in operation and under development as of November 2, 2012. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar	58	71

Purchased Power Agreements:
Solar	15	295
Wind	289	—
Geothermal	10	—
Biomass	14	—
Biogas	6	—
Total Purchased Power Agreements	334	295

Total Distributed Energy: Solar	189	139

Total Renewable Portfolio	581	505

Demand Side Management. In recent years, Arizona regulators have placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. In December 2009, the ACC initiated an Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. This ambitious standard became effective on January 1, 2011 and will likely impact Arizona’s future energy resource needs. 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.

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Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain its financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. On June 1, 2011, APS filed a rate case with the ACC. APS and other parties to the retail rate case subsequently entered into a Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case. On May 15, 2012, the ACC approved the Settlement Agreement without material modifications. The Settlement Agreement demonstrates cooperation among APS, the ACC staff, the Residential Utility Consumer Office and other intervenors to the rate case, and establishes a future rate case filing plan that allows APS the opportunity to help shape Arizona’s energy future outside of continual rate cases. See Note 3 for details regarding the Settlement Agreement terms and for information on APS’s FERC rates.

APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its demand side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 3.

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. On October 1, 2012, APS filed 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 expects a decision from FERC before the end of 2012. We believe these costs 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.

Financial Strength and Flexibility. Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company. Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock. In January 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. APS used the net proceeds from the sale of the notes along with other funds to pay at maturity its $375 million aggregate principal amount of 6.50% unsecured senior notes that matured on March 1, 2012.

Other Subsidiaries. The operations of El Dorado are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years. As a result of the continuing distressed conditions in the real estate markets, during 2009 our other first-tier subsidiary, SunCor, undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to

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complete an orderly liquidation of its business. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations or cash flows.

Key Financial Drivers

In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.

Electric Operating Revenues. For the years 2009 through 2011, retail electric revenues comprised approximately 93% of our total electric operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. Off-system sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’s retail customers through the PSA. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth. Retail customer growth in APS’s service territory for the nine-month period ended September 30, 2012 was 1% compared with the comparable prior-year period. For the three years 2009 through 2011, APS’s customer growth averaged 0.6% per year. We currently expect annual customer growth to average about 2.0% for 2012 through 2015 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. Retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for the nine-month period ended September 30, 2012 decreased 0.2% compared with the comparable prior-year period, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, partially offset by mildly improving economic conditions. For the three years 2009 through 2011, APS experienced annual declines in retail electricity sales averaging 0.8%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kilowatt-hours will remain flat on average during 2012 through 2015, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. A failure of the Arizona economy to continue to improve could further impact these estimates.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns, impacts of energy efficiency programs and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.

Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

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Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Condensed Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs, renewable energy and demand side management related expenses (which are offset by the same amount of regulated electricity segment operating revenues) and other factors. In the settlement agreement related to the 2008 retail rate case, APS committed to operational expense reductions from 2010 through 2014 and received approval to defer certain pension and other postretirement benefit cost increases incurred in 2011 and 2012, which totaled $25 million, as a regulatory asset, until the most recent general retail rate case decision became effective on July 1, 2012. In July 2012, we began amortizing the regulatory asset over a 36-month period.

Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditures” below for information regarding the planned additions to our facilities. As a result of the twenty-year extensions of the operating licenses for each of the Palo Verde units granted by the NRC in 2011, we decreased our pretax depreciation expense related to Palo Verde by approximately $34 million per year starting on January 1, 2012.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 9.6% of the assessed value for 2012 and 9.0% for 2011. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities. (See Note 3 for property tax deferrals contained in the Settlement Agreement).

Income Taxes. Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities.

Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 2). The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed in commercial operation.

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RESULTS OF OPERATIONS

Pinnacle West’s only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.

Operating Results — Three-month period ended September 30, 2012 compared with three-month period ended September 30, 2011

Our consolidated net income attributable to common shareholders for the three months ended September 30, 2012 was $245 million, compared with net income of $255 million for the comparable prior-year period. Income from discontinued operations decreased $9 million primarily due to absence of the 2011 gain on the sale of our investment in APSES.

The regulated electricity segment results of $246 million were comparable to the prior-year period. The results reflect increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3), higher retail transmission revenues, lower net interest charges due to lower debt balances and lower interest rates in the current period, and lower depreciation and amortization due to 20-year Palo Verde license extensions received in 2011. These positive factors were offset by the effects of milder weather as compared with the prior-year period and an increase in operations and maintenance expenses.

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The following table presents net income attributable to common shareholders by business segment compared with the prior-year period:

	Three Months Ended September 30,
	2012			2011			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	806		$	786		$	20
Operations and maintenance	(221		)	(210		)	(11		)
Depreciation and amortization	(100		)	(106		)	6
Taxes other than income taxes	(37		)	(34		)	(3		)
Other income (expenses), net	2			4			(2		)
Interest charges, net of allowance for borrowed funds used during construction	(48		)	(55		)	7
Income taxes	(148		)	(132		)	(16		)
Less income related to noncontrolling interests (Note 7)	(8		)	(7		)	(1		)
Regulated electricity segment net income	246			246			—

All other	(1		)	—			(1		)
Income from Continuing Operations Attributable to Common Shareholders	245			246			(1		)
Income from Discontinued Operations Attributable to Common Shareholders (a)	—			9			(9		)

Net Income Attributable to Common Shareholders	$	245		$	255		$	(10	)

(a) Includes activities related to APSES and SunCor.

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Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $20 million higher for the three months ended September 30, 2012 compared with the prior-year period. The following table summarizes the major components of this change:

	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)

Impacts of retail regulatory settlement effective July 1, 2012 (a)	$	39		$	—		$	39
Higher retail transmission revenues	16			—			16
Effects of weather	(44		)	(12		)	(32		)
Lower fuel and purchased power costs, net of related deferrals and off-system sales	(18		)	(17		)	(1		)
Miscellaneous items, net	(8		)	(6		)	(2		)
Total	$	(15	)	$	(35	)	$	20

(a) Includes a retail non-fuel base rate increase which is offset by other rate changes below (see Note 3).

Operations and maintenance Operations and maintenance expenses increased $11 million for the three months ended September 30, 2012 compared with the prior-year period primarily because of:

· An increase of $7 million related to employee benefit costs, including $3 million of higher stock compensation costs resulting from an improved company stock price and estimated performance results;

· An increase of $5 million related to amortization of pension and other postretirement benefit costs in 2012 compared with deferral of such costs in 2011;

· An increase of $4 million in fossil generation costs as a result of more planned maintenance being completed in the current year quarter than in the same quarter a year ago;

· A decrease of $8 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues; and

· An increase of $3 million due to other miscellaneous factors.

Depreciation and amortization Depreciation and amortization expenses were $6 million lower for the three months ended September 30, 2012 compared with the prior-year period primarily

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due to impacts of the Palo Verde operating license extensions, partially offset by increased plant in service.

Interest charges, net of allowance for borrowed funds used during construction Interest charges, net of allowance for borrowed funds used during construction, decreased $7 million for the three months ended September 30, 2012 compared with the prior-year period primarily because of lower debt balances in the current period.

Income taxes Income taxes were $16 million higher for the three months ended September 30, 2012 compared with the prior-year period primarily due to higher pretax income in the current period and a lower effective tax rate in 2011.

Discontinued Operations

Income from discontinued operations decreased $9 million due to absence of a gain of approximately $10 million after income taxes related to the sale of our investment in APSES in 2011.

Operating Results — Nine-month period ended September 30, 2012 compared with nine-month period ended September 30, 2011

Our consolidated net income attributable to common shareholders for the nine months ended September 30, 2012 was $359 million, compared with net income of $327 million for the comparable prior-year period. The results reflect an increase of approximately $47 million for the regulated electricity segment primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3), higher retail transmission revenues, lower depreciation and amortization due to 20-year Palo Verde license extensions received in 2011, and lower net interest charges due to lower debt balances and lower interest rates in the current year period.

The $12 million decrease in discontinued operations is primarily due to the 2011 gain on sale of our investment in APSES.

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The following table presents net income attributable to common shareholders by business segment compared with the prior-year period:

	Nine Months Ended September 30,
	2012			2011			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses (a)	$	1,823		$	1,777		$	46
Operations and maintenance (a)	(648		)	(676		)	28
Depreciation and amortization	(301		)	(320		)	19
Taxes other than income taxes	(120		)	(112		)	(8		)
Other income (expenses), net	7			14			(7		)
Interest charges, net of allowance for borrowed funds used during construction	(152		)	(169		)	17
Income taxes	(221		)	(177		)	(44		)
Less income related to noncontrolling interests (Note 7)	(24		)	(20		)	(4		)
Regulated electricity segment net income	364			317			47

All other	(4		)	(1		)	(3		)
Income from Continuing Operations Attributable to Common Shareholders	360			316			44

Income (Loss) from Discontinued Operations Attributable to Common Shareholders (b)	(1		)	11			(12		)

Net Income Attributable to Common Shareholders	$	359		$	327		$	32

(a) Includes effects of 2011 settlement of certain transmission right-of-way costs, which did not affect net income, but increased both electric operating revenues and operations and maintenance expenses by $28 million. Costs related to the settlement were offset by related revenues from SCE, which leases the related transmission line from APS.

(b) Includes activities related to APSES and SunCor.

Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $46 million higher for the nine months ended September 30, 2012 compared with the prior-year period. The following table summarizes the major components of this change:

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	Increase (Decrease)
	Operating revenues			Fuel and purchased power expenses			Net change
	(dollars in millions)
Impacts of retail regulatory settlement effective July 1, 2012 (a)	$	39		$	—		$	39
Higher retail transmission revenues	31			—			31
Lower fuel and purchased power costs, net of related deferrals and off-system sales	(1		)	(9		)	8
Effects of weather	7			3			4
Lower usage per customer	(14		)	(2		)	(12		)
Settlement in 2011 of certain prior-period transmission right-of-way revenues	(28		)	—			(28		)
Miscellaneous items, net	2			(2		)	4
Total	$	36		$	(10	)	$	46

(a) Includes a retail non-fuel base rate increase which is offset by other rate changes below (see Note 3).

Operations and maintenance Operations and maintenance expenses decreased $28 million for the nine months ended September 30, 2012 compared with the prior-year period primarily because of:

· A decrease of $28 million related to settlement in 2011 of certain transmission right-of-way costs, which was offset in operating revenues;

· A decrease of $15 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues;

· A decrease of $9 million in generation costs, primarily related to lower nuclear generation costs;

· An increase of $9 million related to higher stock compensation costs resulting from an improved company stock price and estimated performance results;

· An increase of $10 million related to employee benefit costs; and

· An increase of $5 million due to other miscellaneous factors.

Depreciation and amortization Depreciation and amortization expenses were $19 million lower for the nine months ended September 30, 2012 compared with the prior-year period primarily due to the impacts of Palo Verde operating license extensions, partially offset by increased plant in service.

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Taxes other than income taxes Taxes other than income taxes increased $8 million for the nine months ended September 30, 2012 compared with the prior-year period primarily because of higher property tax rates in the current period.

Interest charges, net of allowance for borrowed funds used during construction Interest charges, net of allowance for borrowed funds used during construction, decreased $17 million for the nine months ended September 30, 2012 compared with the prior-year period primarily because of lower debt balances in the current period.

Income taxes Income taxes were $44 million higher for the nine months ended September 30, 2012 compared with the prior-year period primarily due to higher pre-tax income in the current period and a lower effective tax rate in 2011.

Discontinued Operations

Income from discontinued operations decreased $12 million because of absence of a gain of approximately $10 million after income taxes related to the sale of our investment in APSES in 2011.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. On October 18, 2012, the Pinnacle West Board of Directors declared a quarterly dividend of $0.545 per share of common stock, payable on December 3, 2012, to shareholders of record on November 1, 2012. This represents an increase in the indicated annual dividend from $2.10 per share to $2.18 per share. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors based on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

Our primary sources of cash are dividends from APS and external debt and equity issuances. An 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 September 30, 2012, APS’s common equity ratio, as defined, was 56%. Its total shareholder equity was approximately $4.2 billion, and total capitalization was approximately $7.4 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West.

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Many of APS’s current capital expenditure projects qualify for bonus depreciation. The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 includes provisions making qualified property placed into service after September 8, 2010 and before January 1, 2012 eligible for 100% bonus depreciation for federal income tax purposes. In addition, qualified property placed into service in 2012 is eligible for 50% bonus depreciation for federal income tax purposes. These provisions of the recent tax legislation are expected to generate approximately $400-450 million of cash tax benefits for APS through accelerated depreciation. It is anticipated that these cash benefits will be fully realized by APS by the end of 2013, with a majority of the benefit realized in 2012. The cash generated is an acceleration of tax benefits that APS would have otherwise received over 20 years.

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the nine months ended September 30, 2012 and 2011 (dollars in millions):

Pinnacle West Consolidated

	Nine Months Ended September 30,						Net
	2012			2011			Change
Net cash flow provided by operating activities	$	929		$	921		$	8
Net cash flow used for investing activities	(653		)	(534		)	(119		)
Net cash flow provided by (used for) financing activities	(230		)	68			(298		)
Net increase in cash and cash equivalents	$	46		$	455		$	(409	)

Arizona Public Service Company

	Nine Months Ended September 30,						Net
	2012			2011			Change
Net cash flow provided by operating activities	$	923		$	933		$	(10	)
Net cash flow used for investing activities	(653		)	(586		)	(67		)
Net cash flow provided by (used for) financing activities	(236		)	108			(344		)
Net increase in cash and cash equivalents	$	34		$	455		$	(421	)

Operating Cash Flows

Nine-month period ended September 30, 2012 compared with nine-month period ended September 30, 2011. Pinnacle West’s consolidated net cash provided by operating activities was $929 million in 2012, compared to $921 million in 2011, an increase of $8 million in net cash provided. The increase is primarily related to a decrease in cash paid for interest in the current year period.

Other. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. Under ERISA, the

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qualified pension plan was 89% funded as of January 1, 2011 and 105% funded as of January 1, 2012 as a result of changes in funding regulations. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We have contributed $65 million to our pension plan year to date in 2012. The minimum contributions for the pension plan due in 2013 and 2014 under the recently enacted Moving Ahead for Progress in the 21st Century Act (MAP-21) are estimated to be zero and $89 million, respectively. However, we are currently evaluating future expected contributions considering the pension plan’s current funded status, discount rates, interest rates, investment returns and actual contributions made in prior years, among other factors, to determine the level to which future contributions may exceed these new minimum funding levels. The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year.

The $70 million long-term income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt. Further clarification of the timing is expected from the IRS within the next twelve months.

Investing Cash Flows

Nine-month period ended September 30, 2012 compared with nine-month period ended September 30, 2011. Pinnacle West’s consolidated net cash used for investing activities was $653 million in 2012, compared to $534 million in 2011, an increase of $119 million in net cash used. The increase in net cash used for investing activities is primarily due to an increase of approximately $22 million in capital expenditures, the absence of $55 million in proceeds from the sale of life insurance policies in 2011, and the absence of $45 million in proceeds from the sale of Pinnacle West’s investment in APSES in 2011.

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Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years:

Capital Expenditures

(dollars in millions)

	Estimated for the Year Ended December 31,
	2012		2013		2014
APS
Generation:
Nuclear Fuel	$	72	$	58	$	82
Renewables	215		206		221
Environmental	8		25		78
Four Corners Units 4 and 5	294		—		—
Other Generation	141		159		227
Distribution	241		267		318
Transmission	119		158		212
Other (a)	45		28		47
Total APS	$	1,135	$	901	$	1,185

(a) Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS’s existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment. Included under Renewables is the AZ Sun Program, which reflects capital funding from the 2012 RES implementation plan, which was approved by the ACC on December 14, 2011. For purposes of this table, we have assumed the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shutdown of Units 1-3, as discussed in the “Overview” section above. As a result, we included the $294 million purchase price under Generation and have not included environmental expenditures for Units 1-3. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

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Financing Cash Flows and Liquidity

Nine-month period ended September 30, 2012 compared with nine-month period ended September 30, 2011. Pinnacle West’s consolidated net cash used for financing activities was $230 million in 2012, compared to $68 million of net cash provided in 2011, an increase of $298 million in net cash used. The increase in net cash used for financing activities is primarily due to APS’s $408 million in higher repayments of long-term debt partially offset by $56 million in higher issuances of long-term debt. In addition, Pinnacle West had $215 million in lower repayments of long-term debt partially offset by $175 million in lower debt issuances (see below).

Significant Financing Activities. 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.

Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

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See “Financial Assurances” in Note 10 for a discussion of APS’s separate outstanding letters of credit.

Other Financing Matters. See Note 3 for information regarding the PSA approved by the ACC.

See Note 3 for information regarding the settlement related to the 2008 retail rate case, which includes ACC authorization and requirements of equity infusions into APS of at least $700 million by December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in 2010).

See Note 8 for information related to the change in our margin accounts.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At September 30, 2012, the ratio was approximately 45% for Pinnacle West and 44% 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.

Neither Pinnacle West’s nor 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 Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. 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. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

See Note 2 for further discussions of liquidity matters.

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Credit Ratings

The ratings of securities of Pinnacle West and APS as of October 31, 2012 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient liquidity to respond to a downward revision to our credit ratings.

	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	Baa2	BBB	BBB
Commercial paper	P-3	A-2	F3
Outlook	Stable	Positive	Stable

APS
Corporate credit rating	Baa1	BBB	BBB
Senior unsecured	Baa1	BBB	BBB+
Secured lease obligation bonds	Baa1	BBB	BBB+
Commercial paper	P-2	A-2	F3
Outlook	Stable	Positive	Stable

Off-Balance Sheet Arrangements

See Note 7 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

Financial Assurances

See “Financial Assurances” in Note 10 for a discussion of APS’s outstanding letters of credit. Pinnacle West has also issued parental guarantees and surety bonds for APS, which were not material at September 30, 2012.

Contractual Obligations

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Year	2012		2013-2014		2015-2016		Thereafter		Total
Renewable energy credits	$	46	$	83	$	88	$	573	$	790

Changes have also occurred relating to long-term debt payments and interest. See Note 2 for a discussion of these changes.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. There have been no changes to our critical accounting policies since our 2011 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2011 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

See Note 16 for adoption of amended accounting guidance relating to fair value measurements and disclosures and the presentation of comprehensive income.

MARKET AND CREDIT RISKS

Market Risks

Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund and benefit plan assets.

Interest Rate and Equity Risk

We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Notes 14 and 15) and benefit plan assets. The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing value of their investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options and swaps. As part of our risk management program, we use such 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 commodities.

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The following table shows the net pretax changes in mark-to-market of our derivative positions for the nine months ended September 30, 2012 and 2011 (dollars in millions):

	Nine Months Ended September 30,
	2012			2011
Mark-to-market of net positions at beginning of period	$	(222	)	$	(239	)
Recognized in earnings (a):
Change in mark-to-market losses for future period deliveries	1			(2		)
Decrease in regulatory asset	50			15
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (b)	(37		)	(41		)
Mark-to-market losses realized during the period	87			99
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(121	)	$	(168	)

(a) Represents the amounts reflected in income after the effect of PSA deferrals.

(b) The changes in mark-to-market recorded in OCI are due primarily to changes in forward natural gas prices.

The table below shows the fair value of maturities of our derivative contracts (dollars in millions and excluding margin and collateral) at September 30, 2012 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” in Item 8 of our 2011 Form 10-K and Note 14 for more discussion of our valuation methods.

Source of Fair Value	2012			2013			2014			2015			2016			Years thereafter			Total fair value
Observable prices provided by other external sources	$	(15	)	$	(40	)	$	(17	)	$	1		$	—		$	—		$	(71	)
Prices based on unobservable inputs	(2		)	(10		)	(9		)	(11		)	(8		)	(10		)	(50		)
Total by maturity	$	(17	)	$	(50	)	$	(26	)	$	(10	)	$	(8	)	$	(10	)	$	(121	)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at September 30, 2012 and December 31, 2011 (dollars in millions):

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	September 30, 2012 Gain (Loss)					December 31, 2011 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings (a)
Natural gas	$	—	$	—		$	1	$	(1	)
Regulatory asset (liability) or OCI (b)
Electricity	8		(8		)	5		(5		)
Natural gas	27		(27		)	27		(27		)
Total	$	35	$	(35	)	$	33	$	(33	)

(a) Represents the amounts reflected in income after the effect of PSA deferrals.

(b) These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 14 for a discussion of our credit valuation adjustment policy. See Note 8 for a further discussion of credit risk.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Key Financial Drivers” and “Market and Credit Risks” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.

Item 4. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (15 U.S.C. 78a et seq.), is recorded, processed, summarized and reported, within the time periods specified in the United States Securities and Exchange Commission’s (“SEC’s”) rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure

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controls and procedures as of September 30, 2012. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’s disclosure controls and procedures as of September 30, 2012. Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended September 30, 2012 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See “Environmental Matters” in Item 5 below and in Part II, Item 5 of the Pinnacle West/APS Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012, and “Business of Arizona Public Service Company — Environmental Matters” in Item 1 of the 2011 Form 10-K in regard to pending or threatened litigation or other disputes.

See Note 3 for ACC and FERC-related matters.

See Note 10 for information regarding FERC proceedings on Pacific Northwest energy market issues, environmental and climate change lawsuits, a Superfund matter and matters related to a September 2011 power outage.

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A — Risk Factors in the 2011 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS. The risks described in the 2011 Form 10-K are not the only risks facing Pinnacle West and APS. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

The following table contains information about our purchases of our common stock during the third quarter of 2012.

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 — July 31, 2012	—	—		—	—
August 1 — August 31, 2012	—	—		—	—
September 1 — September 30, 2012	1,540	$	52.74	—	—

Total	1,540	$	52.74	—	—

(1) Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding obligations upon the vesting of restricted stock.

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Item 5. OTHER INFORMATION

Environmental Matters

EPA Environmental Regulation

Regional Haze Rules. Over a decade ago, the 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, the EPA) to determine what pollution control technologies constitute the “best available retrofit technology” (“BART”) for certain older major stationary sources. The 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 the EPA’s final BART determinations (and the Cholla Power Plant’s (“Cholla”) obligations to comply with the Arizona Department of Environmental Quality’s (“ADEQ”) 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 State Implementation Plan (“SIP”) for Cholla and other sources within the state on March 2, 2011.

On December 2, 2011, the EPA provided notice of a proposed consent decree to address a lawsuit filed by a number of environmental organizations, which alleged that the EPA failed to promulgate Federal Implementation Plans (“FIPs”) for states that have not yet submitted all or part of the required regional haze SIPs. In accordance with the consent decree, on July 2, 2012, EPA issued a proposed BART rule applicable to Cholla proposing to approve ADEQ’s BART emissions limits for sulfur dioxide and particulate emissions, but proposing to disapprove ADEQ’s BART emissions limits for oxides of nitrogen (“NOx”), for which EPA is proposing to promulgate a FIP. If finalized as proposed, EPA’s FIP would establish a new, more stringent NOx emissions rate for the two BART-eligible Cholla units owned by APS. In order to comply with this new rate, APS would be required to install selective catalytic reduction technology on both units. APS’s total costs for these post-combustion controls would be approximately $182 million, which is not included in our current environmental estimates described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Part I, Item 2. Under the proposed rule, APS would have five years to complete installation of the equipment and achieve the BART emissions limits. APS filed comments on EPA’s proposed BART rule on September 18, 2012. APS cannot currently predict the content of the final rule, which, pursuant to the consent decree, the EPA must promulgate by November 15, 2012.

Four Corners. The EPA previously requested that APS, as the operating agent for Four Corners, perform a BART analysis for Four Corners. APS submitted an analysis to the EPA concluding that certain combustion control equipment constitutes BART for the plant. Based on these analyses and comments received through EPA’s rulemaking process, the EPA then determines what it believes constitutes BART for each plant.

On August 6, 2012, the EPA issued its final BART determination for Four Corners. The rule includes two compliance alternatives. The first emission control strategy finalized by the EPA would

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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 these controls could be up to approximately $400 million for Four Corners. Under the alternative emission control strategy finalized by the EPA, the owners of Four Corners would have the option to close permanently 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 described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Part I, Item 2, since they will be incurred in years following 2014. For particulate matter (“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, the EPA determined it is not necessary or appropriate to set new PM limits for Units 1-3 under the final Four Corners BART rule. (See “Mercury and other Hazardous Air Pollutants” for additional details of these standards.) 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 the EPA of which emission control strategy Four Corners will follow.

Mercury and other Hazardous Air Pollutants. On December 16, 2011, the 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.

Nuclear Matters

Palo Verde Fuel Cycle. The Palo Verde participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. (See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Nuclear — Palo Verde Fuel Cycle” in Part I, Item 1 of the 2011 Form 10-K for a description of the fuel cycle stages and the long term contractual commitments for each stage.) In late August 2012, one of Palo Verde’s suppliers that converts uranium concentrates to uranium hexafluoride invoked the force majeure provision in its contract when it shut down its conversion plant due to regulatory compliance issues. The Palo Verde participants have sufficient strategic reserves of enriched uranium such that they do not anticipate a short term impact on nuclear fuel supplies as a result of the force majeure declaration. The participants are evaluating alternate long-term options for securing conversion services.

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Item 6. EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description

12.1	Pinnacle West	Ratio of Earnings to Fixed Charges

12.2	APS	Ratio of Earnings to Fixed Charges

12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements

31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.2	Pinnacle West	Certificate of James R. Hatfield, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.3	APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.4	APS	Certificate of James R. Hatfield, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

32.1*	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS*	Pinnacle West APS	XBRL Instance Document

101.SCH*	Pinnacle West APS	XBRL Taxonomy Extension Schema Document

101.CAL*	Pinnacle West APS	XBRL Taxonomy Extension Calculation Linkbase Document

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Exhibit No.	Registrant(s)	Description
101.LAB*	Pinnacle West APS	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	Pinnacle West APS	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF*	Pinnacle West APS	XBRL Taxonomy Definition Linkbase Document

*Furnished herewith as an Exhibit.

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In addition, Pinnacle West and APS hereby incorporate the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:

Exhibit No.	Registrant(s)	Description	Previously Filed as Exhibit(1)	Date Filed

3.1	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of May 19, 2010	3.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-3-10

3.2	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008	3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-7-08

3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93

3.4	APS	Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012	3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473	5-22-12

3.5	APS	Arizona Public Service Company Bylaws, amended as of December 16, 2008	3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-4473	2-20-09

(1) Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PINNACLE WEST CAPITAL CORPORATION
	(Registrant)


Dated: November 2, 2012	By:	/s/ James R. Hatfield
	James R. Hatfield
	Sr. Vice President and Chief Financial Officer
	(Principal Financial Officer and
	Officer Duly Authorized to sign this Report)


	ARIZONA PUBLIC SERVICE COMPANY
	(Registrant)


Dated: November 2, 2012	By:	/s/ James R. Hatfield
	James R. Hatfield
	Sr. Vice President and Chief Financial Officer
	(Principal Financial Officer and
	Officer Duly Authorized to sign this Report)