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, 2011

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 25, 2011: 109,181,233
ARIZONA PUBLIC SERVICE COMPANY		Number of shares of common stock, $2.50 par value, outstanding as of October 25, 2011: 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	42
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	71
	Item 4.	Controls and Procedures	71

Part II			73
	Item 1.	Legal Proceedings	73
	Item 1A.	Risk Factors	73
	Item 5.	Other Information	74
	Item 6.	Exhibits	76
Signatures			79

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, 2010 (“2010 Form 10-K”), in Part II, Item 1A of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (the “Second Quarter 10-Q”), in 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,” these factors include, but are not limited to:

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

· our ability to manage capital expenditures and other 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;

· 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 Risk Factors described in Part I, Item 1A of our 2010 Form 10-K, in Part II, Item 1A of our Second Quarter 10-Q 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,
	2011			2010
OPERATING REVENUES
Regulated electricity	$	1,124,049		$	1,116,211
Other revenues	792			499
Total	1,124,841			1,116,710
OPERATING EXPENSES
Regulated electricity fuel and purchased power	337,896			353,904
Operations and maintenance	210,035			219,658
Depreciation and amortization	106,350			104,177
Taxes other than income taxes	34,223			37,528
Other expenses	1,320			1,169
Total	689,824			716,436
OPERATING INCOME	435,017			400,274
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,378			5,524
Other income (Note 11)	441			4,261
Other expense (Note 11)	(3,052		)	(3,894		)
Total	4,767			5,891
INTEREST EXPENSE
Interest charges	62,034			60,419
Allowance for borrowed funds used during construction	(6,939		)	(6,163		)
Total	55,095			54,256
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	384,689			351,909
INCOME TAXES	131,416			122,347
INCOME FROM CONTINUING OPERATIONS	253,273			229,562
INCOME FROM DISCONTINUED OPERATIONS
Net of income tax expense of $6,216 and $5,859 (Note 13)	9,512			9,477
NET INCOME	262,785			239,039
Less: Net income attributable to noncontrolling interests (Note 7)	7,426			5,119
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	255,359		$	233,920

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,128			108,632
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	109,861			109,094

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	2.25		$	2.07
Net income attributable to common shareholders — basic	2.34			2.15
Income from continuing operations attributable to common shareholders — diluted	2.24			2.06
Net income attributable to common shareholders — diluted	2.32			2.14
DIVIDENDS DECLARED PER SHARE	$	—		$	—

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	245,838		$	224,434
Discontinued operations, net of tax	9,521			9,486
Net income attributable to common shareholders	$	255,359		$	233,920

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,
	2011			2010
OPERATING REVENUES
Regulated electricity	$	2,570,692		$	2,527,052
Other revenues	2,795			4,715
Total	2,573,487			2,531,767
OPERATING EXPENSES
Regulated electricity fuel and purchased power	793,952			821,244
Operations and maintenance	675,654			639,580
Depreciation and amortization	319,550			307,806
Taxes other than income taxes	112,002			100,933
Other expenses	4,536			3,572
Total	1,905,694			1,873,135
OPERATING INCOME	667,793			658,632
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	18,697			16,417
Other income (Note 11)	2,630			3,851
Other expense (Note 11)	(7,921		)	(8,768		)
Total	13,406			11,500
INTEREST EXPENSE
Interest charges	183,251			181,937
Allowance for borrowed funds used during construction	(14,371		)	(12,254		)
Total	168,880			169,683
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	512,319			500,449
INCOME TAXES	176,229			165,882
INCOME FROM CONTINUING OPERATIONS	336,090			334,567
INCOME FROM DISCONTINUED OPERATIONS
Net of income tax expense of $7,121 and $14,873 (Note 13)	10,860			23,141
NET INCOME	346,950			357,708
Less: Net income attributable to noncontrolling interests (Note 7)	20,041			15,005
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	326,909		$	342,703

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,003			105,846
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	109,683			106,318

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	2.90		$	3.02
Net income attributable to common shareholders — basic	3.00			3.24
Income from continuing operations attributable to common shareholders — diluted	2.88			3.01
Net income attributable to common shareholders — diluted	2.98			3.22
DIVIDENDS DECLARED PER SHARE	$	1.575		$	1.575

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	316,001		$	319,533
Discontinued operations, net of tax	10,908			23,170
Net income attributable to common shareholders	$	326,909		$	342,703

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, 2011			December 31, 2010
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	564,712		$	110,188
Customer and other receivables	365,868			324,207
Accrued unbilled revenues	184,169			103,292
Allowance for doubtful accounts	(4,126		)	(7,981		)
Materials and supplies (at average cost)	203,118			181,414
Fossil fuel (at average cost)	25,403			21,575
Deferred income taxes	107,732			124,897
Income tax receivable (Note 6)	—			2,483
Assets from risk management activities (Note 8)	27,713			73,788
Deferred fuel and purchased power regulatory asset (Note 3)	31,611			—
Other regulatory assets (Note 3)	55,852			62,286
Other current assets	29,183			28,362
Total current assets	1,591,235			1,024,511

INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 8)	32,316			39,032
Nuclear decommissioning trust (Note 17)	488,551			469,886
Other assets	63,731			116,216
Total investments and other assets	584,598			625,134

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	13,423,406			13,201,960
Accumulated depreciation and amortization	(4,684,760		)	(4,514,204		)
Net	8,738,646			8,687,756
Construction work in progress	618,728			459,361
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	133,832			137,956
Intangible assets, net of accumulated amortization	176,401			184,952
Nuclear fuel, net of accumulated amortization	134,232			108,794
Total property, plant and equipment	9,801,839			9,578,819

DEFERRED DEBITS
Regulatory assets (Note 3)	977,975			986,370
Income tax receivable (Note 6)	68,201			65,103
Other	126,515			113,061
Total deferred debits	1,172,691			1,164,534

TOTAL ASSETS	$	13,150,363		$	12,392,998

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, 2011			December 31, 2010
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	281,647		$	236,354
Accrued taxes (Note 6)	191,507			104,711
Accrued interest	56,174			54,831
Short-term borrowings	—			16,600
Current maturities of long-term debt	876,363			631,879
Customer deposits	71,772			68,322
Liabilities from risk management activities (Note 8)	60,667			58,976
Deferred fuel and purchased power regulatory liability (Note 3)	—			58,442
Other regulatory liabilities (Note 3)	94,374			80,526
Other current liabilities	150,764			139,063
Total current liabilities	1,783,268			1,449,704

LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities	2,963,457			2,948,991
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	83,130			96,803
Total long-term debt less current maturities	3,046,587			3,045,794

DEFERRED CREDITS AND OTHER
Deferred income taxes	1,955,458			1,863,861
Regulatory liabilities (Note 3)	689,120			614,063
Liability for asset retirements (Note 15)	258,332			328,571
Liabilities for pension and other postretirement benefits (Note 4)	877,485			813,121
Liabilities from risk management activities (Note 8)	58,745			65,390
Customer advances	112,730			121,645
Coal mine reclamation	117,779			117,243
Unrecognized tax benefits (Note 6)	76,936			66,349
Other	170,928			132,031
Total deferred credits and other	4,317,513			4,122,274

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

EQUITY (Note 9)
Common stock, no par value	2,441,621			2,421,372
Treasury stock	(5,232		)	(2,239		)
Total common stock	2,436,389			2,419,133
Retained earnings	1,579,240			1,423,961
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(56,582		)	(59,420		)
Derivative instruments	(64,962		)	(100,347		)
Total accumulated other comprehensive loss	(121,544		)	(159,767		)
Total shareholders’ equity	3,894,085			3,683,327
Noncontrolling interests (Note 7)	108,910			91,899
Total equity	4,002,995			3,775,226

TOTAL LIABILITIES AND EQUITY	$	13,150,363		$	12,392,998

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,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	346,950		$	357,708
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of district cooling business	—			(41,973		)
Gain on sale of energy-related products and services business	(10,404		)	—
Depreciation and amortization including nuclear fuel	370,107			350,762
Deferred fuel and purchased power	30,965			50,020
Deferred fuel and purchased power amortization	(121,018		)	(95,926		)
Allowance for equity funds used during construction	(18,697		)	(16,417		)
Real estate impairment charges	—			16,731
Gain on real estate debt restructuring	—			(14,403		)
Deferred income taxes	131,582			281,486
Change in mark-to-market valuations	1,861			3,716
Changes in current assets and liabilities:
Customer and other receivables	(47,410		)	(103,973		)
Accrued unbilled revenues	(80,877		)	(69,035		)
Materials, supplies and fossil fuel	(25,532		)	19,011
Other current assets	(1,581		)	(6,027		)
Accounts payable	29,340			36,687
Accrued taxes and income tax receivable-net	89,534			56,851
Other current liabilities	30,300			6,738
Change in margin and collateral accounts — assets	33,591			(4,336		)
Change in margin and collateral accounts — liabilities	85,785			(143,725		)
Change in unrecognized tax benefits	12,123			(72,649		)
Change in other long-term assets	(10,678		)	(59,382		)
Change in other long-term liabilities	74,565			17,636
Net cash flow provided by operating activities	920,506			569,500

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(643,261		)	(552,707		)
Contributions in aid of construction	36,351			25,258
Allowance for borrowed funds used during construction	(14,371		)	(12,553		)
Proceeds from sale of district cooling business	—			100,300
Proceeds from sale of energy-related products and services business	45,111			—
Proceeds from nuclear decommissioning trust sales	405,637			424,255
Investment in nuclear decommissioning trust	(417,957		)	(442,567		)
Proceeds from sale of commercial real estate investments	1,100			71,174
Proceeds from sale of life insurance policies	55,444			—
Other	(2,346		)	9,621
Net cash flow used for investing activities	(534,292		)	(377,219		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	470,353			—
Repayment of long-term debt	(228,457		)	(84,529		)
Short-term borrowings and payments — net	(16,600		)	(153,715		)
Dividends paid on common stock	(166,197		)	(161,722		)
Common stock equity issuance	14,953			255,156
Distributions to noncontrolling interests	(2,610		)	(3,286		)
Other	(3,132		)	6,352
Net cash flow provided by (used for) financing activities	68,310			(141,744		)

NET INCREASE IN CASH AND CASH EQUIVALENTS	454,524			50,537

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	110,188			145,378

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	564,712		$	195,915
Supplemental disclosure of cash flow information Cash paid during the period for:
Income taxes, net of (refunds)	$	5,676		$	(22,165	)
Interest, net of amounts capitalized	$	163,250		$	167,576

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, SunCor Development Company (“SunCor”), APS Energy Services Company, Inc. (“APSES”), and El Dorado Investment Company (“El Dorado”). See Note 13 for discussion of discontinued operations 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.

In preparing the condensed consolidated financial statements, we have evaluated the events that have occurred after September 30, 2011 through the date the financial statements were issued.

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 2010 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income, Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows in accordance with accounting requirements for reporting discontinued operations (see Note 13) and the impacts related to the reclassification of regulatory assets and liabilities for the current portion (see Note 3).

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, 2010	As previously reported			Reclassifications for discontinued operations			Amount reported after reclassification for discontinued operations
Operating Revenues
Other revenues	$	22,874		$	(22,375	)	$	499
Operating Expenses
Operations and maintenance	221,469			(1,811		)	219,658
Depreciation and amortization	104,194			(17		)	104,177
Other expenses	18,365			(17,196		)	1,169
Other
Other income	4,348			(87		)	4,261
Other expense	(3,855		)	(39		)	(3,894		)
Interest Expense
Interest charges	60,491			(72		)	60,419
Income Taxes	123,486			(1,139		)	122,347
Income From Continuing Operations	231,828			(2,266		)	229,562
Income From Discontinued Operations	7,211			2,266			9,477

Statement of Income for the Nine Months Ended September 30, 2010	As previously reported			Reclassifications for discontinued operations			Amount reported after reclassification for discontinued operations
Operating Revenues
Other revenues	$	52,982		$	(48,267	)	$	4,715
Operating Expenses
Operations and maintenance	644,415			(4,835		)	639,580
Depreciation and amortization	307,864			(58		)	307,806
Taxes other than income taxes	100,936			(3		)	100,933
Other expenses	41,009			(37,437		)	3,572
Other
Other income	3,828			23			3,851
Other expense	(8,650		)	(118		)	(8,768		)
Interest Expense
Allowance for borrowed funds used during construction	(12,314		)	60			(12,254		)
Income Taxes	168,143			(2,261		)	165,882
Income From Continuing Operations	338,395			(3,828		)	334,567
Income From Discontinued Operations	19,313			3,828			23,141

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheets - December 31, 2010	As previously reported		Reclassifications for regulatory assets and liabilities			Amount reported after reclassification for regulatory assets and liabilities

Current Assets — Deferred income taxes	$	94,602	$	30,295		$	124,897
Current Assets — Other regulatory assets	—		62,286			62,286
Deferred Debits — Regulatory assets	1,048,656		(62,286		)	986,370
Current Liabilities — Deferred fuel and purchased power regulatory liability	—		58,442			58,442
Current Liabilities — Other regulatory liabilities	—		80,526			80,526
Deferred Credits and Other — Deferred income taxes	1,833,566		30,295			1,863,861
Deferred Credits and Other — Deferred fuel and purchased power regulatory liability	58,442		(58,442		)	—
Deferred Credits and Other —Regulatory liabilities	694,589		(80,526		)	614,063

Statement of Cash Flows for the Nine Months Ended September 30, 2010	As previously reported			Reclassifications for regulatory assets and liabilities and to conform to current year presentation			Amount reported after reclassification for regulatory assets and liabilities and to conform to current year presentation
Cash Flows from Operating Activities
Other current assets	$	(13,236	)	$	7,209		$	(6,027	)
Other current liabilities	10,989			(4,251		)	6,738
Expenditures for real estate investments	(514		)	514			—
Gains and other changes in real estate assets	1,811			(1,811		)	—
Change in other regulatory liabilities	40,121			(40,121		)	—
Change in other long-term assets	(51,659		)	(7,723		)	(59,382		)
Change in other long-term liabilities	(28,547		)	46,183			17,636

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.

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Pinnacle West

On February 23, 2011, Pinnacle West entered into a $175 million term-loan facility that matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91% $175 million Senior Notes. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings or, if unavailable, its long-term issuer ratings. Through September 30, 2011, Pinnacle West has repaid $40 million of the $175 million term loan facility.

At September 30, 2011, Pinnacle West’s $200 million credit facility, which matures in February 2013, was available for bank borrowings, support of its $200 million commercial paper program, or for issuances of letters of credit. At September 30, 2011, Pinnacle West had no outstanding borrowings or letters of credit under this credit facility and no outstanding commercial paper borrowings. 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.

APS

On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, with a new $500 million facility. The new revolving credit facility terminates in February 2015. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS uses the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit, as necessary from time to time. Interest rates are based on APS’s senior unsecured debt credit ratings.

On August 25, 2011, APS issued $300 million of 5.05% unsecured senior notes that mature on September 1, 2041. The net proceeds from the sale of the notes were used along with cash on hand to repay at maturity APS’s $400 million aggregate principal amount of 6.375% senior notes due October 15, 2011.

On September 7, 2011, APS entered into a new letter of credit agreement supporting its approximately $27 million aggregate principal amount of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B. The agreement expires September 22, 2016.

At September 30, 2011, APS had two credit facilities totaling $1 billion, including the $500 million credit facility described above and a $500 million facility that matures in February 2013. These facilities are available to support its $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At September 30, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. A $20 million letter of credit was outstanding under APS’s 2011 $500 million credit facility described above.

See “Financial Assurances” in Note 10 for discussion of APS’s other 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. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

	As of September 30, 2011				As of December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Pinnacle West	$	135	$	135	$	175	$	176
APS	3,788		4,219		3,503		3,737
Total	$	3,923	$	4,354	$	3,678	$	3,913

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At September 30, 2011, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.0 billion, and total capitalization was approximately $7.7 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.1 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 capital requirements.

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. The Company requested that the increase become effective July 1, 2012. The request would increase the average retail customer bill approximately 6.6%. The filing is based on a test year ended December 31, 2010, adjusted as described below. APS’s filing was deemed sufficient by the ACC staff and a hearing has been scheduled to begin January 19, 2012.

The key financial provisions of the request included:

· an increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through the Company’s renewable energy surcharge (which will increase base rates) and $143.5 million of lower fuel and purchased power costs currently addressed through the Power Supply Adjustor (the “PSA”) (which will decrease base rates);

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· a rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;

· the following proposed capital structure and costs of capital:

	Capital Structure		Cost of Capital
Long-term debt	46.1	%	6.38	%
Common stock equity	53.9	%	11.00	%
Weighted-average cost of capital			8.87	%

· a base rate for fuel and purchased power costs (“Base Fuel Rate”) of $0.03242 per kilowatt-hour (“kWh”) based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).

The Company proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision. In addition, APS proposed two new recovery mechanisms that would adjust electricity rates annually between changes in retail base rates. The Efficiency and Infrastructure Account, a decoupling mechanism, would address recovery of the Company’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation. The Environmental and Reliability Account, a generation infrastructure adjustment mechanism, would allow recovery of the costs associated with generation investments related to new generation additions, generation efficiency projects and environmental compliance requirements.

2008 General Retail Rate Case 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 included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates. The new rates were effective January 1, 2010. The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:

· Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);

· An authorized return on common equity of 11%;

· A capital structure comprised of 46.2% debt and 53.8% common equity;

· A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);

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· 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 and its use of renewable energy, 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 Arizona Renewable Energy Standard and Tariff (“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.

During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval. The plan provided for the acquisition of renewable generation in compliance with requirements through 2014, and requested RES funding of $87 million for 2010, which was later approved by the ACC. APS also sought various other determinations in its plan, including approval of the AZ Sun Program and the Community Power Project in Flagstaff, Arizona described below.

On March 3, 2010, the ACC approved the AZ Sun Program, which contemplates the addition of 100 megawatts (“MW”) of APS-owned solar resources through 2014. Through this program, APS plans to invest up to $500 million in solar photovoltaic projects across Arizona, which APS will acquire through competitive procurement processes. The costs associated with the first 50 MW under this program will be recovered initially through the RES until such time as the costs are recovered in base rates or other mechanisms. The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’s current retail rate case, although APS seeks to recover 19 MW of this second tranche in its 2012 RES implementation plan as discussed below.

On April 1, 2010, the ACC approved the Community Power Project, a pilot program in which APS will own, operate and receive energy from approximately 1.5 MW of solar panels on the rooftops of up to 200 residential and business customers located within a certain test area in Flagstaff, Arizona. The capital carrying costs of the program will be recovered through the RES until such time as these costs are recovered in base rates.

On July 1, 2010, APS filed its annual RES implementation plan, covering the 2011-2015 timeframe and requesting 2011 RES funding of $96 million. The 2011 Plan addressed enhancements

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to the residential distributed energy incentive program based on high customer participation, among other things. On October 13, 2010, APS filed an adjusted RES implementation plan to reflect the following items, among others: 1) increased clarity relating to customer project in-service dates and related budget revisions; 2) AZ Sun Program updates; and 3) the addition of 10 MW of biomass capacity. On December 10, 2010, the ACC approved the 2011 Plan and associated funding request. On February 11, 2011, the ACC amended its original decision that approved the 2011 Plan as follows: the ACC (a) reversed its approval of a feed-in tariff program; (b) restricted APS’s ownership of facilities to only economically challenged, rural schools and only after a school has received a bid from a third-party solar installer; (c) approved the Rapid Reservation program; and (d) maintained the original approved budget with some timing modifications.

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. The range in the funding request arises from APS offering several options for third-party initiatives. The options involve obtaining 150 MW from third-parties entirely through power purchase agreements (“PPAs”) or through a mix of PPAs and non-residential distributed energy programs. APS also proposed (i) an additional 100 MW of APS-owned AZ Sun projects; (ii) permission to recover costs for a 19 MW AZ Sun project now instead of waiting for a recovery mechanism in APS’s current retail rate case; and (iii) an additional 25 MW of APS-owned systems on school and government facilities. On October 26, 2011, the ACC staff issued a report recommending an RES budget of $131.7 million, including the addition of 100 MW of APS-owned AZ Sun projects, permission to recover costs for a 19 MW AZ Sun project through the 2012 RES, and an additional 15 MW of APS-owned systems on school and government facilities. APS expects a decision from the ACC by year end.

Demand-Side Management Adjustor Charge (“DSMAC”). The settlement agreement related to the 2008 retail rate case requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan, requesting approval by the ACC of programs and program elements for which APS had estimated a budget in the amount of $50 million for 2010. APS received ACC approval of all of its proposed programs and implemented the new DSMAC on March 1, 2010. A surcharge was added to customer bills in order to recover these estimated amounts for use on certain demand-side management programs. The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.

The ACC 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 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.

On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million. On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.

On June 1, 2011, APS filed its 2012 Energy Efficiency Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75%

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of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the settlement agreement (1.5% of total energy resources). APS proposed a budget for 2012 of $90 million. When added to the third and final year of the amortization of 2009 program costs discussed above and less the $10 million already being recovered in general rates, the proposed 2012 DSMAC would recover approximately $85 million over a twelve month period beginning March 1, 2012. APS expects a decision from the ACC by year end.

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 2011 and 2010 (dollars in millions):

	Nine Months Ended September 30,
	2011			2010
Beginning balance	$	(58	)	$	(87	)
Deferred fuel and purchased power costs-current period	(31		)	(50		)
Amounts refunded through revenues	121			96
Ending balance	$	32		$	(41	)

The PSA rate for the PSA year beginning February 1, 2011 is ($0.0057) per kWh as compared to ($0.0045) per kWh for the prior year. Any uncollected (overcollected) deferrals during the 2011 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2012.

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 must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the transmission cost adjustor (“TCA”).

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.

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Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38 million of this revenue increase relates to Retail Transmission Charges. The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

Regulatory Assets and Liabilities

As discussed in Note 1, as of September 30, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Condensed Consolidated Balance Sheets. This presentation is reflected in the tables below.

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

	September 30, 2011				December 31, 2010
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	663	$	—	$	669
Deferred income taxes	3		82		3		69
Deferred fuel and purchased power — mark-to-market (Note 8)	35		27		42		35
Transmission vegetation management	9		34		—		46
Coal reclamation	2		35		2		36
Palo Verde VIE (Note 7)	—		34		—		33
Deferred compensation	—		34		—		32
Deferred fuel and purchased power (a)	32		—		—		—
Tax expense of Medicare subsidy	2		18		2		21
Loss on reacquired debt	1		19		1		21
Pension and other post-retirement benefits deferral	—		9		—		—
Demand side management (a)	3		2		12		6
Other	—		21		—		18
Total regulatory assets (b)	$	87	$	978	$	62	$	986

(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.”

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

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	September 30, 2011				December 31, 2010
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	21	$	355	$	22	$	357
Asset retirement obligations (Note 15)	—		202		—		184
Renewable energy standard (b)	58		—		50		—
Income taxes — change in rates	—		50		—		—
Spent nuclear fuel	5		43		4		41
Deferred gains on utility property	2		15		2		16
Income taxes- deferred investment tax credit	—		9		—		1
Deferred fuel and purchased power (b)(c)	—		—		58		—
Other	8		15		3		15
Total regulatory liabilities	$	94	$	689	$	139	$	614

(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.

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates are deferred as a regulatory asset for future recovery, pursuant to an ACC regulatory order. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset) (dollars in 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,
	2011			2010			2011			2010			2011			2010			2011			2010
Service cost - benefits earned during the period	$	14		$	14		$	43		$	42		$	5		$	4		$	17		$	14
Interest cost on benefit obligation	31			31			94			92			12			11			35			32
Expected return on plan assets	(33		)	(31		)	(100		)	(93		)	(10		)	(9		)	(31		)	(29		)
Amortization of:
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	7			5			19			15			4			2			11			7
Net periodic benefit cost	$	19		$	19		$	57		$	57		$	11		$	8		$	32		$	24
Portion of cost charged to expense	$	7		$	10		$	22		$	29		$	4		$	4		$	12		$	12

Contributions

The required minimum contribution to our pension plan is zero in 2011 and approximately $68 million in 2012. The contributions to our other postretirement benefit plans for 2011 and 2012 are expected to be approximately $20 million each year.

5. Business Segments

Pinnacle West’s 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, 2011 and 2010 and at September 30, 2011 and December 31, 2010 is provided as follows (dollars in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Operating revenues:
Regulated electricity segment	$	1,124	$	1,116	$	2,571	$	2,527
All other	1		1		2		5
Total	$	1,125	$	1,117	$	2,573	$	2,532

Net income attributable to common shareholders:
Regulated electricity segment	$	246	$	225	$	318	$	320
All other (a)	9		9		9		23
Total	$	255	$	234	$	327	$	343

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	As of September 30, 2011		As of December 31, 2010
Assets:
Regulated electricity segment	$	13,112	$	12,285
All other (a)	38		108
Total	$	13,150	$	12,393

(a) All other activities relate to APSES, SunCor, Pinnacle West and El Dorado.

6. Income Taxes

The $68 million 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 cash refunds are not expected to be received in the next twelve months.

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. In the first quarter of 2011, Pinnacle West increased regulatory liabilities by a total of $53 million, with a corresponding decrease in accumulated deferred income tax liabilities to reflect the impact of this change in tax law.

As of the balance sheet date, 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 2006. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.

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. The VIE lessor trusts are single-asset leasing entities. APS will pay approximately $49 million per year for the years 2011 to 2015 related to these leases. The leases do not contain fixed price purchase options or residual value guarantees. However, the lease agreements include fixed rate renewal periods which may have a significant impact on the VIEs’ economic performance. We have concluded that these fixed rate renewal periods may give 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. In addition to the fixed rate renewal periods, our primary beneficiary analysis also considered that APS is the operating agent for Palo Verde, has fair value purchase options, and is obligated to decommission the leased assets.

For the reasons discussed above, APS consolidates these VIEs. 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,

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except in certain circumstances such as a default by APS under the lease. 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, 2011 of $7 million and of $20 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, 2011 and December 31, 2010 include the following amounts relating to the VIEs (in millions):

	September 30, 2011		December 31, 2010
Property plant and equipment, net of accumulated depreciation	$	134	$	138
Current maturities of long-term debt	30		29
Long-term debt less current maturities	83		97
Equity- Noncontrolling interests	109		91

For regulatory ratemaking purposes the agreements are treated as operating leases and, as a result, we have recorded a regulatory asset of $34 million as of September 30, 2011 and $33 million as of December 31, 2010.

APS is exposed to losses relating to these lessor trust 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, 2011, APS would have been required to pay the noncontrolling equity participants approximately $145 million and assume $113 million of debt. Since APS consolidates the VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

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 are 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, some of these instruments may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Contracts that have the same terms (quantities and delivery points) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

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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 purchase 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 accumulated other comprehensive income (“AOCI”) 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 of September 30, 2011, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

For its regulated operations, APS defers 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. 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, 2011, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	11,997	gigawatt hours
Gas	124,151	billion Btu (a)

(a) “Btu” is British thermal units.

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, 2011 and 2010 (dollars in thousands):

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	Financial Statement	Three Months Ended September 30,						Nine Months Ended September 30,
Commodity Contracts	Location	2011			2010			2011			2010

Loss Recognized in AOCI (Effective Portion)	Accumulated other comprehensive loss-derivative instruments	$	(25,457	)	$	(67,856	)	$	(40,792	)	$	(168,110	)
Loss Reclassified from AOCI into Income (Effective Portion Realized)	Regulated electricity segment fuel and purchased power	(59,144		)	(59,801		)	(99,278		)	(102,130		)
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)	Regulated electricity segment fuel and purchased power	17			(68		)	(147		)	1,364

(a) During the three and nine months ended September 30, 2011 and 2010, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.

During the next twelve months, we estimate that a net loss of $68 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, certain of these amounts will be recorded as either a regulatory asset or liability and have no 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, 2011 and 2010 (dollars in thousands):

	Financial Statement	Three Months Ended September 30,						Nine Months Ended September 30,
Commodity Contracts	Location	2011			2010			2011			2010

Net Gain Recognized in Income	Regulated electricity segment revenue	$	81		$	1,721		$	1,085		$	2,316

Net Loss Recognized in Income	Regulated electricity segment fuel and purchased power expense	(13,219		)	(41,044		)	(25,138		)	(105,272		)
Total		$	(13,138	)	$	(39,323	)	$	(24,053	)	$	(102,956	)

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 contractual net settlement provisions 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, 2011 (dollars in thousands):

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Commodity Contracts	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Margin and Collateral Provided to Counterparties		Collateral Provided from Counterparties			Other (a)			Total
Current Assets	$	6,608		$	64,177		$	1,529	$	—		$	(44,601	)	$	27,713
Investments and Other Assets	2,700			40,918			—		—			(11,302		)	32,316
Total Assets	9,308			105,095			1,529		—			(55,903		)	60,029

Current Liabilities	(61,134		)	(110,437		)	77,002		(12,145		)	46,047			(60,667		)
Deferred Credits and Other	(45,393		)	(65,365		)	40,711		—			11,302			(58,745		)
Total Liabilities	(106,527		)	(175,802		)	117,713		(12,145		)	57,349			(119,412		)
Total	$	(97,219	)	$	(70,707	)	$	119,242	$	(12,145	)	$	1,446		$	(59,383	)

(a) Other represents derivative instrument netting, options, and other risk management contracts.

The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2010 (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 (a)			Total
Current Assets	$	10,295		$	64,153		$	36,135	$	(1,750	)	$	(35,045	)	$	73,788
Investments and Other Assets	5,056			60,813			—		—			(26,837		)	39,032
Total Assets	15,351			124,966			36,135		(1,750		)	(61,882		)	112,820

Current Liabilities	(108,387		)	(112,847		)	126,364		(1,250		)	37,144			(58,976		)
Deferred Credits and Other	(73,041		)	(85,506		)	66,393		—			26,764			(65,390		)
Total Liabilities	(181,428		)	(198,353		)	192,757		(1,250		)	63,908			(124,366		)
Total	$	(166,077	)	$	(73,387	)	$	228,892	$	(3,000	)	$	2,026		$	(11,546	)

(a) Other represents derivative instrument netting, options, 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 76% of Pinnacle West’s $60 million of risk management assets as of September 30, 2011. 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

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quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

The following table provides information about our derivative instruments that have credit-risk-related contingent features at September 30, 2011 (dollars in millions):

	September 30, 2011
Aggregate Fair Value of Derivative Instruments in a Net Liability Position	$	254
Cash Collateral Posted	99
Additional Cash Collateral in the Event Credit-Risk Related Contingent Features were Fully Triggered (a)	136

(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the footnote 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 $194 million if our debt credit ratings were to fall below investment grade.

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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, 2011 and 2010 (dollars in thousands):

	Three Months Ended September 30, 2011									Three Months Ended September 30, 2010
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total

Beginning balance, July 1	$	3,613,705		$	101,905		$	3,715,610		$	3,479,548		$	113,455		$	3,593,003

Net income	255,359			7,426			262,785			233,920			5,119			239,039
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)	(25,457		)	—			(25,457		)	(67,856		)	—			(67,856		)
Net reclassification of realized losses to income (b)	59,144			—			59,144			59,801			—			59,801
Reclassification of pension and other postretirement benefits to income	1,239			—			1,239			1,314			—			1,314
Net income tax benefit (expense) related to items of other comprehensive income (loss)	(13,795		)	—			(13,795		)	2,660			—			2,660
Total other comprehensive income (loss)	21,131			—			21,131			(4,081		)	—			(4,081		)
Total comprehensive income	276,490			7,426			283,916			229,839			5,119			234,958

Issuance of capital stock	3,789			—			3,789			2,506			—			2,506
Purchase of treasury stock, net of reissuances	537			—			537			577			—			577
Other (primarily stock compensation)	(424		)	—			(424		)	4,456			—			4,456
Dividends on common stock	(12		)	—			(12		)	—			—			—
Net capital activities by noncontrolling interests	—			(421		)	(421		)	—			(7,271		)	(7,271		)
Ending balance, September 30	$	3,894,085		$	108,910		$	4,002,995		$	3,716,926		$	111,303		$	3,828,229

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	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2010
	Common Shareholders			Noncontrolling Interests			Total			Common Shareholders			Noncontrolling Interests			Total

Beginning balance, January 1	$	3,683,327		$	91,899		$	3,775,226		$	3,316,109		$	111,895		$	3,428,004

Net income	326,909			20,041			346,950			342,703			15,005			357,708
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)	(40,792		)	—			(40,792		)	(168,110		)	—			(168,110		)
Net reclassification of realized losses to income (b)	99,278			—			99,278			102,130			—			102,130
Reclassification of pension and other postretirement benefits to income	3,718			—			3,718			4,069			—			4,069
Net unrealized gains (losses) related to pension and other postretirement benefits	974			—			974			(6,933		)	—			(6,933		)
Net income tax benefit (expense) related to items of other comprehensive income (loss)	(24,954		)	—			(24,954		)	27,171			—			27,171
Total other comprehensive income (loss)	38,224			—			38,224			(41,673		)	—			(41,673		)
Total comprehensive income	365,133			20,041			385,174			301,030			15,005			316,035

Issuance of capital stock	20,854			—			20,854			260,665			—			260,665
Purchase of treasury stock, net of reissuances	(2,993		)	—			(2,993		)	1,655			—			1,655
Other (primarily stock compensation)	(606		)	—			(606		)	4,598			—			4,598
Dividends on common stock	(171,630		)	—			(171,630		)	(167,131		)	—			(167,131		)
Net capital activities by noncontrolling interests	—			(3,030		)	(3,030		)	—			(15,597		)	(15,597		)
Ending balance, September 30	$	3,894,085		$	108,910		$	4,002,995		$	3,716,926		$	111,303		$	3,828,229

(a) These amounts primarily include unrealized losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.

(b) These amounts primarily include the reclassification of unrealized losses to realized losses for contracted commodities delivered during the period. In accordance with the PSA, certain of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

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10. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

APS currently estimates it will incur $122 million (in 2011 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, 2011, APS had a regulatory liability of $48 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 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 $46 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, 2011, certain contractual obligations have increased approximately $0.75 billion from December 31, 2010 as discussed in the 2010 Form 10-K. The updated contractual obligations are as follows (dollars in billions):

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Year	2011		2012		2013		2014		2015		Thereafter		Total
Purchase obligations (a)	$	—	$	—	$	0.10	$	—	$	—	$	0.15	$	0.25
Fuel and purchased power commitments	0.20		—		0.05		—		—		—		0.25
Renewable energy credits	—		—		—		—		—		0.25		0.25

(a) Payments for the transmission rights-of-way are subject to change based on changes in the Consumer Price Index.

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.

This hearing has been held in abeyance to provide an opportunity for the parties to engage in settlement negotiations. 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. 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 $1 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.

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Southwest Power Outage

On September 8, 2011 at approximately 3:30PM, a 500 kilovolt 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 2.8 million customers (1.6 million in the United States and 1.2 million in northern Mexico) were reported to have been affected. Service to all affected APS customers was restored by 9:15PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9.

APS has begun an internal review of the September 8 events. In addition:

· the FERC and the North American Electric Reliability Corporation (“NERC”) are conducting a joint inquiry into the outages; and

· the California Independent System Operator Corporation (“Cal ISO”) initiated a joint task force to investigate the outages. Utilities impacted by the outages, including APS, San Diego Gas & Electric Company, Southern California Edison Company (“SCE”), Imperial Irrigation District, Western Area Power Administration and Comisión Federal de Electricidad of Mexico, have been asked to participate in the task force.

FERC and NERC stated that their inquiries will coordinate with any reviews by the Department of Energy and other federal agencies, the Cal ISO, the Western Electric Coordinating Council, and California and Arizona state regulators.

APS cannot predict the timing, results or potential impacts of any of the inquiries into the September 8 events, or any other 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 the violation is found to have been in existence.

New Source Review

On May 7, 2010, APS received a Notice of Intent to Sue from EarthJustice (the “Notice”), on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at the Four Corners Power Plant (“Four Corners”). The Notice alleges New Source Review-related violations and New Source Performance Standards (“NSPS”) violations. Under the Clean Air Act, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit. Within that 60-day time period, the EPA may step in and file a lawsuit regarding the allegations. If the EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in the EPA’s lawsuit, if it so desires. The 60-day period lapsed in early July 2010, and the EPA did not take any action.

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On September 2, 2011, APS received a second Notice of Intent to Sue from EarthJustice (the “Second Notice”), and on October 26, 2011, APS received a Third Notice of Intent to Sue from EarthJustice (the “Third Notice”), on behalf of the same environmental organizations. The Second Notice and Third Notice are virtually identical to the May 2010 Notice and allege violations of the New Source Review and NSPS programs.

On October 3, 2011, EarthJustice 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. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. APS is evaluating the lawsuit and cannot currently predict the outcome of the case.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2011, approximately $44 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit expire in 2013 and 2016. APS has also entered into letters of credit to support 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 2013, and at September 30, 2011, totaled approximately $52 million. Additionally, APS has issued a letter of credit to support the collateral obligations under a certain natural gas tolling contract entered into with a third party. At September 30, 2011, $10 million of letters of credit were outstanding to support this tolling contract obligation. This letter of credit will expire in 2016. We expect to renew expiring letters of credit in the ordinary course of business.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

Pinnacle West sold its investment in APSES on August 19, 2011. Upon the closing of the sale, Pinnacle West was released from its parental guarantee and surety bond obligations related to the APSES business. Pinnacle West has also issued parental guarantees and surety bonds for APS which were not material at September 30, 2011.

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, 2011 and 2010 (dollars in thousands):

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Other income:
Interest income	$	429		$	833		$	1,364		$	2,597
Investment gains — net	—			3,413			1,249			1,074
Miscellaneous	12			15			17			180
Total other income	$	441		$	4,261		$	2,630		$	3,851

Other expense:
Non-operating costs	$	(1,807	)	$	(2,933	)	$	(4,925	)	$	(6,035	)
Investment losses — net	(57		)	—			—			—
Miscellaneous	(1,188		)	(961		)	(2,996		)	(2,733		)
Total other expense	$	(3,052	)	$	(3,894	)	$	(7,921	)	$	(8,768	)

12. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	2.25	$	2.07	$	2.90	$	3.02
Income from discontinued operations	0.09		0.08		0.10		0.22
Earnings per share — basic	$	2.34	$	2.15	$	3.00	$	3.24

Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	2.24	$	2.06	$	2.88	$	3.01
Income from discontinued operations	0.08		0.08		0.10		0.21
Earnings per share — diluted	$	2.32	$	2.14	$	2.98	$	3.22

Dilutive stock options and performance shares (which are contingently issuable) increased average diluted common shares outstanding by approximately 733,000 shares and 462,000 shares for the three months ended September 30, 2011 and 2010, respectively, and by approximately 680,000 and 472,000 shares for the nine months ended September 30, 2011 and 2010, respectively.

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For the three-month and nine-month periods ended September 30, 2011, there were no options to purchase shares of common stock outstanding that were excluded from the computation of diluted earnings per share as a result of the options’ exercise prices being greater than the average market price of the common shares. For the three-month and nine-month periods ended September 30, 2010, options to purchase 175,333 shares and 322,333, respectively, of common stock were outstanding but were excluded from the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares.

13. Discontinued Operations

SunCor (real estate segment) — In July 2010, SunCor sold land parcels, commercial assets and a master planned home-building community for approximately $70 million, which approximated the carrying value of these assets, resulting in a net gain of zero. All activity for the income statement and prior comparative period income statement amounts are included in discontinued operations. In 2010, SunCor recorded real estate impairment charges totaling $17 million in the first and second quarter.

APSES (other) — 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. In June 2010, APSES sold its district cooling business consisting of operations in downtown Phoenix, Tucson, and on certain Arizona State University campuses. As a result of that sale, we recorded an after-tax gain from discontinued operations of approximately $25 million. Prior period income statement amounts related to these sales 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, 2011 and 2010 (dollars in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
Revenue:
SunCor	$	1		$	4	$	4		$	25
APSES	11			22		36			55
Total revenue	$	12		$	26	$	40		$	80

Income (loss) before taxes:
SunCor	$	(2	)	$	14	$	(2	)	$	(10	)
APSES	18			1		20			48
Total income before taxes	$	16		$	15	$	18		$	38

Income (loss) after taxes:
SunCor (a)	$	(1	)	$	8	$	(1	)	$	(6	)
APSES	10			1		12			29
Total income after taxes	$	9		$	9	$	11		$	23

(a) Includes a tax benefit (expense) recognized by the parent company in accordance with an intercompany tax sharing agreement of $1 million and $(6) million for the three months ended September 30, 2011 and 2010, respectively; $1 million and $4 million for the nine months ended September 30, 2011 and 2010, respectively.

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 nuclear decommissioning trust 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, and swaps. This category also includes investments in common 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 models are required 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. 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 transactions, 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 transactions, 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 2010 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

Cash equivalents represent short-term investments in exchange traded money market funds that are valued using quoted prices in active markets.

Risk Management Activities - Derivative Instruments

Exchange traded contracts are valued using quoted prices in active markets. For non-exchange traded 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 based on the financial condition of counterparties. 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 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. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and heat rate options, and is not reflective of material inactive markets.

Investments Held in our Nuclear Decommissioning Trust

The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued based on the fund’s NAV and are classified within Level 2. We may transact in these commingled funds on a semi-monthly basis. 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. Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. See Note 17 for additional discussion about our nuclear decommissioning trust.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at September 30, 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 September 30, 2011
Assets
Cash Equivalents	$	401	$	—		$	—		$	—		$	401
Risk management activities-derivative instruments:
Commodity contracts	—		59			54			(53		)(b)	60
Nuclear decommissioning trust:
U.S. commingled equity funds	—		154			—			—			154
Fixed income securities:
U.S. Treasury	80		—			—			—			80
Cash and cash equivalent funds	—		12			—			2		(c)	14
Corporate debt	—		64			—			—			64
Mortgage-backed securities	—		76			—			—			76
Municipality bonds	—		81			—			—			81
Other	—		20			—			—			20
Subtotal nuclear decommissioning trust	80		407			—			2			489
Total	$	481	$	466		$	54		$	(51	)	$	950

Liabilities
Risk management activities - derivative instruments:
Commodity contracts	$	—	$	(189	)	$	(92	)	$	162	(b)	$	(119	)

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

(b) Represents counterparty netting, margin and collateral (see Note 8).

The following table presents the fair value at December 31, 2010 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	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, 2010
Assets
Cash equivalents	$	35		$	—		$	—		$	—		$	35
Risk management activities-derivative instruments:
Commodity contracts	—			80			61			(28		)(b)	113
Nuclear decommissioning trust:
U.S. commingled equity funds	—			168			—			—			168
Fixed income securities:
U.S. Treasury	50			—			—			—			50
Cash and cash equivalent funds	—			22			—			—			22
Corporate debt	—			60			—			—			60
Mortgage-backed securities	—			81			—			—			81
Municipality bonds	—			79			—			—			79
Other	—			20			—			(10		)(c)	10
Subtotal nuclear decommissioning trust	50			430			—			(10		)	470
Total	$	85		$	510		$	61		$	(38	)	$	618

Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	(1	)	$	(280	)	$	(99	)	$	256	(b)	$	(124	)

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

(b) Represents counterparty netting, margin and collateral (see Note 8).

The following table shows the changes in fair value for 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, 2011 and 2010 (dollars in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended September 30,						Nine Months Ended September 30,
Commodity Contracts	2011			2010			2011			2010
Net derivative balance at beginning of period	$	(47	)	$	(42	)	$	(38	)	$	(10	)
Total net gains (losses) realized/unrealized:
Included in earnings	1			1			2			(1		)
Included in other comprehensive income (“OCI”)	2			(11		)	1			(20		)
Deferred as a regulatory asset or liability	2			(15		)	(4		)	(39		)
Settlements	6			12			10			15
Transfers into Level 3 from Level 2	—			(2		)	(4		)	6
Transfers from Level 3 into Level 2	(2		)	8			(5		)	—
Net derivative balance at end of period	$	(38	)	$	(49	)	$	(38	)	$	(49	)

Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	1		$	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 significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our heat rate options and long-dated energy transactions that extend beyond available quoted periods.

Nonrecurring Fair Value Measurements

For the periods ended September 30, 2011 and 2010, we had no assets or liabilities measured at fair value on a nonrecurring basis.

Other Financial Instruments

The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. For our long-term debt fair values, see Note 2.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

15. Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. In the first quarter of 2011, a new decommissioning study with updated cash flow estimates was completed for Palo Verde. This study reflects the twenty-year license extension approved by the NRC on April 21, 2011, which extends the commencement of decommissioning to 2045. The new study resulted in a $90 million decrease to the liability for asset retirements, a $78 million decrease to electric plant in service, and a $12 million increase to regulatory liabilities.

16. New Accounting Standards

In May 2011, the Financial Accounting Standards Board (“FASB”) issued amended guidance to converge fair value measurement and disclosure requirements for U.S. 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 guidance is effective for us on January 1, 2012. We are currently evaluating this guidance and the impact, if any, it may have on our financial statements.

In June 2011, the FASB issued amended guidance on the presentation of comprehensive income intended to increase the prominence of items reported in other comprehensive income and to facilitate convergence with IFRS. The amended guidance requires entities to present total comprehensive income, which includes components of net income and components of other comprehensive income, in either a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance is currently effective for us on January 1, 2012; however, the FASB is considering delaying the effective date for certain aspects of the standard relating to the presentation of reclassification adjuments. This guidance will change our presentation of comprehensive income, but will not impact our financial statement results.

17. 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 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 summarizes the fair value of APS’s nuclear decommissioning trust fund assets at September 30, 2011 and December 31, 2010 (dollars in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Fair Value		Total Unrealized Gains		Total Unrealized Losses
September 30, 2011
Equity securities	$	154	$	31	$	(5	)
Fixed income securities	333		23		(1		)
Net receivables (a)	2		—		—
Total	$	489	$	54	$	(6	)

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

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
December 31, 2010
Equity securities	$	168		$	43	$	(1	)
Fixed income securities	312			12		(2		)
Net payables (a)	(10		)	—		—
Total	$	470		$	55	$	(3	)

(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,
	2011			2010		2011			2010
Realized gains	$	3		$	1	$	6		$	15
Realized losses	(1		)	—		(4		)	(3		)
Proceeds from the sale of securities (a)	106			94		406			424

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2011 is as follows (dollars in millions):

	Fair Value
Less than one year	$	16
1 year -5 years	78
5 years - 10 years	114
Greater than 10 years	125
Total	$	333

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended September 30,
	2011			2010

ELECTRIC OPERATING REVENUES	$	1,124,057		$	1,116,220

OPERATING EXPENSES
Fuel and purchased power	337,897			353,904
Operations and maintenance	207,967			217,044
Depreciation and amortization	106,326			104,152
Income taxes	145,230			126,841
Taxes other than income taxes	33,854			37,270
Total	831,274			839,211
OPERATING INCOME	292,783			277,009

OTHER INCOME (DEDUCTIONS)
Income taxes	9,422			1,272
Allowance for equity funds used during construction	7,377			5,524
Other income (Note S-2)	617			2,962
Other expense (Note S-2)	(3,045		)	(4,074		)
Total	14,371			5,684

INTEREST EXPENSE
Interest on long-term debt	56,314			53,946
Interest on short-term borrowings	2,846			2,013
Debt discount, premium and expense	1,164			1,121
Allowance for borrowed funds used during construction	(6,938		)	(6,163		)
Total	53,386			50,917

NET INCOME	253,768			231,776

Less: Net income attributable to noncontrolling interests (Note 7)	7,435			5,128

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	246,333		$	226,648

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,
	2011			2010

ELECTRIC OPERATING REVENUES	$	2,570,737		$	2,527,163

OPERATING EXPENSES
Fuel and purchased power	793,952			821,244
Operations and maintenance	669,170			632,235
Depreciation and amortization	319,477			307,731
Income taxes	193,485			177,089
Taxes other than income taxes	110,892			100,171
Total	2,086,976			2,038,470
OPERATING INCOME	483,761			488,693

OTHER INCOME (DEDUCTIONS)
Income taxes	9,647			3,769
Allowance for equity funds used during construction	18,697			16,417
Other income (Note S-2)	3,828			3,872
Other expense (Note S-2)	(11,288		)	(11,091		)
Total	20,884			12,967

INTEREST EXPENSE
Interest on long-term debt	165,805			161,918
Interest on short-term borrowings	7,675			5,734
Debt discount, premium and expense	3,485			3,376
Allowance for borrowed funds used during construction	(14,371		)	(12,254		)
Total	162,594			158,774

NET INCOME	342,051			342,886

Less: Net income attributable to noncontrolling interests (Note 7)	20,089			15,034

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	321,962		$	327,852

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,
	2011			2010
ASSETS

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	13,419,495		$	13,197,254
Accumulated depreciation and amortization	(4,681,247		)	(4,510,591		)
Net	8,738,248			8,686,663

Construction work in progress	618,728			459,316
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	133,832			137,956
Intangible assets, net of accumulated amortization	176,246			184,768
Nuclear fuel, net of accumulated amortization	134,232			108,794
Total property, plant and equipment	9,801,286			9,577,497

INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 17)	488,551			469,886
Assets from risk management activities (Note 8)	32,316			39,032
Other assets	29,591			71,428
Total investments and other assets	550,458			580,346

CURRENT ASSETS
Cash and cash equivalents	555,035			99,937
Customer and other receivables	358,809			288,323
Accrued unbilled revenues	184,169			103,292
Allowance for doubtful accounts	(4,126		)	(7,646		)
Materials and supplies (at average cost)	203,118			181,414
Fossil fuel (at average cost)	25,403			21,575
Assets from risk management activities (Note 8)	27,713			73,788
Regulatory assets (Note 3)	55,852			62,286
Deferred fuel and purchased power regulatory asset (Note 3)	31,611			—
Deferred income taxes	87,877			105,042
Other current assets	28,626			25,135
Total current assets	1,554,087			953,146

DEFERRED DEBITS
Regulatory assets (Note 3)	977,975			986,370
Income tax receivable (Note 6)	68,596			65,498
Unamortized debt issue costs	21,681			20,530
Other	100,622			88,490
Total deferred debits	1,168,874			1,160,888

TOTAL ASSETS	$	13,074,705		$	12,271,877

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,
	2011			2010
LIABILITIES AND EQUITY

CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital	2,379,696			2,379,696
Retained earnings	1,553,752			1,403,390
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(33,215		)	(35,961		)
Derivative instruments	(64,954		)	(100,334		)
Total shareholder equity	4,013,441			3,824,953
Noncontrolling interests (Note 7)	108,564			91,084
Total equity	4,122,005			3,916,037
Long-term debt less current maturities	2,828,457			2,948,991
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	83,130			96,803
Total capitalization	7,033,592			6,961,831

CURRENT LIABILITIES
Current maturities of long-term debt	876,363			456,879
Accounts payable	274,601			218,491
Accrued taxes (Note 6)	192,208			106,431
Accrued interest	55,736			54,638
Customer deposits	71,772			68,312
Liabilities from risk management activities (Note 8)	60,667			58,976
Deferred fuel and purchased power regulatory liability (Note 3)	—			58,442
Other regulatory liabilities (Note 3)	94,374			80,526
Other current liabilities	132,737			132,170
Total current liabilities	1,758,458			1,234,865

DEFERRED CREDITS AND OTHER
Deferred income taxes	1,991,403			1,895,654
Regulatory liabilities (Note 3)	689,120			614,063
Liability for asset retirements (Note 15)	258,332			328,571
Liabilities for pension and other postretirement benefits (Note 4)	836,230			770,611
Liabilities from risk management activities (Note 8)	58,745			65,390
Customer advances	112,730			121,645
Coal mine reclamation	117,779			117,243
Unrecognized tax benefits (Note 6)	76,740			65,363
Other	141,576			96,641
Total deferred credits and other	4,282,655			4,075,181

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

TOTAL LIABILITIES AND EQUITY	$	13,074,705		$	12,271,877

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,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	342,051		$	342,886
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	369,999			349,267
Deferred fuel and purchased power	30,965			50,020
Deferred fuel and purchased power amortization	(121,018		)	(95,926		)
Allowance for equity funds used during construction	(18,697		)	(16,417		)
Deferred income taxes	135,789			218,575
Change in mark-to-market valuations	1,861			3,716
Changes in current assets and liabilities:
Customer and other receivables	(50,147		)	(93,394		)
Accrued unbilled revenues	(80,877		)	(69,035		)
Materials, supplies and fossil fuel	(25,532		)	19,011
Other current assets	(3,836		)	(9,968		)
Accounts payable	42,257			37,150
Accrued taxes	86,032			16,141
Other current liabilities	18,931			2,124
Change in margin and collateral accounts — assets	33,591			(4,336		)
Change in margin and collateral accounts — liabilities	85,785			(143,725		)
Change in unrecognized tax benefits	12,839			(72,217		)
Change in other long-term assets	(10,198		)	(60,775		)
Change in other long-term liabilities	83,301			32,686
Net cash flow provided by operating activities	933,096			505,783
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(637,181		)	(552,331		)
Contributions in aid of construction	36,351			25,258
Allowance for borrowed funds used during construction	(14,371		)	(12,254		)
Proceeds from sale of life insurance policies	44,183			—
Proceeds from nuclear decommissioning trust sales	405,637			424,255
Investment in nuclear decommissioning trust	(417,957		)	(442,567		)
Other	(2,346		)	9,621
Net cash flow used for investing activities	(585,684		)	(548,018		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	295,353			—
Repayment of long-term debt	(13,457		)	(9,538		)
Equity infusion	—			252,833
Dividends paid on common stock	(171,600		)	(156,300		)
Noncontrolling interests	(2,610		)	(3,286		)
Net cash flow provided by financing activities	107,686			83,709
NET INCREASE IN CASH AND CASH EQUIVALENTS	455,098			41,474
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	99,937			120,798
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	555,035		$	162,272
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	7,493		$	76,364
Interest, net of amounts capitalized	$	158,011		$	157,385

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	—
Asset Retirement Obligations	Note 15	—
New Accounting Standards	Note 16	—
Nuclear Decommissioning Trust	Note 17	—

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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, 2011 and 2010 (dollars in thousands):

	Three Months Ended September 30, 2011								Three Months Ended September 30, 2010
	Shareholder Equity			Noncontrolling Interests		Total			Shareholder Equity			Noncontrolling Interests		Total

Beginning balance, July 1	$	3,746,067		$	101,128	$	3,847,195		$	3,605,292		$	88,944	$	3,694,236

Net income	246,333			7,435		253,768			226,648			5,128		231,776
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)	(25,457		)	—		(25,457		)	(67,856		)	—		(67,856		)
Net reclassification of realized losses to income (b)	59,144			—		59,144			59,801			—		59,801
Reclassification of pension and other postretirement benefits to income	1,091			—		1,091			1,172			—		1,172
Net income tax benefit (expense) related to items of other comprehensive income (loss)	(13,740		)	—		(13,740		)	2,717			—		2,717
Total other comprehensive income (loss)	21,038			—		21,038			(4,166		)	—		(4,166		)
Total comprehensive income	267,371			7,435		274,806			222,482			5,128		227,610

Other	3			1		4			—			1		1
Ending balance, September 30	$	4,013,441		$	108,564	$	4,122,005		$	3,827,774		$	94,073	$	3,921,847

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2010
	Shareholder Equity			Noncontrolling Interests			Total			Shareholder Equity			Noncontrolling Interests			Total

Beginning balance, January 1	$	3,824,953		$	91,084		$	3,916,037		$	3,445,355		$	82,324		$	3,527,679

Net income	321,962			20,089			342,051			327,852			15,034			342,886
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)	(40,792		)	—			(40,792		)	(168,110		)	—			(168,110		)
Net reclassification of realized losses to income (b)	99,278			—			99,278			102,130			—			102,130
Reclassification of pension and other postretirement benefits to income	3,272			—			3,272			3,499			—			3,499
Net unrealized gains (losses) related to pension benefits	1,268			—			1,268			(6,863		)	—			(6,863		)
Net income tax benefit (expense) related to items of other comprehensive income (loss)	(24,900		)	—			(24,900		)	27,377			—			27,377
Total other comprehensive income (loss)	38,126			—			38,126			(41,967		)	—			(41,967		)
Total comprehensive income	360,088			20,089			380,177			285,885			15,034			300,919

Dividends on common stock	(171,600		)	—			(171,600		)	(156,300		)	—			(156,300		)
Equity infusion	—			—			—			252,833			—			252,833
Net capital activities by noncontrolling interests	—			(2,610		)	(2,610		)	—			—			—
Other	—			1			1			1			(3,285		)	(3,284		)
Ending balance, September 30	$	4,013,441		$	108,564		$	4,122,005		$	3,827,774		$	94,073		$	3,921,847

(b) These amounts primarily include the reclassification of unrealized losses to realized losses for contracted commodities delivered during the period.

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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, 2011 and 2010 (dollars in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Other income:
Interest income	$	93		$	373		$	312		$	2,653
Investment gains — net	—			2,574			1,418			1,038
Miscellaneous	524			15			2,098			181
Total other income	$	617		$	2,962		$	3,828		$	3,872

Other expense:
Non-operating costs	$	(1,922	)	$	(2,969	)	$	(6,136	)	$	(6,453	)
Asset dispositions	(215		)	(186		)	(1,038		)	(395		)
Miscellaneous	(908		)	(919		)	(4,114		)	(4,243		)
Total other expense	$	(3,045	)	$	(4,074	)	$	(11,288	)	$	(11,091	)

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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 2010 Form 10-K, Part I, Item 1A of the Second Quarter 10-Q and Part II, Item 1A of this Report.

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 substantially 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 applied for twenty-year extensions of its operating licenses for each of the three Palo Verde units in December 2008. On April 21, 2011, the NRC approved the extensions of the Palo Verde licenses.

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 potential legislation and increased regulation concerning greenhouse gas emissions. Recent 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 legislation and regulation 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 coal-fired plant. On November 8, 2010, APS and SCE entered into an asset purchase agreement 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, which would be expected to occur in the second half of 2012, is subject to the receipt of approvals by the ACC, the California Public Utilities Commission and the FERC. APS and SCE filed applications with their respective commissions seeking requisite authority to complete the transaction. Hearings at the ACC concluded on September 1, 2011. We expect the administrative law judge to issue a recommended decision by the end of this year or early next year. Closing is also conditioned on the execution of a new coal supply contract for the lease renewal period described below,

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expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and other typical closing conditions.

APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation which would extend the Four Corners leasehold interest to 2041. Execution by the Navajo Nation of the lease amendments is a condition to closing of the purchase by APS of SCE’s interest in Four Corners. The execution of these amendments by the Navajo Nation requires the approval of the Navajo Nation Council. The amendments were approved by the Navajo Nation Council on February 15, 2011 and signed by the Nation’s President on March 7, 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 will be conducted as part of the DOI review process.

Pursuant to a Co-Tenancy Agreement among the Four Corners participants, the other participants have a right of first refusal to purchase shares of SCE’s interests proportional to their current ownership percentages. The exercise of this purchase right by any of the other participants expired on March 8, 2011 and none of the other participants exercised this right.

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 would 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 applying for approval to purchase SCE’s interest in Units 4 and 5, APS also requested from the ACC recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3.

APS cannot predict whether all of the conditions necessary to consummate the purchase of SCE’s interest will be met such that closing can occur, including whether the parties will receive satisfactory regulatory approvals.

Transmission and Delivery. APS’s 2011 Ten-Year Transmission Plan filed with the ACC in January 2011 projects that it will invest approximately $450 million in new transmission projects (115 kV and above) over the next ten years, adding 258 miles of new lines. The first three years of these additional line miles are included in the capital expenditures table presented in the “Liquidity” section below along with other transmission costs for new subtransmission projects (69 kV) and transmission 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% of retail electric sales in 2011 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 10% of APS’s retail energy sales by year-end 2015, which is double the existing RES target of 5% for that year. See Note 3. A component of the RES is focused on stimulating

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development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

For a table summarizing APS’s renewable energy portfolio, see “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Current and Future Resources — Renewable Energy Standard” in Part I, Item 1 of the 2010 Form 10-K. Since that time, third-party owned distributed energy resources in operation have grown by 41 MW and third-party owned distributed energy resources planned or under development have increased by 20 MW. Additionally, since June 30, 2011, 34 MW developed under the AZ Sun Program (see Note 3) and a 5 MW solar facility under a purchased power contract began commercial operation. Biomass resources from purchased power agreements decreased 6 MW mainly due to the expiration of a short-term contract.

On April 5, 2011, APS issued its 2011 Small Generation request for proposals to solicit for a broad base of renewable technology projects between 2 MW and 15 MW. APS continues to actively consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the Renewable Energy Standard and to meet the needs of its customer base.

On July 1, 2011, APS filed its annual RES implementation plan with the ACC, covering the 2012-2016 timeframe and requesting 2012 RES funding of $129 million to $152 million. The range in the funding request arises from APS offering several options for third-party initiatives. The options involve obtaining 150 MW from third-parties entirely through PPAs or through a mix of PPAs and non-residential distributed energy programs. APS also proposed (i) an additional 100 MW of APS-owned AZ Sun projects; (ii) permission to recover costs for a 19 MW AZ Sun project now instead of waiting for a recovery mechanism in APS’s current retail rate case; and (iii) an additional 25 MW of APS-owned systems on school and government facilities. On October 26, 2011, the ACC staff issued a report recommending an RES budget of $131.7 million, including the addition of 100 MW of APS-owned AZ Sun projects, permission to recover costs for a 19 MW AZ Sun project through the 2012 RES, and an additional 15 MW of APS-owned systems on school and government facilities. APS cannot predict whether the ACC will approve the plan as filed, or as recommended by the ACC staff. APS expects a decision from the ACC by year end.

On October 3, 2011, APS issued a request for proposals to construct a 17 MW solar photovoltaic facility under its AZ Sun Program which is planned to be in-service by 2013. This request is expected to fulfill the first 100 MW authorized under AZ Sun to develop utility-scale solar facilities which will be owned and operated by APS.

Energy Efficiency. Arizona regulators are placing 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 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. On July 27, 2010, the proposed Energy Efficiency Standard was adopted by the ACC, approved by the Arizona Attorney General and became effective on January 1, 2011. This ambitious standard will likely impact Arizona’s future energy resource needs. On June 1, 2011 APS filed its 2012 Energy Efficiency Implementation Plan with a proposed budget for 2012 of $90 million. APS cannot predict whether the ACC will approve the plan as filed.

Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. At the end of 2009, the ACC approved a settlement agreement entered into by APS and other parties to APS’s 2008 general retail rate case. The settlement demonstrated 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. Consistent with this rate

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case filing plan, on June 1, 2011, APS filed a rate case with the ACC requesting, among other things, an increase in retail rates to allow APS to continue to maintain and upgrade its electric systems for enhanced reliability, approval of recovery mechanisms, including a decoupling mechanism described below, and approval of other programs and mechanisms aimed at energy efficiency and renewable energy. See Note 3 for details regarding the current rate case, 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.

On December 15, 2010, the ACC unanimously approved a decoupling policy statement supportive of using a revenue-per-customer methodology, which is the mechanism APS supports. Decoupling refers to a ratemaking design which reduces or removes the linkage between sales and utility revenues and/or profits, reducing utility disincentives to the adoption of programs that benefit customers by saving energy. Mechanically, decoupling compares actual versus authorized revenues or revenue per customer over a period and either credits or collects any differences from customers in a subsequent period. The policy permits regulated utilities to file a decoupling proposal in their next general rate case. APS included in its current general rate case filing a decoupling model consistent with the policy statement and other mechanisms to more timely recover capital and operating costs. APS cannot predict the outcome of the rate case or whether the ACC will approve the various APS requests.

Financial Strength and Flexibility. Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities and have been able to access these facilities and the commercial paper markets, ensuring adequate liquidity for each company. In early February 2011, APS entered into a $500 million revolving credit facility, replacing its $489 million revolving credit facility that would have otherwise matured in September 2011.

APSES. On August 19, 2011, Pinnacle West sold its investment in APSES. The sale resulted in an after-tax gain of approximately $10 million.

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 reduce its outstanding debt. At September 30, 2011, SunCor had total remaining assets of about $10 million.

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 2008 through 2010, 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

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per customer and the impacts of energy efficiency programs, 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, 2011 was 0.4% compared with the prior year period. For the three years 2008 through 2010, APS’s customer growth averaged 0.9% per year. We currently expect customer growth to average about 1% per year for 2011 through 2013 based on our assessment of the modestly improving economic conditions, both nationally and in Arizona. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for the nine-month period ended September 30, 2011 increased 0.5% compared to the same period in the prior year, reflecting the mildly improving economic conditions, partially offset by the effects of our energy efficiency programs. For the three years 2008 through 2010, APS’s actual retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, declined at an average annual rate of 0.9%. We currently estimate that total annual retail electricity sales in kilowatt-hours will remain flat on average during 2011 through 2013, including the effects of APS’s energy efficiency programs, but excluding the effects of weather variations. The failure of the Arizona economy to rebound in the near future 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.

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, 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, which it achieved for the 2010 year, and received approval to defer certain pension and other postretirement benefit cost increases to be incurred in 2011 and 2012.

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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. With the twenty-year extensions of the operating licenses for each of the Palo Verde units recently granted by the NRC, we estimate that our pretax depreciation expense will decrease 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 for APS, which owns substantially all of our property, was 9.0% of the assessed value in 2011 and 8.0% of the assessed value in 2010. Property taxes may increase as we add new utility plants (including new generation, transmission and distribution facilities), as we improve our existing facilities and due to increases in the average property tax rate.

Income Taxes. Income taxes are affected by the amount of pre-tax book income, income tax rates, and certain non-taxable items, such as the allowance for equity funds used during construction. 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 offsets a portion of interest expense while capital projects are under construction. We stop accruing allowance for borrowed funds on a project when it is placed in commercial operation.

RESULTS OF OPERATIONS

Pinnacle West’s 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.

APSES’s and SunCor’s operations have been classified as discontinued operations. Pinnacle West sold its investment in APSES in August 2011.

Operating Results — Three-month period ended September 30, 2011 compared with three-month period ended September 30, 2010

Our consolidated net income attributable to common shareholders for the three months ended September 30, 2011 was $255 million, compared with net income of $234 million for the comparable prior-year period. The increase in results from continuing operations reflects an increase of approximately $21 million for the regulated electricity segment primarily due to increased revenues related to warmer weather and decreased 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,
	2011			2010			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	786		$	762		$	24
Operations and maintenance	(210		)	(220		)	10
Depreciation and amortization	(106		)	(104		)	(2		)
Taxes other than income taxes	(34		)	(38		)	4
Other income (expenses), net	(3		)	—			(3		)
Interest charges, net of allowances for funds used during construction	(48		)	(48		)	—
Income taxes	(132		)	(122		)	(10		)
Less income related to noncontrolling interests (Note 7)	(7		)	(5		)	(2		)
Regulated electricity segment income from continuing operations	246			225			21

Income from Discontinued Operations Attributable to Common Shareholders (a)	9			9			—

Net Income Attributable to Common Shareholders	$	255		$	234		$	21

(a) Includes activities related to APSES and SunCor.

Regulated electricity segment

This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.

Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $24 million higher for the three months ended September 30, 2011 compared with the prior-year period. The following table describes the major components of this change:

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

Effects of weather on retail sales	$	27		$	9		$	18
Higher retail transmission charges	7						7
Higher demand-side management, renewable energy and similar regulatory surcharges (substantially offset in operations and maintenance expense)	6			—			6
Lower retail revenues related to refund of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense	(12		)	(14		)	2
Higher fuel and purchased power costs and lower off-system sales, net of related PSA deferrals	(17		)	(13		)	(4		)
Miscellaneous items, net	(3		)	2			(5		)
Total	$	8		$	(16	)	$	24

Operations and maintenance Operations and maintenance expenses decreased $10 million for the three months ended September 30, 2011 compared with the prior-year period primarily because of:

· A decrease of $11 million related to employee benefit costs;

· A decrease of $9 million in generation costs, primarily due to timing of planned fossil plant maintenance and other costs;

· An increase of $8 million related to costs for demand-side management, renewable energy, and similar regulatory programs, which are offset in operating revenues; and

· An increase of $2 million due to other miscellaneous factors.

Income taxes Income taxes were $10 million higher for the three months ended September 30, 2011 compared with the prior-year period primarily due to higher pretax income in the current-year period.

Discontinued Operations

Income from discontinued operations for the three months ended September 30, 2011 included a gain of approximately $10 million after income taxes related to the sale of our investment in APSES. Income from discontinued operations for the period ended September 30, 2010 of $9 million related primarily to real estate activities.

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Operating Results — Nine-month period ended September 30, 2011 compared with nine-month period ended September 30, 2010

Our consolidated net income attributable to common shareholders for the nine months ended September 30, 2011 was $327 million, compared with net income of $343 million for the comparable prior-year period. The $16 million variance consists of a $4 million decrease in income from continuing operations and a $12 million decrease in income from discontinued operations. The reduction in income from continuing operations reflects a decrease of approximately $3 million for the regulated electricity segment. Increased revenues related to warmer weather and higher retail customer usage were offset by higher depreciation and amortization due to increased plant in service, higher property taxes due to increased property tax rates and higher income taxes resulting from income tax benefits recognized in the prior-year period.

In addition, income from discontinued operations for the nine months ended September 30, 2011 included a gain of approximately $10 million after income taxes related to the sale of our investment in APSES. Income from discontinued operations in the prior-year period is primarily due to a gain of $25 million related to the sale of APSES’s district cooling business.

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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,
	2011			2010			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses (a)	$	1,777		$	1,706		$	71
Operations and maintenance (a)	(676		)	(639		)	(37		)
Depreciation and amortization	(320		)	(308		)	(12		)
Taxes other than income taxes	(112		)	(101		)	(11		)
Other income (expenses), net	(5		)	(5		)	—
Interest charges, net of allowances for funds used during construction	(150		)	(152		)	2
Income taxes	(177		)	(166		)	(11		)
Less income related to noncontrolling interests (Note 7)	(20		)	(15		)	(5		)
Regulated electricity segment income from continuing operations	317			320			(3		)

All other	(1		)	—			(1		)
Income from Continuing Operations Attributable to Common Shareholders	316			320			(4		)

Income from Discontinued Operations Attributable to Common Shareholders (b)	11			23			(12		)

Net Income Attributable to Common Shareholders	$	327		$	343		$	(16	)

(a) Includes effects of settlement of certain prior-period transmission rights-of-way related to Four Corners, 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.

Regulated electricity segment

This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.

Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $71 million higher for the nine months

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ended September 30, 2011 compared with the prior-year period. The following table describes the major components of this change:

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

Settlement of certain prior-period transmission rights-of-way (offset in operations and maintenance expense)	$	28		$	—		$	28
Effects of weather on retail sales	33			12			21
Higher demand-side management, renewable energy and similar regulatory surcharges (substantially offset in operations and maintenance expense)	16			2			14
Higher retail revenues primarily due to higher usage per customer, excluding the effects of weather, but including the effects of APS’s energy efficiency programs	7			4			3
Lower retail revenues related to refund of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense	(25		)	(30		)	5
Higher fuel and purchased power costs and lower off-system sales, net of related PSA deferrals	(19		)	(19		)	—
Miscellaneous items, net	4			4			—
Total	$	44		$	(27	)	$	71

Operations and maintenance Operations and maintenance expenses increased $37 million for the nine months ended September 30, 2011 compared with the prior-year period primarily because of:

· An increase of $28 million for settlement of certain transmission rights-of-way, which is offset in operating revenues;

· An increase of $15 million related to costs for demand-side management, renewable energy, and similar regulatory programs, which are offset in operating revenues;

· A decrease of $11 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 $12 million higher for the nine months ended September 30, 2011 compared with the prior-year period primarily because of increased plant in service.

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Taxes other than income taxes Taxes other than income taxes increased $11 million for the nine months ended September 30, 2011 compared with the prior-year period primarily because of higher property tax rates in the current period.

Income taxes Income taxes were $11 million higher for the nine months ended September 30, 2011 compared with the prior-year period. This is primarily due to $8 million of income tax benefits recognized in the prior-year period related to a reduction in the Company’s 2010 effective income tax rate and the effects of higher pretax income in the current period.

Discontinued Operations

Income from discontinued operations for the nine months ended September 30, 2011 included a gain of $10 million related to the sale of our investment in APSES. Income from discontinued operations for the nine months ended September 30, 2010 included a gain of $25 million related to the sale of APSES’s district cooling business.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows — Pinnacle West Consolidated

The following table presents net cash provided by (used for) operating, investing and financing activities for the nine months ended September 30, 2011 and 2010 (dollars in millions):

	Nine Months Ended September 30,
	2011			2010
Net cash flow provided by operating activities	$	921		$	570
Net cash flow used for investing activities	(534		)	(377		)
Net cash flow provided by (used for) financing activities	68			(142		)

The increase of approximately $351 million in net cash provided by operating activities is primarily due to the $267 million change in collateral and margin posted, as a result of changes in commodity prices and expiration of prior hedge contracts, and a $100 million voluntary pension contribution in 2010.

The increase of approximately $157 million in net cash used for investing activities is primarily due to a decrease of approximately $125 million in net proceeds from the sales of our non-utility businesses (see Note 13) and an increase of $91 million in capital expenditures, partially offset by $55 million of proceeds from the sale of life insurance policies in 2011.

The increase of approximately $210 million in net cash provided by financing activities is primarily due to issuances of long-term debt, net of long-term debt repayments (see Note 2) and lower repayments of short-term borrowings, partially offset by proceeds of approximately $253 million from the issuance of equity in April 2010.

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Cash Flows — Arizona Public Service Company Consolidated

The following table presents net cash provided by (used for) operating, investing and financing activities for the nine months ended September 30, 2011 and 2010 (dollars in millions):

	Nine Months Ended September 30,
	2011			2010
Net cash flow provided by operating activities	$	933		$	506
Net cash flow used for investing activities	(586		)	(548		)
Net cash flow provided by financing activities	108			84

The increase of approximately $427 million in net cash provided by operating activities is primarily due to the $267 million change in collateral and margin posted, as a result of changes in commodity prices and expiration of prior hedge contracts; a $100 million voluntary pension contribution in 2010; and income tax payments in 2010.

The increase of approximately $38 million in net cash used for investing activities is primarily due to an increase in capital expenditures, partially offset by proceeds from the sale of life insurance policies in 2011.

The increase of approximately $24 million in net cash provided by financing activities is primarily due to APS’s issuance of $300 million of unsecured senior notes, partially offset by proceeds of approximately $253 million from the infusion of equity from Pinnacle West in 2010.

Liquidity

Capital Expenditure Requirements

The following table summarizes capital expenditures on an accrual basis for the nine months ended September 30, 2011 and 2010 and the estimated capital expenditures for the next three years:

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CAPITAL EXPENDITURES

(dollars in millions)

	Nine Months Ended September 30,				Estimated for the Year Ended December 31,
	2010		2011		2011		2012		2013
APS
Generation:
Nuclear Fuel	$	63	$	63	$	67	$	85	$	80
Renewables	1		196		231		147		307
Environmental	2		8		12		16		73
Four Corners Units 4 and 5	—		—		—		294		—
Other Generation	126		78		144		157		186
Distribution	183		157		237		283		292
Transmission	83		79		112		155		200
Other (a)	43		46		65		48		44
Total APS	501		627		868		1,185		1,182
Other	4		—		—		—		—
Total	$	505	$	627	$	868	$	1,185	$	1,182

(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 is a significant component of the increase in capital expenditures from 2010 to 2011. In addition, Renewables reflects the additional capital funding requested for the RES implementation plan filed on July 1, 2011, which is subject to ACC approval. APS cannot predict whether the ACC will approve the plan as filed. 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, also subject to ACC approval, and the subsequent shut down 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, new customer construction, related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems.

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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Pinnacle West (Parent Company)

Our primary cash needs are for dividends to our shareholders and principal and interest payments on our short-term and long-term debt. The level of our common stock dividends and future dividend growth will be dependent on declaration of 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.

On October 19, 2011, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on December 1, 2011, to shareholders of record on November 1, 2011.

Our primary sources of cash are dividends from APS, external debt and equity financings. An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At September 30, 2011, APS’s common equity ratio, as defined, was 52%. Its total shareholder equity was approximately $4.0 billion, and total capitalization was approximately $7.7 billion. Under this order, APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.1 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

We maintain a committed revolving credit facility in order to enhance liquidity and provide credit support for our commercial paper program.

On February 23, 2011, Pinnacle West entered into a $175 million term loan facility that matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91% $175 million Senior Notes. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings, or, if unavailable, its long-term issuer ratings. Through September 30, 2011, Pinnacle West has repaid $40 million of the $175 million term loan facility.

Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS 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. 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. The required minimum contribution to our pension plan is zero in 2011 and approximately $68 million in 2012. The contributions to our other postretirement benefit plans for 2011 and 2012 are expected to be approximately $20 million each year.

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APS

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. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.

On February 14, 2011, APS refinanced its $489 million credit facility that would have matured in September 2011, with a new $500 million facility. The new revolving credit facility terminates in February 2015. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS uses the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit, as necessary from time to time. Interest rates are based on APS’s senior unsecured debt credit ratings.

At September 30, 2011, APS had two credit facilities totaling $1 billion, including the $500 million credit facility described above and a $500 million facility that matures in February 2013. These facilities are available to support its $250 million commercial paper program, for bank borrowings, or for issuances of letters of credit. See “Financial Assurances” in Note 10 for a discussion of APS’s letters of credit. At September 30, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. A $20 million letter of credit was outstanding under APS’s 2011 $500 million credit facility described above.

The $68 million 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 cash refunds are not expected to be received in the next twelve months.

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 $425-475 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 and 2013. The cash generated is an acceleration of tax benefits that APS would have otherwise received over 20 years.

Other Financing Matters — See Note 3 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs to the extent those costs vary from the

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Base Fuel Rate on a current basis, APS’s recovery or refund of the deferrals from or to its ratepayers, as appropriate, is subject to annual and, if necessary, periodic PSA adjustments.

See Note 3 for information regarding the retail rate case settlement, which includes ACC authorization and requirements of equity infusions into APS of at least $700 million by December 31, 2014.

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

El Dorado

El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.

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 these covenants and each anticipates it will continue to meet this and other significant covenant requirements. 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, 2011, the ratio was approximately 50% for Pinnacle West and 48% 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 and letters of credit issued 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 facilities borrowings.

See Note 2 for further discussions of liquidity matters.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of October 25, 2011 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.

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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 cover a downward revision to our credit ratings.

	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	Baa3	BBB	BBB-
Commercial paper	P-3	A-2	F3
Outlook	Stable	Positive	Stable

APS
Senior unsecured	Baa2	BBB	BBB
Secured lease obligation bonds	Baa2	BBB	BBB
Corporate credit rating	Baa2	BBB	BBB-
Commercial paper	P-2	A-2	F3
Outlook	Stable	Positive	Stable

Off-Balance Sheet Arrangements

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

Guarantees and Surety Bonds

Contractual Obligations

Year	2011		2012-2013		2014-2015		Thereafter		Total
Purchase obligations (a)	$	—	$	0.10	$	—	$	0.15	$	0.25
Fuel and purchased power commitments	0.20		0.05		—		—		0.25
Renewable energy credits	—		—		—		0.25		0.25

(a) Payments for the transmission rights-of-way are subject to change based on changes in the Consumer Price Index.

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See Note 2 for a discussion of long-term debt and liquidity matters.

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 2010 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2010 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

See Note 16 for the pending 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.

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 17). The nuclear decommissioning trust fund also has risks associated with the changing market value of its investments. Nuclear decommissioning 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.

The following table shows the net pretax changes in mark-to-market of our derivative positions for the nine months ended September 30, 2011 and 2010 (dollars in millions):

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	Nine Months Ended September 30,
	2011			2010
Mark-to-market of net positions at beginning of period	$	(239	)	$	(169	)
Recognized in earnings (a):
Change in mark-to-market losses for future period deliveries	(2		)	(7		)
Mark-to-market losses realized including ineffectiveness during the period	—			3
Decrease (increase) in regulatory asset	15			(52		)
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (b)	(41		)	(168		)
Mark-to-market losses realized during the period	99			102
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(168	)	$	(291	)

(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, 2011 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 2010 Form 10-K and Note 14 for more discussion of our valuation methods.

Source of Fair Value	2011			2012			2013			2014			2015			Years thereafter			Total fair value
Prices provided by other external sources	$	(26	)	$	(73	)	$	(26	)	$	(5	)	$	—		$	—		$	(130	)
Prices based on models and other valuation methods	(4		)	(10		)	(6		)	(5		)	(6		)	(7		)	(38		)
Total by maturity	$	(30	)	$	(83	)	$	(32	)	$	(10	)	$	(6	)	$	(7	)	$	(168	)

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, 2011 and December 31, 2010 (dollars in millions):

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	September 30, 2011 Gain (Loss)					December 31, 2010 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings (a)
Electricity	$	—	$	—		$	—	$	—
Natural gas	1		(1		)	1		(1		)
Regulatory asset, (liability) or OCI (b)
Electricity	6		(6		)	13		(13		)
Natural gas	34		(34		)	42		(42		)
Total	$	41	$	(41	)	$	56	$	(56	)

(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 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 controls and procedures as of September 30, 2011. Based on that evaluation, Pinnacle West’s Chief Executive Officer

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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, 2011. 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, 2011 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

Two purported consumer class action complaints have been filed in Federal District Court in San Diego, California naming APS, Pinnacle West and San Diego Gas & Electric Company as defendants and seeking damages for loss of perishable inventory as a result of interruption of electrical service. APS and Pinnacle West have numerous defenses against any such complaints, and do not believe that any potential impact would be material.

See “Environmental Matters” in Item 5 below, in Part II, Item 5 of the Second Quarter 10-Q, in Part II, Item 5 of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, and “Business of Arizona Public Service Company — Environmental Matters” in Item 1 of the 2010 Form 10-K in regard to pending or threatened litigation or other disputes.

See Note 10 for information regarding FERC proceedings on Pacific Northwest energy market issues and a lawsuit filed by certain environmental organizations relating to Four Corners.

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 2010 Form 10-K and in Part II, Item 1A — Risk Factors in the Second Quarter 10-Q, which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS. The risks described in the 2010 Form 10-K and the Second Quarter 10-Q 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. The risk factor below is an update to our 2010 Form 10-K.

We are subject to information security risks and risks of unauthorized access to our systems.

In the regular course of our business we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or the inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our operations and financial condition.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, our technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of our systems could impact the reliability of our generation, transmission and distribution systems and also subject us to financial harm. If our technology systems were to fail or be breached and if we are unable to recover in a timely way, we may not be able to fulfill critical business functions and sensitive confidential data could be compromised, which could have a material adverse impact on our operations and financial condition.

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Item 5. OTHER INFORMATION

Environmental Matters

Climate Change

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, and Pinnacle West filed its reply on June 30, 2010. On January 24, 2011, the defendants filed a motion to defer calendaring of oral argument until after the United States Supreme Court rules in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut. The Kivalina court granted that motion on February 23, 2011.

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 October 11, 2011, the Ninth Circuit scheduled oral argument in the Kivalina case for November 28, 2011. We believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.

EPA Environmental Regulation

Regional Haze Rules. Over a decade ago, 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.

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 has 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. The EPA may accept the proposed SIP or reject part or all of it if the EPA determines the SIP is inadequate. If the EPA rejects the proposed SIP provisions applicable to Cholla, it could issue a Federal Implementation Plan (“FIP”) for the plant that includes more stringent pollution control technology requirements and emission limits.

On January 19, 2011, a group of environmental organizations notified the EPA of its intent to sue the agency as a result of the EPA’s alleged failure to promulgate a FIP for states that have not yet submitted all or part of the required BART SIPs, including Arizona. On August 29, 2011, the environmental organizations filed a lawsuit against the EPA alleging that the EPA failed to promulgate a FIP for these states.

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Once APS receives a final determination as to what constitutes BART for Cholla, we will have up to five years to complete the installation of the equipment and to achieve the BART emission limits. However, in order to coordinate with the plant’s other scheduled activities, APS is currently implementing portions of its recommended plan for Cholla on a voluntary basis. Costs related to the implementation of these portions of our recommended plan are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 2).

Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry

Following the March 11, 2011 earthquake and tsunami in Japan, the NRC Commissioners launched a two-pronged review of U.S. nuclear power plant safety. The NRC supported the establishment of an agency task force to conduct both a near- and long-term analysis of the lessons that can be learned from the situation in Japan. The near-term task force issued a report on July 12, 2011, and on October 3, 2011, the NRC staff issued a plan for implementing the near-term task force’s recommendations.

On October 18, 2011, the NRC Commissioners directed the NRC staff to implement, without delay, the near-term task force recommendations, subject to certain conditions. One such condition is that the agency should strive to complete and implement lessons learned from the earthquake and tsunami in Japan within five years. A second condition is that the staff should designate the recommendation for a rulemaking to address extended loss of offsite power to be completed within 24 to 30 months.

Until further action is taken by the NRC as a result of this event, we cannot predict any financial or operational impacts on Palo Verde or APS.

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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 hereby incorporates 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	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 1, 2011	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 1, 2011	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)