Edgar Filing: ARIZONA PUBLIC SERVICE CO

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 June 30, 2011

OR

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 July 26, 2011: 109,110,950
ARIZONA PUBLIC SERVICE COMPANY		Number of shares of common stock, $2.50 par value, outstanding as of July 26, 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			72
	Item 1.	Legal Proceedings	72
	Item 1A.	Risk Factors	72
	Item 5.	Other Information	73
	Item 6.	Exhibits	75
Signatures			78

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 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 this Report and in 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 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 greenhouse gas emissions, renewable energy mandates, nuclear plant operations and energy efficiency standards;

· our ability to meet renewable energy requirements 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 Item 1A of our 2010 Form 10-K and in Part II, Item 1A of this Report, which readers should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended June 30,
	2011			2010
OPERATING REVENUES
Regulated electricity segment	$	798,669		$	799,416
Other revenues	1,130			3,379
Total	799,799			802,795
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power	244,049			251,800
Operations and maintenance	210,590			213,609
Depreciation and amortization	106,617			102,995
Taxes other than income taxes	40,155			31,682
Other expenses	1,396			1,325
Total	602,807			601,411
OPERATING INCOME	196,992			201,384
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	5,924			5,504
Other income (Note 11)	557			943
Other expense (Note 11)	(3,186		)	(5,650		)
Total	3,295			797
INTEREST EXPENSE
Interest charges	60,140			60,751
Allowance for borrowed funds used during construction	(3,856		)	(3,072		)
Total	56,284			57,679
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	144,003			144,502
INCOME TAXES	50,818			51,188
INCOME FROM CONTINUING OPERATIONS	93,185			93,314
INCOME FROM DISCONTINUED OPERATIONS
Net of income tax expense of $773 and $16,922 (Note 13)	654			26,252
NET INCOME	93,839			119,566
Less: Net income attributable to noncontrolling interests (Note 7)	7,154			4,769
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	86,685		$	114,797

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	109,044			107,355
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	109,718			107,764

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	0.79		$	0.82
Net income attributable to common shareholders — basic	0.80			1.07
Income from continuing operations attributable to common shareholders — diluted	0.78			0.82
Net income attributable to common shareholders — diluted	0.79			1.07
DIVIDENDS DECLARED PER SHARE	$	1.05		$	1.05

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	86,001		$	88,536
Discontinued operations, net of tax	684			26,261
Net income attributable to common shareholders	$	86,685		$	114,797

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)

	Six Months Ended June 30,
	2011			2010
OPERATING REVENUES
Regulated electricity segment	$	1,446,643		$	1,410,841
Other revenues	2,003			4,216
Total	1,448,646			1,415,057
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power	456,056			467,340
Operations and maintenance	465,619			419,922
Depreciation and amortization	213,200			203,629
Taxes other than income taxes	77,779			63,405
Other expenses	3,216			2,403
Total	1,215,870			1,156,699
OPERATING INCOME	232,776			258,358
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	11,319			10,893
Other income (Note 11)	2,247			1,892
Other expense (Note 11)	(4,927		)	(7,176		)
Total	8,639			5,609
INTEREST EXPENSE
Interest charges	121,217			121,518
Allowance for borrowed funds used during construction	(7,432		)	(6,091		)
Total	113,785			115,427
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	127,630			148,540
INCOME TAXES	44,813			43,535
INCOME FROM CONTINUING OPERATIONS	82,817			105,005
INCOME FROM DISCONTINUED OPERATIONS
Net of income tax expense of $906 and $9,013 (Note 13)	1,348			13,664
NET INCOME	84,165			118,669
Less: Net income attributable to noncontrolling interests (Note 7)	12,615			9,886
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	71,550		$	108,783

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	108,939			104,431
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	109,540			104,857

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	0.64		$	0.91
Net income attributable to common shareholders — basic	0.66			1.04
Income from continuing operations attributable to common shareholders — diluted	0.64			0.91
Net income attributable to common shareholders — diluted	0.65			1.04
DIVIDENDS DECLARED PER SHARE	$	1.575		$	1.575

AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	70,163		$	95,099
Discontinued operations, net of tax	1,387			13,684
Net income attributable to common shareholders	$	71,550		$	108,783

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)

	June 30, 2011			December 31, 2010
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	92,274		$	110,188
Customer and other receivables	294,532			324,207
Accrued unbilled revenues	163,682			103,292
Allowance for doubtful accounts	(3,791		)	(7,981		)
Materials and supplies (at average cost)	194,352			181,414
Fossil fuel (at average cost)	26,863			21,575
Deferred income taxes	113,243			124,897
Assets held for sale	30,540			2,861
Income tax receivable (Note 6)	—			2,483
Assets from risk management activities (Note 8)	38,897			73,788
Regulatory assets (Note 3)	56,158			62,286
Other current assets	30,103			25,501
Total current assets	1,036,853			1,024,511

INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 8)	43,173			39,032
Nuclear decommissioning trust (Note 14)	497,671			469,886
Other assets	63,726			116,216
Total investments and other assets	604,570			625,134

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	13,351,239			13,201,960
Accumulated depreciation and amortization	(4,675,228		)	(4,514,204		)
Net	8,676,011			8,687,756
Construction work in progress	524,870			459,361
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	134,799			137,956
Intangible assets, net of accumulated amortization	177,845			184,952
Nuclear fuel, net of accumulated amortization	142,697			108,794
Total property, plant and equipment	9,656,222			9,578,819

DEFERRED DEBITS
Regulatory assets (Note 3)	983,394			986,370
Income tax receivable (Note 6)	67,970			65,103
Other	125,071			113,061
Total deferred debits	1,176,435			1,164,534

TOTAL ASSETS	$	12,474,080		$	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)

	June 30, 2011			December 31, 2010
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	271,759		$	236,354
Accrued taxes (Note 6)	131,727			104,711
Accrued interest	55,123			54,831
Common dividends payable	57,272			—
Short-term borrowings	7,300			16,600
Current maturities of long-term debt	903,516			631,879
Customer deposits	70,196			68,322
Liabilities from risk management activities (Note 8)	58,684			58,976
Deferred fuel and purchased power regulatory liability (Note 3)	54,359			58,442
Other regulatory liabilities (Note 3)	88,557			80,526
Other current liabilities	132,801			139,063
Total current liabilities	1,831,294			1,449,704

LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities	2,678,565			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	2,761,695			3,045,794

DEFERRED CREDITS AND OTHER
Deferred income taxes	1,825,077			1,863,861
Regulatory liabilities (Note 3)	695,036			614,063
Liability for asset retirements (Note 15)	255,326			328,571
Liabilities for pension and other postretirement benefits (Note 4)	869,277			813,121
Liabilities from risk management activities (Note 8)	57,073			65,390
Customer advances	120,621			121,645
Coal mine reclamation	117,651			117,243
Unrecognized tax benefits (Note 6)	83,229			66,349
Other	142,191			132,031
Total deferred credits and other	4,165,481			4,122,274

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

EQUITY (Note 9)
Common stock, no par value	2,438,256			2,421,372
Treasury stock	(5,768		)	(2,239		)
Total common stock	2,432,488			2,419,133
Retained earnings	1,323,892			1,423,961
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(57,332		)	(59,420		)
Derivative instruments	(85,343		)	(100,347		)
Total accumulated other comprehensive loss	(142,675		)	(159,767		)
Total shareholders’ equity	3,613,705			3,683,327
Noncontrolling interests (Note 7)	101,905			91,899
Total equity	3,715,610			3,775,226

TOTAL LIABILITIES AND EQUITY	$	12,474,080		$	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)

	Six Months Ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	84,165		$	118,669
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of district cooling business	—			(41,973		)
Depreciation and amortization including nuclear fuel	245,700			229,964
Deferred fuel and purchased power	64,679			65,249
Deferred fuel and purchased power amortization	(68,762		)	(55,494		)
Allowance for equity funds used during construction	(11,319		)	(10,893		)
Real estate impairment charges	—			16,731
Deferred income taxes	11,945			50,972
Change in mark-to-market valuations	(279		)	2,396
Changes in current assets and liabilities:
Customer and other receivables	43,271			(7,133		)
Accrued unbilled revenues	(60,390		)	(51,470		)
Materials, supplies and fossil fuel	(18,226		)	13,577
Other current assets	(37,053		)	(8,340		)
Accounts payable	37,817			45,313
Accrued taxes and income tax receivable-net	29,530			75,546
Other current liabilities	3,967			(26,583		)
Expenditures for real estate investments	(40		)	(458		)
Gains and other changes in real estate assets	—			(2,931		)
Change in margin and collateral accounts — assets	21,185			656
Change in margin and collateral accounts — liabilities	39,567			(90,694		)
Change in unrecognized tax benefits	18,959			(62,630		)
Change in other long-term assets	(26,185		)	(11,015		)
Change in other long-term liabilities	57,748			(48,045		)
Net cash flow provided by operating activities	436,279			201,414

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(387,272		)	(378,579		)
Contributions in aid of construction	21,905			15,163
Allowance for borrowed funds used during construction	(7,432		)	(6,395		)
Proceeds from sale of district cooling business	—			100,300
Proceeds from nuclear decommissioning trust sales	299,600			329,796
Investment in nuclear decommissioning trust	(308,222		)	(342,004		)
Proceeds from sale of life insurance policies	55,444			—
Other	(2,352		)	3,850
Net cash flow used for investing activities	(328,329		)	(277,869		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	175,000			—
Repayment of long-term debt	(187,962		)	(15,221		)
Short-term borrowings and payments — net	(9,300		)	(149,099		)
Dividends paid on common stock	(112,537		)	(106,522		)
Common stock equity issuance	14,520			254,612
Distributions to noncontrolling interests	(2,610		)	(3,286		)
Other	(2,975		)	1,095
Net cash flow used for financing activities	(125,864		)	(18,421		)

NET DECREASE IN CASH AND CASH EQUIVALENTS	(17,914		)	(94,876		)

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

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	92,274		$	50,502
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	—		$	(3,944	)
Interest, net of amounts capitalized	$	110,659		$	115,722

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 June 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 June 30, 2010	As previously reported			Reclassifications for discontinued operations			Amount reported after reclassification for discontinued operations
Operating Revenues
Other revenues	$	21,178		$	(17,799	)	$	3,379
Operating Expenses
Operations and maintenance	215,104			(1,495		)	213,609
Depreciation and amortization	103,017			(22		)	102,995
Taxes other than income taxes	31,684			(2		)	31,682
Other expenses	15,716			(14,391		)	1,325
Other
Other income	933			10			943
Other expense	(5,660		)	10			(5,650		)
Interest Expense
Interest charges	60,741			10			60,751
Allowance for borrowed funds used during construction	(3,104		)	32			(3,072		)
Income Taxes	51,829			(641		)	51,188
Income From Continuing Operations	94,584			(1,270		)	93,314
Income From Discontinued Operations	24,982			1,270			26,252

Statement of Income for the Six Months Ended June 30, 2010	As previously reported			Reclassifications for discontinued operations			Amount reported after reclassification for discontinued operations
Operating Revenues
Other revenues	$	30,108		$	(25,892	)	$	4,216
Operating Expenses
Operations and maintenance	422,946			(3,024		)	419,922
Depreciation and amortization	203,670			(41		)	203,629
Taxes other than income taxes	63,408			(3		)	63,405
Other expenses	22,644			(20,241		)	2,403
Other
Other income	1,819			73			1,892
Other expense	(7,134		)	(42		)	(7,176		)
Interest Expense
Interest charges	121,446			72			121,518
Allowance for borrowed funds used during construction	(6,151		)	60			(6,091		)
Income Taxes	44,657			(1,122		)	43,535
Income From Continuing Operations	106,567			(1,562		)	105,005
Income From Discontinued Operations	12,102			1,562			13,664

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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 and to conform to current year presentation			Amount reported after reclassification for regulatory assets and liabilities and to conform to current year presentation

Current Assets — Regulatory assets	$	—	$	62,286		$	62,286
Current Assets — Deferred income taxes	94,602		30,295			124,897
Current Assets — Assets held for sale	—		2,861			2,861
Current Assets — Other current assets	28,362		(2,861		)	25,501
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 Six Months Ended June 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	$	(13,796	)	$	5,456		$	(8,340	)
Other current liabilities	(22,719		)	(3,864		)	(26,583		)
Change in other long-term assets	(5,542		)	(5,473		)	(11,015		)
Change in other long-term liabilities	(51,926		)	3,881			(48,045		)

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. During the first quarter of 2011, APS refinanced an existing revolving credit facility (as discussed below) that would have otherwise matured in September 2011.

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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. On July 25, 2011, we repaid $25 million of the $175 million term loan facility.

At June 30, 2011, Pinnacle West’s $200 million credit facility, which matures in 2013, was available for bank borrowings, support of its $200 million commercial paper program, or for issuances of letters of credit. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At June 30, 2011, Pinnacle West had no outstanding borrowings under this credit facility, no outstanding letters of credit and commercial paper borrowings of $7 million.

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 will use the facility for general corporate purposes, commercial paper program support and for the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit ratings.

At June 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 June 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.

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 June 30, 2011, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $3.7 billion, and total capitalization was approximately $7.1 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.8 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.

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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 APS is now awaiting a procedural order from the ACC and expects a hearing will be scheduled for early 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);

· 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.

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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);

· 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

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$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.

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 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 an additional 100 MW of APS-owned AZ Sun projects and 25 MW of APS-owned facilities on schools. 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.

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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 spread 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% 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.

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 liability for 2011 and 2010 (dollars in millions):

	Six Months Ended June 30,
	2011			2010
Beginning balance	$	(58	)	$	(87	)
Deferred fuel and purchased power costs-current period	(65		)	(65		)
Amounts refunded through revenues	69			55
Ending balance	$	(54	)	$	(97	)

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. The regulatory liability at June 30, 2011 reflects lower average prices, primarily for natural gas and gas-based generation. 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

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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.

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 transmission services used for APS’s retail customers. 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 June 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.

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

	June 30, 2011				December 31, 2010
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	672	$	—	$	669
Deferred income taxes	3		72		3		69
Deferred fuel and purchased power — mark-to-market (Note 8)	31		32		42		35
Transmission vegetation management	9		36		—		46
Coal reclamation	2		36		2		36
Palo Verde VIE (Note 7)	—		34		—		33
Deferred compensation	—		34		—		32
Tax expense of Medicare subsidy	2		21		2		21
Loss on reacquired debt	1		20		1		21
Pension and other post-retirement benefits deferral	—		6		—		—
Demand side management (a)	8		5		12		6
Other	—		15		—		18
Total regulatory assets (b)	$	56	$	983	$	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.”

Included in the balance of regulatory assets at June 30, 2011 and December 31, 2010 is a regulatory asset for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income (“OCI”) and result in lower future earnings.

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

	June 30, 2011				December 31, 2010
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	19	$	358	$	22	$	357
Asset retirement obligations (Note 15)	—		213		—		184
Deferred fuel and purchased power (b)(c)	54		—		58		—
Renewable energy standard (b)	57		—		50		—
Income taxes — change in rates	—		50		—		—
Spent nuclear fuel	4		43		4		41
Deferred gains on utility property	2		15		2		16
Other	7		16		3		16
Total regulatory liabilities	$	143	$	695	$	139	$	614

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(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.

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 a regulatory asset) (dollars in millions):

	Pension Benefits												Other Benefits
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010			2011			2010			2011			2010
Service cost - benefits earned during the period	$	13		$	13		$	29		$	28		$	5		$	5		$	11		$	10
Interest cost on benefit obligation	31			30			62			61			12			10			23			21
Expected return on plan assets	(33		)	(31		)	(67		)	(62		)	(11		)	(10		)	(21		)	(20		)
Amortization of:
Transition obligation	—			—			—			—			—			(1		)	—			—
Prior service cost	—			—			1			1			—			—			—			—
Net actuarial loss	7			4			13			10			4			2			8			5
Net periodic benefit cost	$	18		$	16		$	38		$	38		$	10		$	6		$	21		$	16
Portion of cost charged to expense	$	7		$	8		$	15		$	19		$	4		$	3		$	8		$	8

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. APS and other subsidiaries fund their respective shares of these contributions. APS’s share is approximately 99% of both plans.

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.

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Financial data for the three and six months ended June 30, 2011 and 2010 and at June 30, 2011 and December 31, 2010 is provided as follows (dollars in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Operating revenues:
Regulated electricity segment	$	799	$	800	$	1,447	$	1,411
All other	1		3		2		4
Total	$	800	$	803	$	1,449	$	1,415

Net income attributable to common shareholders:
Regulated electricity segment	$	86	$	88	$	71	$	95
All other (a)	1		27		1		14
Total	$	87	$	115	$	72	$	109

	As of June 30, 2011		As of December 31, 2010
Assets:
Regulated electricity segment	$	12,398	$	12,285
All other (a)	76		108
Total	$	12,474	$	12,393

(a) All other activities relate to APSES, SunCor 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.

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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. Consolidation of these VIEs eliminates the lease accounting and results in changes in our consolidated assets, debt, equity, and net income. Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease. 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 six months ended June 30, 2011 of $7 million and of $13 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 June 30, 2011 and December 31, 2010 include the following amounts relating to the VIEs (in millions):

	June 30, 2011		December 31, 2010
Property plant and equipment, net of accumulated depreciation	$	135	$	138
Current maturities of long-term debt	30		29
Long-term debt less current maturities	83		97
Equity- Noncontrolling interests	101		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 June 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 June 30, 2011, APS would have been required to

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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 these market fluctuations by utilizing various derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. Derivative instruments that are designated as cash flow hedges are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We may also invest in derivative instruments for trading purposes; however, for the period ended June 30, 2011, there was no material trading activity.

Our derivative instruments are accounted for at fair value; see Note 14 for a discussion of fair value measurements. Derivative instruments for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales scope exception and are accounted for under the accrual method of accounting. Due to the scope exception, these derivative instruments are excluded from our derivative instrument discussion and disclosures below.

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. Economic hedges not designated as accounting hedges are recorded at fair value on our balance sheet with changes in fair value recognized in the statement of income as incurred. These instruments are included in the “non-designated hedges” discussion and disclosure 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 June 30, 2011, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but this does not impact our financial condition, net income or cash flows.

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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 portion of APS’s base rates attributable to fuel and purchased power costs (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 June 30, 2011, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	13,226,728	megawatt hours
Gas	145,891,520	MMBTU (a)

(a) “MMBTU” is one million British thermal units.

Derivative Instruments in Designated Accounting Hedging Relationships

The following table provides information about gains and losses from derivative instruments in designated accounting hedging relationships and their impact on our Condensed Consolidated Statements of Income during the three and six months ended June 30, 2011 and 2010 (dollars in thousands):

	Financial Statement	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	Location	2011			2010			2011			2010

Amount of Loss Recognized in AOCI on Derivative Instruments (Effective Portion)	Accumulated other comprehensive loss-derivative instruments	$	(16,324	)	$	(8,588	)	$	(15,335	)	$	(100,255	)
Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)	Regulated electricity segment fuel and purchased power	(25,287		)	(29,143		)	(40,133		)	(42,329		)
Amount of Gain (Loss) Recognized in Income from Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)	Regulated electricity segment fuel and purchased power	(176		)	11,899			(164		)	1,432

(a) During the three and six months ended June 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 $89 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions. Approximately 90% of the amounts related to derivatives subject to the PSA will be recorded as either a regulatory asset or liability and have no effect on earnings.

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Derivative Instruments Not Designated as Accounting Hedges

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments and their impact on our Condensed Consolidated Statements of Income during the three and six months ended June 30, 2011 and 2010 (dollars in thousands):

		Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	Financial Statement Location	2011			2010			2011			2010

Amount of Net Gain (Loss) Recognized in Income from Derivative Instruments	Regulated electricity segment revenue	$	(503	)	$	426		$	1,004		$	595

Amount of Net Loss Recognized in Income from Derivative Instruments	Regulated electricity segment fuel and purchased power expense	(2,892		)	(29,260		)	(11,919		)	(64,228		)
Total		$	(3,395	)	$	(28,834	)	$	(10,915	)	$	(63,633	)

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Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the Condensed Consolidated Balance Sheets. These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of June 30, 2011 (dollars in thousands):

Commodity Contracts	Current Assets			Investments and Other Assets		Current Liabilities			Deferred Credits and Other			Total Assets (Liabilities)
Derivatives designated as accounting hedging instruments:
Assets	$	329		$	—	$	11,730		$	3,011		$	15,070
Liabilities	(550		)	—		(90,187		)	(57,209		)	(147,946		)
Total hedging instruments	(221		)	—		(78,457		)	(54,198		)	(132,876		)

Derivatives not designated as accounting hedging instruments:
Assets	24,607			43,173		31,946			10,365			110,091
Liabilities	(869		)	—		(94,294		)	(82,903		)	(178,066		)
Total non-hedging instruments	23,738			43,173		(62,348		)	(72,538		)	(67,975		)

Total derivatives	23,517			43,173		(140,805		)	(126,736		)	(200,851		)

Margin account	2,137			—		11,087			3,862			17,086
Collateral provided to counterparties (a)	10,000			—		81,669			65,801			157,470
Collateral provided from counterparties (a)	—			—		(12,145		)	—			(12,145		)
Prepaid option premiums and other	3,243			—		1,510			—			4,753
Balance Sheet Total	$	38,897		$	43,173	$	(58,684	)	$	(57,073	)	$	(33,687	)

(a) Amounts represent collateral relating to non-derivatives and derivative instruments, including those that qualify for scope exceptions.

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The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis at December 31, 2010 (dollars in thousands):

Commodity Contracts	Current Assets			Investments and Other Assets			Current Liabilities			Deferred Credits and Other			Total Assets (Liabilities)
Derivatives designated as accounting hedging instruments:
Assets	$	1,234		$	142		$	9,062		$	4,913		$	15,351
Liabilities	(602		)	(1,933		)	(107,784		)	(71,109		)	(181,428		)
Total hedging instruments	632			(1,791		)	(98,722		)	(66,196		)	(166,077		)

Derivatives not designated as accounting hedging instruments:
Assets	36,831			40,927			27,322			19,886			124,966
Liabilities	(312		)	(33		)	(112,535		)	(85,473		)	(198,353		)
Total non-hedging instruments	36,519			40,894			(85,213		)	(65,587		)	(73,387		)

Total derivatives	37,151			39,103			(183,935		)	(131,783		)	(239,464		)

Margin account	24,579			—			997			—			25,576
Collateral provided to counterparties (a)	11,556			—			125,367			66,393			203,316
Collateral provided from counterparties (a)	(1,750		)	—			(1,250		)	—			(3,000		)
Prepaid option premiums and other	2,252			(71		)	(155		)	—			2,026
Balance Sheet Total	$	73,788		$	39,032		$	(58,976	)	$	(65,390	)	$	(11,546	)

(a) Amounts represent collateral relating to non-derivatives and derivative instruments, including those that qualify for scope exceptions.

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 64% of Pinnacle West’s $82 million of risk management assets as of June 30, 2011. This exposure relates to long-term traditional wholesale contracts with counterparties that have very high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a

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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. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on June 30, 2011 was $303 million, for which we had posted collateral of $147 million in the normal course of business.

For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit ratings were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). If the investment grade contingent features underlying these agreements had been fully triggered on June 30, 2011, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $106 million of collateral to our counterparties; this amount includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the above footnote. 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 six months ended June 30, 2011 and 2010 (dollars in thousands):

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

Beginning balance, April 1	$	3,631,411		$	97,360		$	3,728,771		$	3,213,933		$	116,067		$	3,330,000

Net income	86,685			7,154			93,839			114,797			4,769			119,566
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)	(16,324		)	—			(16,324		)	(8,588		)	—			(8,588		)
Net reclassification of realized losses to income (b)	25,287			—			25,287			29,143			—			29,143
Reclassification of pension and other postretirement benefits to income	1,046			—			1,046			1,362			—			1,362
Net unrealized gains (losses) related to pension and other postretirement benefits	974			—			974			(6,933		)	—			(6,933		)
Net income tax expense related to items of other comprehensive income (loss)	(4,337		)	—			(4,337		)	(5,914		)	—			(5,914		)
Total other comprehensive income	6,646			—			6,646			9,070			—			9,070
Total comprehensive income	93,331			7,154			100,485			123,867			4,769			128,636

Issuance of capital stock	3,505			—			3,505			255,480			—			255,480
Other (primarily stock compensation)	(33		)	—			(33		)	140			—			140
Dividends on common stock	(114,509		)	—			(114,509		)	(113,872		)	—			(113,872		)
Net capital activities by noncontrolling interests	—			(2,609		)	(2,609		)	—			(7,381		)	(7,381		)
Ending balance, June 30	$	3,613,705		$	101,905		$	3,715,610		$	3,479,548		$	113,455		$	3,593,003

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	Six Months Ended June 30, 2011									Six Months Ended June 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	71,550			12,615			84,165			108,783			9,886			118,669
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)	(15,335		)	—			(15,335		)	(100,255		)	—			(100,255		)
Net reclassification of realized losses to income (b)	40,133			—			40,133			42,329			—			42,329
Reclassification of pension and other postretirement benefits to income	2,478			—			2,478			2,755			—			2,755
Net unrealized gains (losses) related to pension and other postretirement benefits	974			—			974			(6,933		)	—			(6,933		)
Net income tax benefit related to items of other comprehensive income (loss)	(11,158		)	—			(11,158		)	24,511			—			24,511
Total other comprehensive income (loss)	17,092			—			17,092			(37,593		)	—			(37,593		)
Total comprehensive income	88,642			12,615			101,257			71,190			9,886			81,076

Issuance of capital stock	17,065			—			17,065			258,160			—			258,160
Purchase of treasury stock, net of reissuances	(3,530		)	—			(3,530		)	1,078			—			1,078
Other (primarily stock compensation)	(181		)	—			(181		)	142			—			142
Dividends on common stock	(171,618		)	—			(171,618		)	(167,131		)	—			(167,131		)
Net capital activities by noncontrolling interests	—			(2,609		)	(2,609		)	—			(8,326		)	(8,326		)
Ending balance, June 30	$	3,613,705		$	101,905		$	3,715,610		$	3,479,548		$	113,455		$	3,593,003

(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.

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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 June 30, 2011, APS had a regulatory liability of $47 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Nuclear Insurance

The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also 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 June 30, 2011, certain contractual obligations have increased approximately $0.5 billion from December 31, 2010 as discussed in the 2010 Form 10-K. This increase is primarily related to an increase in purchase obligations for an amended agreement for certain transmission rights-of-way and a new contract for the construction of a solar facility. In addition, there were increased fuel and purchased power commitments and an increase in renewable energy credit obligations. 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)	$	0.2	$	0.1	$	0.1	$	—	$	—	$	0.3	$	0.7
Fuel and purchased power commitments	0.5		0.4		0.5		0.5		0.6		7.0		9.5
Renewable energy credits	0.1		—		—		0.1		—		0.3		0.5

(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. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. 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.

Financial Assurances

APS has entered into various agreements that require letters of credit for financial assurance purposes. At June 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 2011 and 2013. 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 June 30, 2011, totaled approximately $54 million. We expect to renew expiring letters of credit in the ordinary course of business.

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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.

11. Other Income and Other Expense

The following table provides detail of other income and other expense for the three and six months ended June 30, 2011 and 2010 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Other income:
Interest income	$	543		$	635		$	935		$	1,572
Investment gains — net	12			—			1,307			—
Miscellaneous	2			308			5			320
Total other income	$	557		$	943		$	2,247		$	1,892

Other expense:
Non-operating costs	$	(1,629	)	$	(1,237	)	$	(3,119	)	$	(3,084	)
Investment losses — net	—			(3,561		)	—			(2,339		)
Miscellaneous	(1,557		)	(852		)	(1,808		)	(1,753		)
Total other expense	$	(3,186	)	$	(5,650	)	$	(4,927	)	$	(7,176	)

12. Earnings Per Share

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

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	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	0.79	$	0.82	$	0.64	$	0.91
Income from discontinued operations	0.01		0.25		0.02		0.13
Earnings per share — basic	$	0.80	$	1.07	$	0.66	$	1.04

Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	0.78	$	0.82	$	0.64	$	0.91
Income from discontinued operations	0.01		0.25		0.01		0.13
Earnings per share — diluted	$	0.79	$	1.07	$	0.65	$	1.04

Dilutive stock options and performance shares (which are contingently issuable) increased average diluted common shares outstanding by approximately 674,000 shares and 409,000 shares for the three months ended June 30, 2011 and 2010, respectively, and by approximately 601,000 and 426,000 shares for the six months ended June 30, 2011 and 2010, respectively.

For the three-month and six-month periods ended June 30, 2011, there were no options to purchase shares of common stock outstanding that 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. For the three-month and six-month periods ended June 30, 2010, options to purchase 387,800 shares 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 2009, our real estate subsidiary, SunCor, began disposing of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce its outstanding debt. 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 of $17 million in the first and second quarter. SunCor’s asset sales resulted in no gain for 2010. SunCor has approximately $3 million of assets on its balance sheet classified as assets held for sale at June 30, 2011.

APSES (other) — Pinnacle West is negotiating the potential sale of its investment in APSES. As a result, we have classified APSES in discontinued operations at June 30, 2011. If the sale is consummated, we expect to record an after-tax gain from discontinued operations. Prior period income statement amounts related to APSES for revenues and costs are reflected in discontinued operations. APSES’s $28 million of assets are classified as held for sale and $6 million of liabilities are held for sale and are included in other current liabilities on the balance sheet as of June 30, 2011.

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 this sale, we

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recorded an after-tax gain from discontinued operations of approximately $25 million. Prior period income statement amounts related to this sale 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 six months ended June 30, 2011 and 2010 (dollars in millions):

	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011			2010
Revenue:
SunCor	$	2	$	11		$	3		$	21
APSES	15		22			26			33
Total revenue	$	17	$	33		$	29		$	54

Income (loss) before taxes:
SunCor	$	—	$	(2	)	$	(1	)	$	(24	)
APSES	1		45			3			47
Total income (loss) before taxes	$	1	$	43		$	2		$	23

Income (loss) after taxes:
SunCor (a)	$	—	$	(1	)	$	—		$	(14	)
APSES	1		27			1			28
Total income (loss) after taxes	$	1	$	26		$	1		$	14

(a) Includes a tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of $1 million for the three months ended June 30, 2010, and $9 million for the six months ended June 30, 2010.

14. Fair Value Measurements

We disclose the fair value of certain assets and liabilities according to a 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 — Quoted prices in active markets for identical assets or liabilities. 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 derivative instruments that are exchange-traded such as futures, cash equivalents invested in exchange-traded money market funds, exchange-traded equities, and nuclear decommissioning trust investments in Treasury securities.

Level 2 — 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. This category includes nonexchange-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.

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Level 3 — Model-derived valuations 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 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. 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. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. 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 derivative instruments, nuclear decommissioning trusts, certain cash equivalents and plan assets held in our retirement and other benefit plans (see Note 8).

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

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 overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

Some of our derivative instrument transactions 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 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.

Nuclear Decommissioning Trust

The nuclear decommissioning trust invests in fixed income securities directly and equity securities indirectly through commingled funds. Cash equivalents are held in a fixed income security commingled fund. The commingled funds are valued based on the fund’s net asset value and are classified within Level 2. We may transact in the equity commingled fund on a semi-monthly basis and the cash equivalent commingled fund on a daily basis. 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. The trust fund investments have been established to satisfy APS’s nuclear decommissioning obligations.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at June 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)			Counterparty Netting & Other (b)			Balance at June 30, 2011
Assets
Cash Equivalents	$	33	$	—		$	—		$	—		$	33
Risk management activities:
Commodity contracts	—		60			63			(41		)	82
Nuclear decommissioning trust:
Equity securities:
U.S. commingled funds	—		178			—			—			178
Fixed income securities:
U.S. Treasury	82		—			—			—			82
Cash and cash equivalent funds (c)	—		14			—			—			14
Corporate	—		58			—			—			58
Mortgage-backed	—		84			—			—			84
Municipality	—		71			—			—			71
Other	—		18			—			(7		)	11
Total	$	115	$	483		$	63		$	(48	)	$	613

Liabilities
Risk management activities:
Commodity contracts	$	—	$	(214	)	$	(110	)	$	208		$	(116	)

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

(b) Risk management activities represent netting under master netting agreements, including margin and collateral (see Note 8). Nuclear decommissioning trust represents net pending securities sales and purchases.

(c) These cash equivalents are held in a commingled short-term investment fund that invests in short-term, highly liquid, fixed income instruments.

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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PINNACLE WEST CAPITAL CORPORATION

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)			Counterparty Netting & Other (b)			Balance at December 31, 2010
Assets
Cash equivalents	$	35		$	—		$	—		$	—		$	35
Risk management activities:
Commodity contracts	—			80			61			(28		)	113
Nuclear decommissioning trust:
Equity securities:
U.S. commingled funds	—			168			—			—			168
Fixed income securities:
U.S. Treasury	50			—			—			—			50
Cash and cash equivalent funds (c)	—			22			—			—			22
Corporate	—			60			—			—			60
Mortgage-backed	—			81			—			—			81
Municipality	—			79			—			—			79
Other	—			20			—			(10		)	10
Total	$	85		$	510		$	61		$	(38	)	$	618

Liabilities
Risk management activities:
Commodity contracts	$	(1	)	$	(280	)	$	(99	)	$	256		$	(124	)

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

(b) Risk management activities represent netting under master netting arrangements, including margin and collateral. See Note 8. Nuclear decommissioning trust represents net pending securities sales and purchases.

(c) These cash equivalents are held in a commingled short-term investment fund that invests in short-term, highly liquid, fixed income instruments.

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 six months ended June 30, 2011 and 2010 (dollars in millions):

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended June 30,						Six Months Ended June 30,
Commodity Contracts	2011			2010			2011			2010
Net derivative balance at beginning of period	$	(48	)	$	(31	)	$	(38	)	$	(10	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			(1		)	1			(2		)
Included in OCI	(3		)	(3		)	(1		)	(9		)
Deferred as a regulatory asset or liability	1			(12		)	(6		)	(24		)
Settlements	4			3			4			3
Transfers into Level 3 from Level 2	1			8			(4		)	8
Transfers from Level 3 into Level 2	(2		)	(6		)	(3		)	(8		)
Net derivative balance at end of period	$	(47	)	$	(42	)	$	(47	)	$	(42	)

Net unrealized gains (losses) 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 option models and long-dated energy transactions that extend beyond available quoted periods.

Nonrecurring Fair Value Measurements

We may be required to record other assets at fair value on a nonrecurring basis. These nonrecurring fair value measurements typically involve write-downs of individual assets due to impairment.

Financial Instruments Not Carried at Fair Value

The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our long-term debt fair value estimates are based on quoted market prices of 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.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table represents the carrying amount and estimated fair value of our long-term debt, including current maturities (dollars in millions):

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

Pinnacle West	$	175	$	175	$	175	$	176
APS	3,490		3,782		3,503		3,737
Total	$	3,665	$	3,957	$	3,678	$	3,913

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. 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 the offsetting amount of gains or 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 June 30, 2011 and December 31, 2010 (dollars in millions):

	Fair Value			Total Unrealized Gains		Total Unrealized Losses
June 30, 2011
Equity securities	$	178		$	51	$	(1	)
Fixed income securities	327			15		—
Net payables (a)	(7		)	—		—
Total	$	498		$	66	$	(1	)

(a) Net payables 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.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Realized gains	$	2		$	2		$	3		$	14
Realized losses	(1		)	(1		)	(3		)	(3		)
Proceeds from the sale of securities (a)	110			171			300			330

(a) Proceeds are reinvested in the trust.

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

	Fair Value
Less than one year	$	18
1 year - 5 years	71
5 years - 10 years	110
Greater than 10 years	128
Total	$	327

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 effective for us on January 1, 2012. This

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

guidance will change our presentation of comprehensive income, but will not impact our financial statement results.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended June 30,
	2011			2010

ELECTRIC OPERATING REVENUES	$	798,686		$	799,467

OPERATING EXPENSES
Fuel and purchased power	244,048			251,800
Operations and maintenance	208,597			211,310
Depreciation and amortization	106,594			102,970
Income taxes	54,259			55,688
Taxes other than income taxes	39,788			31,450
Total	653,286			653,218
OPERATING INCOME	145,400			146,249

OTHER INCOME (DEDUCTIONS)
Income taxes	1,565			1,654
Allowance for equity funds used during construction	5,924			5,504
Other income (Note S-2)	1,233			1,827
Other expense (Note S-2)	(4,651		)	(6,091		)
Total	4,071			2,894

INTEREST EXPENSE
Interest on long-term debt	54,754			53,220
Interest on short-term borrowings	2,521			2,879
Debt discount, premium and expense	1,164			1,118
Allowance for borrowed funds used during construction	(3,857		)	(3,072		)
Total	54,582			54,145

NET INCOME	94,889			94,998

Less: Net income attributable to noncontrolling interests (Note 7)	7,184			4,778

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	87,705		$	90,220

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)

	Six Months Ended June 30,
	2011			2010

ELECTRIC OPERATING REVENUES	$	1,446,680		$	1,410,943

OPERATING EXPENSES
Fuel and purchased power	456,056			467,340
Operations and maintenance	461,203			415,191
Depreciation and amortization	213,152			203,579
Income taxes	48,255			50,248
Taxes other than income taxes	77,038			62,901
Total	1,255,704			1,199,259
OPERATING INCOME	190,976			211,684

OTHER INCOME (DEDUCTIONS)
Income taxes	225			2,497
Allowance for equity funds used during construction	11,319			10,893
Other income (Note S-2)	3,211			2,445
Other expense (Note S-2)	(8,243		)	(8,552		)
Total	6,512			7,283

INTEREST EXPENSE
Interest on long-term debt	109,491			107,972
Interest on short-term borrowings	4,829			3,721
Debt discount, premium and expense	2,321			2,255
Allowance for borrowed funds used during construction	(7,432		)	(6,091		)
Total	109,209			107,857

NET INCOME	88,279			111,110

Less: Net income attributable to noncontrolling interests (Note 7)	12,654			9,906

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	75,625		$	101,204

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)

	June 30,			December 31,
	2011			2010
ASSETS

PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	13,347,328		$	13,197,254
Accumulated depreciation and amortization	(4,671,739		)	(4,510,591		)
Net	8,675,589			8,686,663

Construction work in progress	524,870			459,316
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)	134,799			137,956
Intangible assets, net of accumulated amortization	177,690			184,768
Nuclear fuel, net of accumulated amortization	142,697			108,794
Total property, plant and equipment	9,655,645			9,577,497

INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 14)	497,671			469,886
Assets from risk management activities (Note 8)	43,173			39,032
Other assets	29,597			71,428
Total investments and other assets	570,441			580,346

CURRENT ASSETS
Cash and cash equivalents	85,818			99,937
Customer and other receivables	291,240			288,323
Accrued unbilled revenues	163,682			103,292
Allowance for doubtful accounts	(3,580		)	(7,646		)
Materials and supplies (at average cost)	194,352			181,414
Fossil fuel (at average cost)	26,863			21,575
Assets from risk management activities (Note 8)	38,897			73,788
Regulatory assets (Note 3)	56,158			62,286
Deferred income taxes	93,388			105,042
Other current assets	29,821			25,135
Total current assets	976,639			953,146

DEFERRED DEBITS
Regulatory assets (Note 3)	983,394			986,370
Income tax receivable (Note 6)	68,365			65,498
Unamortized debt issue costs	19,304			20,530
Other	100,797			88,490
Total deferred debits	1,171,860			1,160,888

TOTAL ASSETS	$	12,374,585		$	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)

	June 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	1,307,416			1,403,390
Accumulated other comprehensive loss:
Pension and other postretirement benefits	(33,874		)	(35,961		)
Derivative instruments	(85,333		)	(100,334		)
Total shareholder equity	3,746,067			3,824,953
Noncontrolling interests (Note 7)	101,128			91,084
Total equity	3,847,195			3,916,037
Long-term debt less current maturities	2,503,565			2,948,991
Palo Verde sale leaseback lessor notes less current maturities (Note 7)	83,130			96,803
Total capitalization	6,433,890			6,961,831

CURRENT LIABILITIES
Current maturities of long-term debt	903,516			456,879
Accounts payable	266,018			218,491
Accrued taxes (Note 6)	142,252			106,431
Accrued interest	54,979			54,638
Common dividends payable	57,300			—
Customer deposits	70,182			68,312
Liabilities from risk management activities (Note 8)	58,684			58,976
Deferred fuel and purchased power regulatory liability (Note 3)	54,359			58,442
Other regulatory liabilities (Note 3)	88,557			80,526
Other current liabilities	118,366			132,170
Total current liabilities	1,814,213			1,234,865

DEFERRED CREDITS AND OTHER
Deferred income taxes	1,856,415			1,895,654
Regulatory liabilities (Note 3)	695,036			614,063
Liability for asset retirements (Note 15)	255,326			328,571
Liabilities for pension and other postretirement benefits (Note 4)	827,314			770,611
Liabilities from risk management activities (Note 8)	57,073			65,390
Customer advances	120,621			121,645
Coal mine reclamation	117,651			117,243
Unrecognized tax benefits (Note 6)	82,246			65,363
Other	114,800			96,641
Total deferred credits and other	4,126,482			4,075,181

COMMITMENTS AND CONTINGENCIES (SEE NOTES)

TOTAL LIABILITIES AND EQUITY	$	12,374,585		$	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)

	Six Months Ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	88,279		$	111,110
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	245,617			228,513
Deferred fuel and purchased power	64,679			65,249
Deferred fuel and purchased power amortization	(68,762		)	(55,494		)
Allowance for equity funds used during construction	(11,319		)	(10,893		)
Deferred income taxes	11,488			58,225
Change in mark-to-market valuations	(279		)	2,396
Changes in current assets and liabilities:
Customer and other receivables	11,104			(4,062		)
Accrued unbilled revenues	(60,390		)	(51,470		)
Materials, supplies and fossil fuel	(18,226		)	13,577
Other current assets	(9,458		)	(10,786		)
Accounts payable	49,939			43,451
Other current liabilities	32,321			(33,793		)
Change in margin and collateral accounts — assets	21,185			656
Change in margin and collateral accounts — liabilities	39,567			(90,694		)
Change in long-term income tax receivable	(2,867		)	—
Change in unrecognized tax benefits	18,972			(62,198		)
Change in other long-term assets	(22,137		)	(12,676		)
Change in other long-term liabilities	66,290			(36,857		)
Net cash flow provided by operating activities	456,003			154,254

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(387,932		)	(378,239		)
Contributions in aid of construction	21,905			15,163
Allowance for borrowed funds used during construction	(7,432		)	(6,091		)
Proceeds from sale of life insurance policies	44,183			—
Proceeds from nuclear decommissioning trust sales	299,600			329,796
Investment in nuclear decommissioning trust	(308,222		)	(342,004		)
Other	(2,352		)	1,074
Net cash flow used for investing activities	(340,250		)	(380,301		)

CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of long-term debt	(12,962		)	(9,296		)
Equity infusion	—			252,833
Dividends paid on common stock	(114,300		)	(99,400		)
Noncontrolling interests	(2,610		)	(3,286		)
Net cash flow provided by (used for) financing activities	(129,872		)	140,851
NET DECREASE IN CASH AND CASH EQUIVALENTS	(14,119		)	(85,196		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	99,937			120,798
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	85,818		$	35,602
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	—		$	65,498
Interest, net of amounts capitalized	$	106,546		$	106,485

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

Table of Contents

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	—

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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 six months ended June 30, 2011 and 2010 (dollars in thousands):

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

Beginning balance, April 1	$	3,766,131		$	96,554		$	3,862,685		$	3,366,986		$	87,452		$	3,454,438

Net income	87,705			7,184			94,889			90,220			4,778			94,998
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)	(16,324		)	—			(16,324		)	(8,588		)	—			(8,588		)
Net reclassification of realized losses to income (b)	25,287			—			25,287			29,143			—			29,143
Reclassification of pension and other postretirement benefits to income	893			—			893			1,264			—			1,264
Net unrealized gains (losses) related to pension benefits	1,268			—			1,268			(6,862		)	—			(6,862		)
Net income tax expense related to items of other comprehensive income	(4,394		)	—			(4,394		)	(5,905		)	—			(5,905		)
Total other comprehensive income	6,730			—			6,730			9,052			—			9,052
Total comprehensive income	94,435			7,184			101,619			99,272			4,778			104,050

Dividends on common stock	(114,500		)	—			(114,500		)	(113,800		)	—			(113,800		)
Equity infusion	—			—			—			252,833			—			252,833
Net capital activities by noncontrolling interests	—			(2,610		)	(2,610		)	—			(3,286		)	(3,286		)
Other	1			—			1			1			—			1
Ending balance, June 30	$	3,746,067		$	101,128		$	3,847,195		$	3,605,292		$	88,944		$	3,694,236

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ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Six Months Ended June 30, 2011									Six Months Ended June 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	75,625			12,654			88,279			101,204			9,906			111,110
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)	(15,335		)	—			(15,335		)	(100,255		)	—			(100,255		)
Net reclassification of realized losses to income (b)	40,133			—			40,133			42,329			—			42,329
Reclassification of pension and other postretirement benefits to income	2,181			—			2,181			2,328			—			2,328
Net unrealized gains (losses) related to pension benefits	1,268			—			1,268			(6,862		)	—			(6,862		)
Net income tax benefit (expense) related to items of other comprehensive income	(11,159		)	—			(11,159		)	24,659			—			24,659
Total other comprehensive income (loss)	17,088			—			17,088			(37,801		)	—			(37,801		)
Total comprehensive income	92,713			12,654			105,367			63,403			9,906			73,309

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		)	—			(3,286		)	(3,286		)
Other	1			—			1			1			—			1
Ending balance, June 30	$	3,746,067		$	101,128		$	3,847,195		$	3,605,292		$	88,944		$	3,694,236

(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 six months ended June 30, 2011 and 2010 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Other income:
Interest income	$	89		$	143		$	219		$	211
Investment gains — net	268			—			1,418			—
Miscellaneous	876			1,684			1,574			2,234
Total other income	$	1,233		$	1,827		$	3,211		$	2,445

Other expense:
Non-operating costs (a)	$	(2,400	)	$	(1,751	)	$	(4,214	)	$	(3,708	)
Asset dispositions	—			—			(823		)	—
Investment losses — net	—			(2,700		)	—			(1,535		)
Miscellaneous	(2,251		)	(1,640		)	(3,206		)	(3,309		)
Total other expense	$	(4,651	)	$	(6,091	)	$	(8,243	)	$	(8,552	)

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Notes that appear in Item 1 of this report. For information on the broad 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 Item 1A of the 2010 Form 10-K 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. With a focus on safely and efficiently generating electricity for the long-term, 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 twenty-year 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.

Southern California Edison (“SCE”), a participant in the Four Corners Power Plant (“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 is 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 with the ACC are ongoing and will resume on August 8, 2011. Closing is also conditioned on the execution of a new coal supply contract for the lease renewal period described below, expiration of the

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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. 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. These events will change the plant’s overall generating capacity from 2,100 MW to 1,540 MW and APS’s entitlement from the plant from 791 MW to 970 MW. When applying for approval to purchase 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 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 development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).

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During the second quarter 2011, APS’s third-party owned distributed energy resources in operation grew by 14 MW while third-party owned distributed energy resources planned or under development decreased by 11 MW mainly due to projects becoming operational. 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.

On April 5, 2011, APS issued its 2011 Small Generation request for proposal 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 an additional 100 MW of APS-owned AZ Sun projects and 25 MW of APS-owned facilities on schools. APS cannot predict whether the ACC will approve the plan as filed.

Demand Side Management. 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.

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 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.

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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 terminated in September 2011.

APSES. Pinnacle West is negotiating the potential sale of its investment in APSES. As a result, we have classified APSES in discontinued operations at June 30, 2011. The sale is consistent with the Company’s continued streamlining and focus on its core, regulated utility business. If the sale is consummated, we expect to record an after-tax gain from discontinued operations.

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 June 30, 2011, SunCor had total remaining assets of about $12 million, which includes approximately $3 million of assets held for sale.

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 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 six-month period ended June 30, 2011 was 0.4% compared with the prior year period. For the three years 2008

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through 2010, APS’s customer growth averaged 0.9% per year. We currently expect customer growth to average about 1.3% per year for 2011 through 2013 based on our assessment of improving economic conditions, both nationally and in Arizona. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for the six-month period ended June 30, 2011 increased 1.0% compared to the same period in the prior year, reflecting the 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 retail electricity sales in kilowatt-hours will remain flat on average per year during 2011 through 2013, including the effects of APS’s energy efficiency programs, but excluding the effects of weather variations. A continuation of the economic downturn, or 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.

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.

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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 currently owns substantially all of our property, was 8.0% of the assessed value in 2010 and 7.5% of the assessed value in 2009. 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 is negotiating the potential sale of its investment in APSES. If the sale is consummated, we expect to record an after-tax gain from discontinued operations.

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

Our consolidated net income attributable to common shareholders for the three months ended June 30, 2011 was $87 million, compared with net income of $115 million for the comparable prior-year period. The $28 million variance consists of a $3 million decrease in income from continuing operations and a $25 million decrease in income from discontinued operations (primarily due to a gain of $25 million in the prior-year period related to the sale of APSES’s district cooling business). The reduction in results from continuing operations reflects a decrease of approximately $2 million for the regulated electricity segment primarily due to higher property taxes related to increased property tax rates and higher depreciation due to increased plant in service. These negative factors were partially offset by higher retail customer usage.

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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 June 30,
	2011			2010			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	555		$	548		$	7
Operations and maintenance	(211		)	(214		)	3
Depreciation and amortization	(107		)	(103		)	(4		)
Taxes other than income taxes	(40		)	(32		)	(8		)
Other income (expenses), net	(3		)	(3		)	—
Interest charges, net of allowances for funds used during construction	(50		)	(52		)	2
Income taxes	(51		)	(51		)	—
Less income related to noncontrolling interests (Note 7)	(7		)	(5		)	(2		)
Regulated electricity segment income from continuing operations	86			88			(2		)

All Other	—			1			(1		)
Income from Continuing Operations Attributable to Common Shareholders	86			89			(3		)

Income from Discontinued Operations Attributable to Common Shareholders (a)	1			26			(25		)

Net Income Attributable to Common Shareholders	$	87		$	115		$	(28	)

(a) Includes activities related to APSES and SunCor. Income from discontinued operations for the period ended June 30, 2010 includes a gain of $25 million after income taxes related to the sale of APSES’s district cooling business.

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 $7 million higher for the three months ended June 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)

Higher demand-side management, renewable energy and similar regulatory surcharges (substantially offset in operations and maintenance expense)	$	5		$	1		$	4
Higher retail sales primarily due to higher usage per customer, excluding the effects of weather, but including the effects of APS’s energy efficiency programs	5			2			3
Effects of weather on retail sales	(3		)	—			(3		)
Lower retail revenues related to refund of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense	(8		)	(10		)	2
Miscellaneous items, net	—			(1		)	1
Total	$	(1	)	$	(8	)	$	7

Operations and maintenance Operations and maintenance expenses decreased $3 million for the three months ended June 30, 2011 compared with the prior-year period primarily because of:

· A decrease of $6 million in generation costs, primarily due to timing of fossil plant planned maintenance; and

· An increase of $3 million related to costs for demand-side management, renewable energy, and similar regulatory programs, which are offset in operating revenues.

Depreciation and amortization Depreciation and amortization expenses were $4 million higher for the three months ended June 30, 2011 compared with the prior-year period primarily because of increased plant in service.

Taxes other than income taxes Taxes other than income taxes increased $8 million for the three months ended June 30, 2011 compared with the prior-year period primarily because of higher property tax rates in the current period.

Discontinued Operations

Income from discontinued operations for the period ended June 30, 2010 included a gain of $25 million after income taxes related to the sale of APSES’s district cooling business.

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Operating Results — Six-month period ended June 30, 2011 compared with six-month period ended June 30, 2010

Our consolidated net income attributable to common shareholders for the six months ended June 30, 2011 was $72 million, compared with net income of $109 million for the comparable prior-year period. The $37 million variance consists of a $25 million decrease in income from continuing operations and a $12 million decrease in income from discontinued operations. The reduction in results from continuing operations reflects a decrease of approximately $24 million for the regulated electricity segment primarily due to increased operations and maintenance expenses related to planned timing and level of maintenance at two of our gas-fired, combined-cycle generation plants and higher property taxes due to increased property tax rates. These negative factors were partially offset by increased revenues related to higher retail customer usage.

In addition, the decrease in income from discontinued operations is primarily due to a gain of $25 million in the prior-year period related to the sale of APSES’s district cooling business, partially offset by real estate impairment charges in the prior-year period.

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

	Six Months Ended June 30,
	2011			2010			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses (a)	$	991		$	944		$	47
Operations and maintenance (a)	(466		)	(420		)	(46		)
Depreciation and amortization	(213		)	(204		)	(9		)
Taxes other than income taxes	(78		)	(63		)	(15		)
Other income (expenses), net	(3		)	(5		)	2
Interest charges, net of allowances for funds used during construction	(103		)	(104		)	1
Income taxes	(45		)	(43		)	(2		)
Less income related to noncontrolling interests (Note 7)	(12		)	(10		)	(2		)
Regulated electricity segment income from continuing operations	71			95			(24		)

All other	(1		)	—			(1		)
Income from Continuing Operations Attributable to Common Shareholders	70			95			(25		)

Income from Discontinued Operations Attributable to Common Shareholders (b)	2			14			(12		)

Net Income Attributable to Common Shareholders	$	72		$	109		$	(37	)

(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. Income from discontinued operations for the period ended June 30, 2010 included a gain of $25 million after income taxes related to the sale of APSES’s district cooling business, partially offset by real estate impairment charges of $10 million after income taxes.

Regulated electricity segment

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

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Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $47 million higher for the six months ended June 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
Higher retail sales primarily due to higher usage per customer, excluding the effects of weather, but including the effects of APS’s energy efficiency programs	12			4			8
Higher demand-side management, renewable energy and similar regulatory surcharges (substantially offset in operations and maintenance expense)	9			1			8
Effects of weather on retail sales	7			4			3
Lower retail revenues related to refund of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense	(13		)	(16		)	3
Miscellaneous items, net	(7		)	(4		)	(3		)
Total	$	36		$	(11	)	$	47

Operations and maintenance Operations and maintenance expenses increased $46 million for the six months ended June 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 $12 million in generation costs, primarily due to planned timing and level of maintenance at two of our gas-fired combined-cycle generation plants;

· An increase of $7 million related to costs for demand-side management, renewable energy, and similar regulatory programs, which are offset in operating revenues; and

· A decrease of $1 million due to other miscellaneous factors.

Depreciation and amortization Depreciation and amortization expenses were $9 million higher for the six months ended June 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 $15 million for the six months ended June 30, 2011 compared with the prior-year period primarily because of higher property tax rates in the current period.

Income taxes Income taxes were $2 million higher for the six months ended June 30, 2011 compared with the prior-year period. This is primarily due to $9 million of income tax benefits recognized in the prior-year period related to a reduction in the Company’s 2010 effective income tax rate, partially offset by the effects of lower pretax income in the current period.

Discontinued Operations

Income from discontinued operations for the period ended June 30, 2010 included a gain of $25 million related to the sale of APSES’s district cooling business, partially offset by real estate impairment charges.

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 six months ended June 30, 2011 and 2010 (dollars in millions):

	Six Months Ended June 30,
	2011			2010
Net cash flow provided by operating activities	$	436		$	201
Net cash flow used for investing activities	(328		)	(278		)
Net cash flow used for financing activities	(126		)	(18		)

The increase of approximately $235 million in net cash provided by operating activities is primarily due to return of collateral and margin cash as a result of changes in commodity prices and expiration of prior hedge contracts, and a voluntary pension contribution in 2010 of approximately $100 million.

The increase of approximately $50 million in net cash used for investing activities is primarily due to approximately $100 million of proceeds from the sale of APSES’s district cooling business in June 2010, partially offset by $55 million of proceeds from the sale of life insurance policies in 2011.

The increase of approximately $108 million in net cash used for financing activities is primarily due to proceeds of approximately $253 million from the issuance of equity in April 2010, partially offset by lower repayments of short-term borrowings.

Cash Flows — Arizona Public Service Company Consolidated

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

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	Six Months Ended June 30,
	2011			2010
Net cash flow provided by operating activities	$	456		$	154
Net cash flow used for investing activities	(340		)	(380		)
Net cash flow provided by (used for) financing activities	(130		)	141

The increase of approximately $302 million in net cash provided by operating activities is primarily due to return of collateral and margin cash as a result of changes in commodity prices and expiration of prior hedge contracts; a voluntary pension contribution in 2010 of approximately $100 million; and income tax payments in 2010.

The decrease of approximately $40 million in net cash used for investing activities is primarily due to proceeds from the sale of life insurance policies in 2011.

The decrease of approximately $271 million in net cash provided by financing activities is primarily due to 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 six months ended June 30, 2011 and 2010 and the estimated capital expenditures for the next three years:

CAPITAL EXPENDITURES

(dollars in millions)

	Six Months Ended June 30,				Estimated for the Year Ended December 31,
	2010		2011		2011		2012		2013
APS
Generation:
Nuclear Fuel	$	51	$	48	$	67	$	68	$	69
Renewables	—		96		224		161		265
Environmental	2		5		11		22		122
Four Corners Units 4 and 5	—		—		—		294		—
Other Generation	71		53		143		152		107
Distribution	120		101		247		350		285
Transmission	61		48		136		220		248
Other (a)	26		22		59		49		41
Total APS	331		373		887		1,316		1,137
Other	3		—		—		—		—
Total	$	334	$	373	$	887	$	1,316	$	1,137

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(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 also reflects the additional funding included in 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 also 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.

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 June 24, 2011, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on September 1, 2011, to shareholders of record on August 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 June 30, 2011, APS’s common equity ratio, as defined, was 53%. Its total shareholder equity was approximately $3.7 billion, and total capitalization was approximately $7.1 billion. Under this order, APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.8 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.

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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. On July 25, 2011, we repaid $25 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. APS and other subsidiaries fund their respective shares of these contributions. APS’s share is approximately 99% of both plans.

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 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 will use the facility for bank borrowings, commercial paper program support and for the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit ratings.

At June 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 June 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.

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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 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.

Other Subsidiaries

SunCor — At June 30, 2011, SunCor had total remaining assets of approximately $12 million, which includes approximately $3 million of assets held for sale. At June 30, 2011, SunCor had no debt outstanding.

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 June 30, 2011, the ratio was approximately 50% for Pinnacle West and 47% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

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.

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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 July 26, 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. 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.

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Guarantees and Surety Bonds

We have issued $5 million of parental guarantees and obtained $98 million of surety bonds on behalf of APSES to offer energy-related products. These bonds relate to current projects and projects under warranty. Pinnacle West is negotiating the potential sale of its investment in APSES (see Note 13), and will be released of such parental guarantee and surety bond obligations upon closing of the sale. Pinnacle West has also issued parental guarantees and surety bonds for APS which are not material at June 30, 2011. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 10 for additional information regarding guarantees and letters of credit.

Contractual Obligations

Year	2011		2012-2013		2014-2015		Thereafter		Total
Purchase obligations (a)	$	0.2	$	0.2	$	—	$	0.3	$	0.7
Fuel and purchased power commitments	0.5		0.9		1.1		7.0		9.5
Renewable energy credits	0.1		—		0.1		0.3		0.5

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

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.

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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 Note 14). 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 qualify as derivatives, including exchange-traded futures and options and over-the-counter 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 six months ended June 30, 2011 and 2010 (dollars in millions):

	Six Months Ended June 30,
	2011			2010
Mark-to-market of net positions at beginning of period	$	(239	)	$	(169	)
Recognized in earnings:
Change in mark-to-market losses for future period deliveries	—			(4		)
Mark-to-market losses realized including ineffectiveness during the period	—			2
Decrease (increase) in regulatory asset	13			(37		)
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (a)	(15		)	(100		)
Mark-to-market losses realized during the period	40			42
Change in valuation techniques	—			—
Mark-to-market of net positions at end of period	$	(201	)	$	(266	)

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(a) 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 June 30, 2011 by maturities and by the type of valuation that is performed to calculate the fair values. 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 actively quoted	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Prices provided by other external sources	(81		)	(52		)	(19		)	(2		)	—			—			(154		)
Prices based on models and other valuation methods	(10		)	(8		)	(8		)	(6		)	(7		)	(8		)	(47		)
Total by maturity	$	(91	)	$	(60	)	$	(27	)	$	(8	)	$	(7	)	$	(8	)	$	(201	)

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 June 30, 2011 and December 31, 2010 (dollars in millions):

	June 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
Electricity	$	—	$	—		$	—	$	—
Natural gas	1		(1		)	1		(1		)
Regulatory asset, (liability) or OCI (a)
Electricity	13		(13		)	13		(13		)
Natural gas	44		(44		)	42		(42		)
Total	$	58	$	(58	)	$	56	$	(56	)

(a) 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.

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Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 14 — “Fair Value Measurements” 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 June 30, 2011. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’s disclosure controls and procedures as of June 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 June 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

See “Environmental Matters” in Item 5 below and 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 relating to FERC proceedings on Pacific Northwest energy market issues.

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, 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 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.

The operation of APS’s nuclear power plant exposes it to substantial regulatory oversight and potentially significant liabilities and capital expenditures.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. Events impacting the industry may lead the NRC to impose additional requirements and regulations on existing and new facilities. As a result of the March 2011 earthquake and tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, various industry organizations are working to analyze information from the Japan incident and develop action plans for U.S. nuclear power plants. Additionally, the NRC is performing its own independent review of the events at Fukushima Daiichi, including a review of the agency’s processes and regulations in order to determine whether the agency should promulgate additional regulations and possibly make more fundamental changes to the NRC’s system of regulation. We cannot predict when or if the NRC will take formal action as a result of its review. The financial and/or operational impacts on Palo Verde and APS may be significant.

In the event of noncompliance with its requirements, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime that could ultimately result in the shut down of a unit, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. The increased costs resulting from penalties, a heightened level of scrutiny and implementation of plans to achieve compliance with NRC requirements may adversely affect APS’s financial condition, results of operations and cash flows.

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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. The court has not yet scheduled oral arguments on the plaintiffs’ appeal. 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. We believe the action in Kivalina is without merit and intend to 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.

Four Corners and the Navajo Plant. In addition to the other BART-related matters discussed in “Business of Arizona Public Service Company — Environmental Matters — EPA Environmental Regulation — Regional Haze Rules” in Item 1 of the 2010 Form 10-K, on February 16, 2010, a group of environmental organizations filed a petition with the Departments of Interior and Agriculture requesting those agencies to certify to the EPA that visibility impairment in sixteen national park and wilderness areas is reasonably attributable to emissions from Four Corners, the Navajo Plant and other non-APS plants. If the agencies certify impairment, the EPA is required to evaluate and, if necessary, determine BART for Four Corners and the Navajo Plant under a different haze program known as “Reasonably Attributable Visibility Impairment.” On January 19, 2011, a similar group of environmental organizations filed a lawsuit against the Departments of Interior and Agriculture, alleging among other things that the agencies failed to act on the February 2010 petition “without unreasonable delay” and requesting the court to order the agencies to act on the petition within 30 days. On June 30, 2011, the court issued its opinion dismissing the plaintiffs’ claims explaining that because the Departments of Interior and Agriculture reached a “definitive decision” to deny the plaintiffs’ petitions, the court is unable to grant further relief to the plaintiffs and, therefore, their claims must be dismissed as moot.

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Review of New Sources and Modifications in Indian Country. Pursuant to its authority under the Clean Air Act, on June 11, 2011, the EPA finalized a Federal Implementation Plan (“FIP”), which puts in place a pre-construction air permitting program for construction of new and modified small facilities and minor modifications of existing facilities in Indian country. The FIP will require a source owner or operator to apply for a permit before building a new facility or modifying an existing one if it is determined that the proposed project will increase emissions above any of the minor New Source Review thresholds included in the rule. Among other things, sources triggering the rule’s source-specific permit requirements will be required to undergo a case-by-case control technology review and, potentially, an air impact quality analysis. We are currently evaluating the potential impact of this rule on Four Corners and the Navajo Plant, the two APS co-owned power plants located on Indian lands.

Water Supply

Little Colorado River Adjudication. APS has filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’s claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’s water rights claims has been set in this matter.

A number of parties, including APS, the Navajo Nation, the Hopi Tribe, and other claimants in the Little Colorado River Adjudication have been engaged in settlement negotiations to resolve competing water claims. On June 3, 2011, counsel for all the parties to the settlement discussions, including APS, signed, on behalf of their respective clients, a document expressing their agreement to recommend that the settlement be approved by their respective clients. If ultimately approved by the parties, United States Congress and the Arizona legislature, APS believes this settlement would be beneficial to protecting APS’s interest through its resolution of any and all claims that the Navajo Nation and the Hopi Tribe may have to the Little Colorado River system and source in Arizona.

Although the above matters remain subject to further evaluation, APS does not expect that the described litigation or settlement will have a material adverse impact on its financial position, results of operations, cash flows or liquidity.

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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: August 2, 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: August 2, 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