FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

(Mark One)

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

For the quarterly period ended March 31, 2010

OR

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

For the transition period from                      to                     

	Exact Name of Each Registrant as specified in its
Commission File	charter; State of Incorporation; Address; and	IRS Employer
Number	Telephone Number	Identification No.
1-8962	PINNACLE WEST CAPITAL CORPORATION	86-0512431
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, Arizona 85072-3999
	(602) 250-1000
1-4473	ARIZONA PUBLIC SERVICE COMPANY	86-0011170
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, Arizona 85072-3999
	(602) 250-1000

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 þ No o
ARIZONA PUBLIC SERVICE COMPANY	Yes þ 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 o No o
ARIZONA PUBLIC SERVICE COMPANY	Yes o 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 þ	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 þ	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 þ
ARIZONA PUBLIC SERVICE COMPANY	Yes o No þ

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 May 3, 2010: 108,447,282
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of May 3, 2010: 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.

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		40
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		47
Item 3. Quantitative and Qualitative Disclosures About Market Risk		67
Item 4. Controls and Procedures		67
Part II		68
Item 1. Legal Proceedings		68
Item 1A. Risk Factors		68
Item 5. Other Information		68
Item 6. Exhibits		72
Signatures		75
Exhibit 10.1
Exhibit 10.2
Exhibit 10.3
Exhibit 10.4
Exhibit 12.1
Exhibit 12.2
Exhibit 12.3
Exhibit 31.1
Exhibit 31.2
Exhibit 31.3
Exhibit 31.4
Exhibit 32.1
Exhibit 32.2

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 relates to APS, and Supplemental Notes, which only relate to APS’ Condensed Consolidated Financial Statements. Item 2 of this report is divided into two sections — Pinnacle West Consolidated and APS. The Pinnacle West Consolidated section describes Pinnacle West and its subsidiaries on a consolidated basis, including discussions of Pinnacle West’s regulated utility and non-utility operations.

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by applicable law. 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, 2009 (“2009 Form 10-K”) and in Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operation herein, these factors include, but are not limited to:

• regulatory and judicial decisions, developments and proceedings;

• our ability to achieve timely and adequate rate recovery of our costs;

• our ability to reduce 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;

• power plant performance and outages;

• volatile fuel and purchased power costs;

• fuel and water supply availability;

• new legislation or regulation relating to greenhouse gas emissions, renewable energy mandates 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 credit, financial and real estate market conditions;

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

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

• our ability, or the ability of our subsidiaries, to meet debt service obligations;

• 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;

• 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;

• transmission and distribution 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 ability of our counterparties and power plant participants to meet contractual or other obligations;

• technological developments in the electric industry; and

• economic and other conditions affecting the real estate market in SunCor Development Company’s (“SunCor”) market areas.

These and other factors are discussed in Risk Factors described in Item 1A of our 2009 Form 10-K, which readers should review carefully before placing any reliance on our financial statements or disclosures.

2

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
	March 31,
	2010			2009
OPERATING REVENUES
Regulated electricity segment	$	611,425		$	602,578
Real estate segment		9,416			14,840
Other revenues		12,750			8,449
Total		633,591			625,867
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		215,540			247,388
Real estate segment operations		13,890			26,910
Real estate impairment charge (Note 20)		15,112			208,480
Operations and maintenance		209,991			197,616
Depreciation and amortization		101,536			101,812
Taxes other than income taxes		31,827			34,128
Other expenses		8,061			6,467
Total		595,957			822,801
OPERATING INCOME (LOSS)		37,634			(196,934	)
OTHER
Allowance for equity funds used during construction		5,389			4,992
Other income (Note 14)		2,395			537
Other expense (Note 14)		(2,696	)		(9,741	)
Total		5,088			(4,212	)
INTEREST EXPENSE
Interest charges		62,054			59,035
Capitalized interest		(3,080	)		(3,834	)
Total		58,974			55,201
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(16,252	)		(256,347	)
INCOME TAXES		(15,480	)		(95,004	)
LOSS FROM CONTINUING OPERATIONS		(772	)		(161,343	)
LOSS FROM DISCONTINUED OPERATIONS
Net of income tax benefit of $81 and $3,063 (Note 17)		(125	)		(4,727	)
NET LOSS		(897	)		(166,070	)
Less: Net income (loss) attributable to noncontrolling interests (Notes 9 and 20)		5,117			(9,560	)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(6,014	)	$	(156,510	)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		101,474			100,986
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		101,474			100,986
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Loss from continuing operations attributable to common shareholders — basic	$	(0.06	)	$	(1.50	)
Net loss attributable to common shareholders — basic	$	(0.06	)	$	(1.55	)
Loss from continuing operations attributable to common shareholders — diluted	$	(0.06	)	$	(1.50	)
Net loss attributable to common shareholders — diluted	$	(0.06	)	$	(1.55	)
DIVIDENDS DECLARED PER SHARE	$	0.525		$	0.525
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Loss from continuing operations, net of tax	$	(5,889	)	$	(151,783	)
Discontinued operations, net of tax		(125	)		(4,727	)
Net loss attributable to common shareholders	$	(6,014	)	$	(156,510	)

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

3

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	March 31,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,528		$	145,378
Customer and other receivables		215,062			301,915
Accrued unbilled revenues		86,466			110,971
Allowance for doubtful accounts		(5,892	)		(6,153	)
Materials and supplies (at average cost)		171,118			176,020
Fossil fuel (at average cost)		37,907			39,245
Deferred income taxes		77,915			53,990
Income tax receivable (Note 8)		19,503			26,005
Assets from risk management activities (Note 10)		75,421			50,619
Other current assets		39,583			30,747
Total current assets		720,611			928,737
INVESTMENTS AND OTHER ASSETS
Real estate investments — net (Note 20)		104,177			119,989
Assets from risk management activities (Note 10)		40,763			28,855
Nuclear decommissioning trust (Note 18)		433,399			414,576
Other assets		112,571			110,091
Total investments and other assets		690,910			673,511
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		12,849,716			12,848,138
Less accumulated depreciation and amortization		(4,349,437	)		(4,340,645	)
Net		8,500,279			8,507,493
Construction work in progress		528,940			467,700
Palo Verde sale leaseback, net of accumulated depreciation (Note 9)		144,528			146,722
Intangible assets, net of accumulated amortization		169,912			164,380
Nuclear fuel, net of accumulated amortization		142,254			118,243
Total property, plant and equipment		9,485,913			9,404,538
DEFERRED DEBITS
Regulatory assets		863,233			813,161
Income tax receivable (Note 8)		65,103			65,103
Other		109,149			101,274
Total deferred debits		1,037,485			979,538
TOTAL ASSETS	$	11,934,919		$	11,986,324

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

4

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	March 31,			December 31,
	2010			2009
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	219,888		$	240,637
Accrued taxes		127,513			104,011
Accrued interest		53,336			54,596
Short-term borrowings		289,616			153,715
Current maturities of long-term debt (Note 4)		489,626			303,476
Customer deposits		70,484			71,026
Liabilities from risk management activities (Note 10)		52,469			55,908
Other current liabilities		90,794			125,574
Total current liabilities		1,393,726			1,108,943
LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt (Note 4)		3,180,476			3,370,524
Palo Verde sale leaseback lessor notes (Notes 4 and 9)		126,000			126,000
Total long-term debt less current maturities		3,306,476			3,496,524
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,582,660			1,496,095
Deferred fuel and purchased power regulatory liability (Note 5)		105,378			87,291
Other regulatory liabilities		670,023			679,072
Liability for asset retirements		306,868			301,783
Liabilities for pension and other postretirement benefits (Note 6)		723,959			811,338
Liabilities from risk management activities (Note 10)		79,194			62,443
Customer advances		134,030			136,595
Coal mine reclamation		92,303			92,060
Unrecognized tax benefits (Note 8)		76,632			142,099
Other		133,670			144,077
Total deferred credits and other		3,904,717			3,952,853
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 11)
Common stock, no par value		2,155,977			2,153,295
Treasury stock		(2,734	)		(3,812	)
Total common stock		2,153,243			2,149,483
Retained earnings		1,238,940			1,298,213
Accumulated other comprehensive loss:
Pension and other postretirement benefits		(50,048	)		(50,892	)
Derivative instruments		(128,202	)		(80,695	)
Total accumulated other comprehensive loss		(178,250	)		(131,587	)
Total Pinnacle West shareholders’ equity		3,213,933			3,316,109
Noncontrolling interests (Note 9)		116,067			111,895
Total equity		3,330,000			3,428,004
TOTAL LIABILITIES AND EQUITY	$	11,934,919		$	11,986,324

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

5

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)

	Three Months Ended
	March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(897	)	$	(166,070	)
Adjustments to reconcile net loss to net cash used for operating activities:
Depreciation and amortization including nuclear fuel		114,122			112,000
Deferred fuel and purchased power		44,040			28,238
Deferred fuel and purchased power amortization		(25,953	)		28,961
Allowance for equity funds used during construction		(5,389	)		(4,992	)
Real estate impairment charge		15,112			215,869
Deferred income taxes		50,845			(3,901	)
Change in mark-to-market valuations		1,842			3,822
Changes in current assets and liabilities:
Customer and other receivables		60,244			76,390
Accrued unbilled revenues		24,505			15,365
Materials, supplies and fossil fuel		6,240			(11,796	)
Other current assets		(8,836	)		(711	)
Accounts payable		(23,334	)		(78,090	)
Accrued taxes and income tax receivable-net		30,004			(81,846	)
Other current liabilities		(36,582	)		(29,658	)
Expenditures for real estate investments		(443	)		(1,459	)
Gains and other changes in real estate assets		4,095			(264	)
Change in margin and collateral accounts — assets		(11,280	)		(23,476	)
Change in margin and collateral accounts — liabilities		(124,495	)		(162,013	)
Change in unrecognized tax benefits		(62,062	)		(1,050	)
Change in other long-term assets		(25,903	)		8,897
Change in other long-term liabilities		(39,550	)		19,618
Net cash flow used for operating activities		(13,675	)		(56,166	)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(202,554	)		(193,014	)
Contributions in aid of construction		2,949			18,762
Capitalized interest		(3,080	)		(3,834	)
Proceeds from nuclear decommissioning trust sales		158,448			129,816
Investment in nuclear decommissioning trust		(164,552	)		(135,264	)
Other		(1,639	)		1,501
Net cash flow used for investing activities		(210,428	)		(182,033	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		—			499,683
Repayment and reacquisition of long-term debt		(4,150	)		(16,386	)
Short-term borrowings and payments — net		135,901			(263,464	)
Dividends paid on common stock		(51,421	)		(51,196	)
Common stock equity issuance		844			815
Other		1,079			(3,694	)
Net cash flow provided by financing activities		82,253			165,758
NET DECREASE IN CASH AND CASH EQUIVALENTS		(141,850	)		(72,441	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		145,378			105,245
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,528		$	32,804
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	(5,547	)	$	17,602
Interest, net of amounts capitalized	$	58,679		$	46,040

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

6

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, APS Energy Services Company, Inc. (“APSES”), and El Dorado Investment Company (“El Dorado”). 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 sale leaseback variable interest entities (see Note 9 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.

2. Condensed Consolidated Financial Statements

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 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 17) and amended accounting guidance on consolidation of variable interest entities (see Note 9).

3. Quarterly Fluctuations

Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate activities, such as the real estate impairment charges recorded in 2009 and 2010 (see Note 20), can have significant impacts on our results for interim periods. For these reasons, results for interim periods do not necessarily represent results expected for the year.

4. Long-term Debt and Liquidity Matters

The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements as of March 31, 2010 (dollars in millions):

	Consolidated
Year	Pinnacle West		APS
2010	$	315	$	223
2011		632		457
2012		478		478
2013		59		59
2014		503		503
Thereafter		1,816		1,816
Total	$	3,803	$	3,536

7

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Credit Facilities and Debt Issuances

Pinnacle West and APS maintain credit facilities in order to enhance liquidity and provide credit support. During the first quarter of 2010, Pinnacle West and APS refinanced existing revolving credit facilities that would have matured in December 2010. In addition, Pinnacle West and APS accessed the commercial paper market, which neither company had utilized since the third quarter of 2008 due to negative market conditions.

Pinnacle West

On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. The new facility matures February 2013. 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. Pinnacle West will use the facility for general corporate purposes, repayment of long-term debt, commercial paper support and for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. As a result of the downsized revolving credit facility, the Company also reduced the size of its commercial paper program to $200 million from $250 million.

At March 31, 2010, the $200 million revolver was available to support the issuance of up to $200 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit up to $100 million. At March 31, 2010 the Company had outstanding $10 million of borrowings under its revolving credit facility and no letters of credit. In addition, Pinnacle West had commercial paper borrowings of $80 million at March 31, 2010.

In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the proceeds from this offering to APS. APS anticipates using these capital contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

APS

On February 12, 2010, APS refinanced its $377 million revolving credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2013. APS has the option to 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 support and for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.

At March 31, 2010 APS had two committed revolving credit facilities totaling $989 million, including the $500 million credit facility described above and a $489 million facility that terminates in September 2011. The revolvers are available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit up to $739 million. At March 31, 2010, APS had borrowings of $70 million under its $489 million credit facility and no letters of credit under its revolving credit facilities. APS had commercial paper borrowings of $125 million at March 31, 2010.

8

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On January 1, 2010, due to the adoption of amended accounting guidance relating to variable interest entities (“VIEs”), APS began consolidating the Palo Verde Lessor Trusts (see Note 9) and, as a result of consolidation of these VIEs, we have reported the Lessor Trusts’ long-term debt on our Condensed Consolidated Balance Sheets. Interest rates on these debt instruments are 8% and are fixed for the remaining life. As of March 31, 2010, approximately $26 million was classified as current maturities of long-term debt and $126 million was classified as long-term debt relating to these VIEs. These debt instruments mature on December 30, 2015 and have sinking fund features that are serviced by the lease payments. See Note 9 for additional discussion of the VIEs.

SunCor

SunCor’s principal loan facility (the “SunCor Secured Revolver”) is secured primarily by an interest in land, commercial properties and land contracts. At March 31, 2010, SunCor had outstanding borrowings of approximately $54 million under the SunCor Secured Revolver, which matured on January 30, 2010. SunCor and the lenders under the SunCor Secured Revolver have signed a forbearance agreement under which the lenders have agreed not to exercise any remedies prior to June 30, 2010 to allow time for SunCor to continue discussions concerning the potential sale of additional properties. In addition to the SunCor Secured Revolver, at March 31, 2010, SunCor had approximately $42 million of outstanding debt under other credit facilities ($26 million of which has matured and remains outstanding). To date, the lenders under these credit facilities have taken no enforcement action. At March 31, 2010, $92 million was classified as current maturities of long-term debt and $4 million was classified as short-term borrowings on our Condensed Consolidated Balance Sheets.

If SunCor is unable to obtain extensions or renewals of the SunCor Secured Revolver or its other matured debt, or if it is unable to comply with the mandatory repayment and other provisions of any new or modified credit agreements, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such an immediate repayment obligation would have a material adverse impact on SunCor’s business and financial position and impair its ongoing viability.

SunCor cannot predict the outcome of negotiations with its lenders or its ability to sell assets for sufficient proceeds to repay its outstanding debt (see Note 20). SunCor’s ability to generate sufficient cash from operations while it pursues lender negotiations and further asset sales is uncertain.

Neither Pinnacle West nor any of its other subsidiaries has guaranteed any SunCor indebtedness. A SunCor debt default would not result in a cross-default of any of the debt of Pinnacle West or any of its other subsidiaries. While there can be no assurances as to the ultimate outcome of this matter, Pinnacle West does not believe that SunCor’s inability to obtain extensions or renewals from SunCor’s lenders would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

As of March 31, 2010, SunCor could not transfer any cash dividends to Pinnacle West as a result of the covenants mentioned above. The restriction does not affect Pinnacle West’s ability to meet its ongoing capital requirements.

9

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At March 31, 2010, APS’ common equity ratio, as defined, was 50%. Its total common equity was approximately $3.4 billion, and total capitalization was approximately $6.7 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.7 billion, assuming APS’ total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

5. Regulatory Matters

2008 General Retail Rate Case Impacts

On December 30, 2009, the ACC issued an order approving a settlement agreement (“Settlement Agreement”) entered into by APS and twenty-one other parties to its general retail rate case, which was originally filed in March 2008. The Settlement Agreement contains 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’ next general rate case, if that is before the end of 2012), resulting in present estimates of increased revenues of $23 million, $25 million and $49 million, respectively;

• An authorized return on common equity of 11.0%;

• 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;

• 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 as of May 6, 2010 from proceeds of a Pinnacle West equity issuance (see Note 4)); 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.

The parties also agreed to a rate case filing plan in which APS is prohibited from filing its next two general rate cases until on or after June 1, 2011 and June 1, 2013, respectively, unless certain extraordinary events occur. Subject to the foregoing, APS may not request its next general retail rate increase to be effective prior to July 1, 2012. APS currently expects it will file its next rate case in June 2011. The parties agreed to use good faith efforts to process these subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cost Recovery Mechanisms

APS has received supportive 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 on 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 the upcoming year’s RES funding amount.

During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval. The plan provides for the acquisition of renewable generation in compliance with requirements through 2014, and requests RES funding of $86.7 million for 2010. APS also sought various other determinations in its plan, including approval of the AZ Sun program and the Community Power Project in Flagstaff, Arizona. At its December 2009 open meeting, the ACC approved APS’ 2010 RES funding request.

On March 3, 2010, the ACC approved the AZ Sun program, which contemplates the addition of 100 megawatts (“MW”) of utility-owned solar resources through 2014. Through the expected life of the program, APS plans to invest up to $500 million for turn-key photovoltaic power plants across Arizona. Developers will be selected through competitive procurement processes to build the plants, which APS will own. 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. The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’s next 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 solar panels on the rooftops of up to 200 residential and business customers located within a certain test area. Third party developers may also own systems that participate in the pilot. Costs of the program will be recovered through the RES until such time as the costs are recovered in base rates.

Demand-Side Management Adjustor Charge (“DSMAC”). The Settlement Agreement 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 has estimated a budget in the amount of $49.9 million for 2010. In order to recover these estimated amounts for use on certain demand-side management programs, a surcharge would be added to customer bills similar to that described above under the RES. The surcharge will offset energy efficiency expenses and allow for the recovery of any earned incentives. APS received ACC approval of all of its proposed programs and implemented the new DSMAC on March 1, 2010.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The ACC approved recovery of the 2010 Energy Efficiency budget less some $1.0 million, which reflected a recalculation of the incentive payment due to APS under the Energy Efficiency Implementation Plan and not a reduction in allowed program costs. The ACC also 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.

PSA Mechanism and Balance. The power supply adjustor (“PSA”) provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for the three-month periods ended March 31, 2010 and 2009 (dollars in millions):

	Three Months Ended
	March 31,
	2010			2009
Beginning balance	$	(87	)	$	8
Deferred fuel and purchased power costs-current period		(44	)		(28	)
Amounts refunded (recovered)		26			(29	)
Ending balance	$	(105	)	$	(49	)

The PSA rate for the current PSA Year is ($0.0045) per kilowatt hour (“kWh”). Since the 2010 PSA adjustment was a reduction of the PSA rate, the ACC accelerated the 2010 adjustment from the standard PSA year start date of February 1^st to January 1^st to coincide with the increase in retail rates resulting from the ACC’s decision in the general retail rate case, causing a minimal net impact on residential bills. This accelerated 2010 adjustment will remain in effect until February 1, 2011. The $105 million regulatory liability at March 31, 2010 reflects lower average prices and the seasonal nature of fuel and purchased power costs. Any uncollected (overcollected) deferrals during the 2010 PSA Year will be included in the historical component of the PSA rate for the PSA Year beginning February 1, 2011.

The PSA rate for the PSA Year that began February 1, 2009 was $0.0053 per kWh. The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

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 the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’ 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 under the transmission cost adjustor (“TCA”) mechanism, by which changes in Retail Transmission Charges can be reflected in APS’ retail rates.

The formula rate is updated, or “trued-up”, each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ 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 have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In 2009, APS was authorized to implement an increase in its annual transmission revenues based on calculations filed with the FERC using data for its 2008 fiscal year. Increases in APS’ annual transmission revenues of $22.8 million became effective June 1, 2009. Of this amount, $21 million represents an increase in Retail Transmission Charges, which was approved by the ACC on July 29, 2009 and allows APS to reflect the related increased Retail Transmission Charges in its retail rates through the TCA effective August 1, 2009. The 2010 TCA will be filed with the ACC in mid-May.

6. 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.

On March 23, 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act (the “Act”). One feature of the Act is the elimination of the tax deduction for prescription drug costs that are reimbursed as part of the Medicare Part D subsidy. Although this tax increase does not take effect until 2013, we are required to recognize the full accounting impact in our financial statements in the period in which the Act is signed. In accordance with accounting for regulated companies, the loss of this deduction is substantially offset by a regulatory asset that will be recovered through future electric revenues. In the first quarter of 2010, Pinnacle West charged regulatory assets and liabilities for a total of $42 million, with a corresponding increase in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in millions):

	Pension Benefits						Other Benefits
	Three Months						Three Months
	Ended March 31,						Ended March 31,
	2010			2009			2010			2009
Service cost — benefits earned during the period	$	15		$	14		$	5		$	5
Interest cost on benefit obligation		31			29			11			10
Expected return on plan assets		(31	)		(29	)		(10	)		(9	)
Amortization of:
Transition obligation		—			—			1			1
Prior service cost		1			1			—			—
Net actuarial loss		6			3			3			3
Net periodic benefit cost	$	22		$	18		$	10		$	10
Portion of cost charged to expense	$	11		$	8		$	5		$	5
APS’ share of cost charged to expense	$	10		$	8		$	5		$	5

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Contributions

The required minimum contribution to our pension plan is zero in 2010. During the first quarter of 2010 we made a voluntary contribution of $100 million to our pension plan. The contribution to our other postretirement benefit plans in 2010 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.

7. Business Segments

Pinnacle West’s two reportable business segments are:

• 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; and

• our real estate segment, which consists of SunCor’s real estate development and investment activities

Financial data for the three months ended March 31, 2010 and 2009 and at March 31, 2010 and December 31, 2009 is provided as follows (dollars in millions):

	Three Months Ended
	March 31,
	2010			2009
Operating revenues:
Regulated electricity segment	$	611		$	603
Real estate segment (a)		10			15
All other (b)		13			8
Total	$	634		$	626
Net income (loss) attributable to common shareholders:
Regulated electricity segment	$	7		$	(20	)
Real estate segment (a)		(13	)		(132	)
All other (b)		—			(5	)
Total	$	(6	)	$	(157	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	As of		As of
	March 31, 2010		December 31, 2009
Assets:
Regulated electricity segment	$	11,686	$	11,691
Real estate segment (a)		133		161
All other (b)		116		134
Total	$	11,935	$	11,986

(a)	In 2009 our real estate subsidiary, SunCor, began disposing of substantially all of its assets (see Note 20). As a result, the real estate segment may no longer be a reporting segment in the future.
(b)	Includes activities related to APSES and El Dorado. None of the activities of either of these companies constitutes a reportable segment.

8. Income Taxes

Pinnacle West expects to recognize approximately $131 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 20), which will not be fully realized until all the asset sale transactions are completed. Approximately $6 million of these benefits were recorded in the three months ended March 31, 2010 as reductions to income tax expense related to the current impairment charges. The additional $125 million of tax benefits were recorded as reductions to income tax expense related to SunCor impairment charges recorded on or before December 31, 2009.

The $85 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 and the current year tax benefits related to the SunCor strategic asset sales that closed prior to March 31, 2010.

During the first quarter of 2010, the Company reached a settlement with the IRS with regard to the examination of tax returns for the years ended December 31, 2005 through 2007. As a result of this settlement, net uncertain tax positions have decreased by $62 million through March 31, 2010, including approximately $3.5 million which decreased our effective tax rate. Additionally, the settlement resulted in the recognition of net interest benefits of approximately $3 million through the effective tax rate.

As of March 31, 2010, 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 1999.

9. Variable Interest Entities

On January 1, 2010 we adopted amended accounting guidance relating to VIEs. This amended guidance significantly changed the consolidation model for VIEs. Under the prior guidance the consolidation model considered risk absorption using a quantitative approach when determining the primary beneficiary. The consolidation model under the new guidance requires a qualitative assessment and focuses on the powers to direct activities of the VIE when determining the primary beneficiary. As a result of applying this qualitative assessment we have determined that APS is the primary beneficiary of certain VIEs, and is therefore required to consolidate these VIEs. Prior to adopting this new guidance APS was not considered the primary beneficiary of these VIEs and did not consolidate these entities. We have adopted this guidance using retrospective application and have adjusted prior periods presented to reflect consolidation of the VIEs in those periods. Further discussion follows regarding the impact of the consolidation.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS VIEs

In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Nuclear Generating Station (“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 2010 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 we are the operating agent for Palo Verde, are obligated to decommission the leased assets and have fair value purchase options.

Under the previous quantitative VIE consolidation model, APS was not considered the primary beneficiary of the lessor trusts as APS did not absorb the majority of the entities’ expected losses or did not receive a majority of the residual returns. The arrangements were previously accounted for as operating leases.

Consolidation of these VIEs eliminates the lease accounting we previously reported 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 and for payment to the noncontrolling interest holders. The creditors of the VIEs have no recourse to the general credit of APS or Pinnacle West. As a result of consolidation we have eliminated rent expense, and have recognized depreciation and interest expense, resulting in an increase in net income of $5 million 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 March 31, 2010 include the following amounts relating to the VIEs (in millions):

	March 31,
	2010
Property plant and equipment, net of accumulated depreciation	$	145
Long-term debt including current maturities		152
Equity- Noncontrolling interests		87

For regulatory ratemaking purposes the leases continue to be treated as operating leases, and as a result we have recorded a regulatory asset of $32 million as of March 31, 2010.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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 March 31, 2010, APS would have been required to pay the noncontrolling equity participants approximately $153 million and assume $152 million of debt. Since APS now consolidates the VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

We also have certain long-term purchased power agreements to purchase substantially all of an entity’s output from a specified facility for a specified period. We have evaluated these arrangements under the VIE accounting guidance and have determined that these agreements do not represent variable interests. If these agreements had been deemed variable interests in these entities, we would not be considered the primary beneficiary of these entities, as we do not have the power to direct activities of these entities in a manner that would significantly impact their economic performance and therefore would not consolidate the entities. The adoption of the amended accounting guidance has not changed how we account for these arrangements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Prior-Year Periods

We have elected to apply the amended guidance retrospectively for all prior periods presented on Pinnacle West’s Condensed Consolidated Statements of Income, Balance Sheets, and Statements of Cash Flows. The following table presents the financial statement line item changes (dollars in thousands):

				Reclassifications as a			Amount reported
				result of the adoption of			after adoption of
	As previously			new VIE accounting			amended VIE
	reported			guidance			accounting guidance
Statement of Income for the three months ended March 31, 2009
Operating Expenses — Operations and maintenance	$	207,531		$	(9,915	)	$	197,616
Operating Expenses — Depreciation and amortization		99,886			1,926			101,812
Interest Expense — Interest Charges		55,696			3,339			59,035
Loss from Continuing Operations		(165,993	)		4,650			(161,343	)
Net Loss		(170,720	)		4,650			(166,070	)
Net income (loss) attributable to noncontrolling interests		(14,210	)		4,650			(9,560	)
Balance Sheets — December 31, 2009
Property, Plant and Equipment — Palo Verde sale leaseback, net of accumulated depreciation	$	—		$	146,722		$	146,722
Deferred Debits — Regulatory assets		781,714			31,447			813,161
Current Liabilities — Current maturities of long-term debt		277,693			25,783			303,476
Long-Term Debt Less Current Maturities — Palo Verde sale leaseback lessor notes		—			126,000			126,000
Deferred Credits and Other — Other		200,015			(55,938	)		144,077
Equity — Noncontrolling Interests		29,571			82,324			111,895
Statement of Cash Flows for the three months ended March 31, 2009
Cash Flows from Operating Activities — Net loss	$	(170,720	)	$	4,650		$	(166,070	)
Cash Flows from Operating Activities — Depreciation and amortization including nuclear fuel		110,073			1,927			112,000
Cash Flows from Operating Activities — Change in other current liabilities		(20,744	)		(8,914	)		(29,658	)
Cash Flows from Operating Activities — Change in other long-term liabilities		17,281			2,337			19,618

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SunCor VIEs

SunCor is the primary beneficiary of certain land development trust arrangements and, accordingly, consolidates these VIEs. We have determined that SunCor is the primary beneficiary of these VIEs because SunCor controls the activities related to the development of the land held in the trusts. Our adoption of amended VIE accounting guidance has not changed our accounting treatment of the SunCor VIEs. Our Condensed Consolidated Balance Sheets reflect $29 million of assets and $29 million of noncontrolling equity interests relating to these arrangements at March 31, 2010 and December 31, 2009. The assets relating to these VIEs consist strictly of land, all of which is restricted and may only be used for payment to the noncontrolling interests. We have not provided, and are not required to provide, financing or other financial support to these entities.

10. Derivative and Energy Trading 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.

Our derivative instruments are accounted for at fair value and are presented on the Condensed Consolidated Balance Sheets as “Assets/Liabilities from Risk Management Activities” (see Note 19 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 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 between 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 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 March 31, 2010, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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’ retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”), which is currently $0.0376 per kWh (see Note 5). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of March 31, 2010, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power		15,928,321	megawatt hours
Gas		157,264,840	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 months ended March 31, 2010 and 2009 (dollars in thousands):

		Three Months Ended
	Financial Statement	March 31,
Commodity Contracts	Location	2010			2009
Amount of Loss Recognized in AOCI on Derivative Instruments (Effective Portion)	Accumulated other comprehensive loss-derivative instruments	$	(91,667	)	$	(138,548	)
Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)	Regulated electricity segment fuel and purchased power		(13,185	)		(25,365	)
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		(10,467	)		992

(a) During the three months ended March 31, 2010 and 2009, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During the next twelve months, we estimate that a net loss of $118 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.

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 months ended March 31, 2010 and 2009 (dollars in thousands):

		Three Months Ended
	Financial Statement	March 31,
Commodity Contracts	Location	2010			2009
Amount of Net Gain (Loss) Recognized in Income from Derivative Instruments	Regulated electricity segment revenue	$	170		$	(429	)
Amount of Net Loss Recognized in Income from Derivative Instruments	Regulated electricity segment fuel and purchased power expense		(34,969	)		(63,964	)
Total		$	(34,799	)	$	(64,393	)

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 balance sheet. These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of March 31, 2010 (dollars in thousands):

				Investments			Current			Deferred Credits			Total Assets
Commodity Contracts	Current Assets			and Other Assets			Liabilities			and Other			(Liabilities)
Derivatives designated as accounting hedging instruments:
Assets	$	—		$	—		$	—		$	18		$	18
Liabilities		(1,381	)		—			(132,258	)		(112,704	)		(246,343	)
Total hedging instruments		(1,381	)		—			(132,258	)		(112,686	)		(246,325	)
Derivatives not designated as accounting hedging instruments:
Assets		41,278			40,780			59,403			47,986			189,447
Liabilities		(2,384	)		(17	)		(117,972	)		(103,669	)		(224,042	)
Total non-hedging instruments		38,894			40,763			(58,569	)		(55,683	)		(34,595	)
Total derivatives		37,513			40,763			(190,827	)		(168,369	)		(280,920	)
Margin account		20,402			—			9,336			258			29,996
Collateral provided to counterparties		23,256			—			130,072			88,917			242,245
Collateral provided from counterparties		(5,750	)		—			(1,050	)		—			(6,800	)
Balance Sheet Total	$	75,421		$	40,763		$	(52,469	)	$	(79,194	)	$	(15,479	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2009 (dollars in thousands):

				Investments			Current			Deferred Credits			Total Assets
Commodity Contracts	Current Assets			and Other Assets			Liabilities			and Other			(Liabilities)
Derivatives designated as accounting hedging instruments:
Assets	$	329		$	—		$	3,242		$	75		$	3,646
Liabilities		(3,436	)		(256	)		(72,899	)		(77,953	)		(154,544	)
Total hedging instruments		(3,107	)		(256	)		(69,657	)		(77,878	)		(150,898	)
Derivatives not designated as accounting hedging instruments:
Assets		31,220			29,807			34,645			44,631			140,303
Liabilities		(4,123	)		(696	)		(81,722	)		(71,408	)		(157,949	)
Total non-hedging instruments		27,097			29,111			(47,077	)		(26,777	)		(17,646	)
Total derivatives		23,990			28,855			(116,734	)		(104,655	)		(168,544	)
Margin account		8,643			—			12,464			104			21,211
Collateral provided to counterparties		17,986			—			49,412			42,108			109,506
Collateral provided from counterparties		—			—			(1,050	)		—			(1,050	)
Balance Sheet Total	$	50,619		$	28,855		$	(55,908	)	$	(62,443	)	$	(38,877	)

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 one counterparty for which our exposure represents approximately 31% of Pinnacle West’s $116 million of risk management assets as of March 31, 2010. This exposure relates to a long-term traditional wholesale contract with a counterparty that has 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 single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 2010 was $425 million, for which we had posted collateral of $222 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 rating were to fall below investment grade (below BBB- for Standard & Poor’s Ratings Services (“Standard & Poor’s”) or Fitch, Inc. (“Fitch”) or Baa3 for Moody’s Investors Service, Inc. (“Moody’s”)), which would be a violation of the credit rating provisions. If the investment grade contingent features underlying these agreements had been triggered on March 31, 2010, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $80 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 $200 million if our debt credit ratings were to fall below investment grade.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

11. Changes in Equity

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three months ended March 31, 2010 and 2009 (dollars in thousands):

	Three Months Ended March 31, 2010									Three Months Ended March 31, 2009
	Shareholders’			Noncontrolling						Shareholders’			Noncontrolling
	Equity			Interests			Total			Equity			Interests			Total
Beginning balance, January 1	$	3,316,109		$	111,895		$	3,428,004		$	3,445,979		$	124,990		$	3,570,969
Net income (loss)		(6,014	)		5,117			(897	)		(156,510	)		(9,560	)		(166,070	)
Other comprehensive loss:
Net unrealized losses on derivative instruments (a)		(91,667	)		—			(91,667	)		(138,548	)		—			(138,548	)
Net reclassification of realized losses to income (b)		13,185			—			13,185			25,365			—			25,365
Reclassification of pension and other postretirement benefits to income		1,393			—			1,393			1,252			—			1,252
Income tax benefit related to items of other comprehensive income		30,426			—			30,426			44,003			—			44,003
Total other comprehensive loss		(46,663	)		—			(46,663	)		(67,928	)		—			(67,928	)
Total comprehensive income (loss)		(52,677	)		5,117			(47,560	)		(224,438	)		(9,560	)		(233,998	)
Issuance of capital stock		2,680			—			2,680			2,629			—			2,629
Purchase of treasury stock, net of reissuances		1,078			—			1,078			(1,551	)		—			(1,551	)
Other		2			(22	)		(20	)		(6,707	)		(129	)		(6,836	)
Common stock dividends		(53,259	)		—			(53,259	)		(53,010	)		—			(53,010	)
Net capital activities by noncontrolling interests		—			(923	)		(923	)		—			1,316			1,316
Ending balance, March 31	$	3,213,933		$	116,067		$	3,330,000		$	3,162,902		$	116,617		$	3,279,519

(a)	These amounts primarily include unrealized gains and 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 gains and losses to realized gains and losses for contracted commodities delivered during the period.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the United States Department of Energy (“DOE”), and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance under the contract. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel.

Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim. The trial in the APS matter began on January 28, 2009, and closing arguments were heard in late May 2009. The court has not indicated when it will reach its decision in the matter. In January 2010, on appeal of another utility’s damages case in which the DOE successfully raised the unavoidable delays defense, the Court of Appeals for the Federal Circuit reversed the lower court’s decision and concluded that the Court of Federal Claims, the court handling the APS matter, is bound by the November 1997 D.C. Circuit decision that prevents the DOE from excusing its delay in performance.

APS currently estimates it will incur $132 million (in 2010 dollars) over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2010, APS had a regulatory liability of $37 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Fuel and Purchased Power Commitments

APS is party to various fuel and purchased power contracts with terms expiring between 2010 and 2042 that include required purchase provisions. APS estimates the contract requirements to be approximately $469 million in 2010; $341 million in 2011; $360 million in 2012; $466 million in 2013; $498 million in 2014; and $6.7 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. These amounts have increased since the 2009 Form 10-K due to increased solar contracts to meet our increasing requirements.

Renewable Energy Credits

In 2010, APS entered into additional contracts to purchase renewable energy credits to comply with the RES. APS estimates the new level of contract requirements at March 31, 2010 to be approximately $33 million in 2010; $19 million in 2011; $19 million in 2012; $19 million in 2013; $19 million in 2014; and $209 million thereafter.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

California Energy Market Issues and Refunds in the Pacific Northwest

In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. In addition, on March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including APS, failed to properly file rate information at the FERC in connection with sales to California from 2000 to March 2002 under market-based rates. Since 2004, the Ninth Circuit and the FERC have issued various decisions and orders involving the aforementioned issues, including decisions related to: entities subject to FERC jurisdiction and, therefore, potentially owing refunds; applicable refund methodologies; the temporal scope and types of transactions that are properly subject to the refund orders; and the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings. A settlement, resolving APS’ issues with certain California parties for the current refund period, was approved by the FERC in an order issued on June 30, 2008. The resolution of the claims related to the parties involved in this settlement had no material adverse impact on our financial position, results of operations or cash flows. We currently believe the refund claims at the FERC related to the parties not involved in this settlement will have no material adverse impact on our financial position, results of operations or cash flows.

On July 25, 2001, the FERC also 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 under Superfund (“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 52^nd 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 $1.2 million, which is reserved as a liability on our financial statements. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time we cannot accurately estimate our total expenditures.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Landlord Bankruptcy

On April 16, 2009, the landlord for our corporate headquarters building announced that it is seeking relief under Chapter 11 of the United States Bankruptcy Code. At March 31, 2010, we have several assets on our books related to our landlord, the most significant of which is an asset related to levelized rent payments for the building of approximately $67 million which is included in other deferred debits on the Condensed Consolidated Balance Sheets. This amount will continue to increase to approximately $94 million as a result of the lease terms until 2015, when this amount will begin to decrease over the remaining life of the lease. We are monitoring this matter and, while there can be no assurances as to the ultimate outcome of the matter due to the complexity of the bankruptcy proceedings, we currently do not expect that it will have a material adverse effect on our financial position, results of operations, or cash flows.

13. 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’ interest in the three Palo Verde units, APS’ 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 $16 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 $44 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.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. Other Income and Other Expense

The following table provides detail of other income and other expense for the three months ended March 31, 2010 and 2009 (dollars in thousands):

	Three Months Ended
	March 31,
	2010			2009
Other income:
Interest income	$	875		$	261
SunCor other income (a)		286			93
Investment gains — net		1,222			—
Miscellaneous		12			183
Total other income	$	2,395		$	537
Other expense:
Non-operating costs	$	(1,794	)	$	(1,608	)
Investment losses — net		—			(7,230	)
Miscellaneous		(902	)		(903	)
Total other expense	$	(2,696	)	$	(9,741	)

(a) Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.

15. Guarantees

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries.

Our parental guarantees for APS relate to commodity energy products. In addition, Pinnacle West has obtained approximately $9 million of surety bonds related to APS’ operations, which primarily relate to self-insured workers’ compensation. Our credit support instruments enable APSES to offer energy-related products. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. At March 31, 2010, we had no guarantees that were in default. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2010 are as follows (dollars in millions):

	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
APSES	$	9		1	$	28		1
APS		3		1		9		1
Total	$	12			$	37

APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2010, approximately $227 million of letters of credit were outstanding to support existing pollution control bonds of approximately $224 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $62 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit were amended and extended in April 2010, and will expire in 2013.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

16. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2010 and 2009:

	Three Months Ended
	March 31,
	2010			2009
Basic earnings per share:
Loss from continuing operations attributable to common shareholders	$	(0.06	)	$	(1.50	)
Loss from discontinued operations		—			(0.05	)
Loss per share — basic	$	(0.06	)	$	(1.55	)
Diluted earnings per share:
Loss from continuing operations attributable to common shareholders	$	(0.06	)	$	(1.50	)
Loss from discontinued operations		—			(0.05	)
Loss per share — diluted	$	(0.06	)	$	(1.55	)

For the three months ended March 31, 2010 and 2009 the weighted average common shares outstanding were the same for both basic and diluted shares. Options to purchase 387,800 shares of common stock for the three-month period ended March 31, 2010 and 625,524 shares for the three-month period ended March 31, 2009 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.

17. Discontinued Operations

SunCor (real estate segment) — In 2009, SunCor sold properties that are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income. Prior year income statement amounts related to these properties were reclassified from operations to discontinued operations. In addition, see Note 20 — Real Estate Impairment Charge.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table contains SunCor’s revenue, loss before income taxes and loss after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2010 and 2009 (dollars in millions):

	Three Months Ended
	March 31,
	2010		2009
Revenue	$	—	$	4
Loss before income taxes		—		(8	)
Loss after taxes (a)		—		(5	)

(a) Includes a tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of $3 million for the three months ended March 31, 2009.

18. Nuclear Decommissioning Trust

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with Nuclear Regulatory Commission (“NRC”) regulations. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust funds are invested in a tax efficient manner 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’ nuclear decommissioning trust fund assets at March 31, 2010 and December 31, 2009 (dollars in millions):

				Total		Total
				Unrealized		Unrealized
	Fair Value			Gains		Losses
March 31, 2010
Equity securities	$	150		$	34	$	(3	)
Fixed income securities		298			11		(1	)
Net payables (a)		(15	)		—		—
Total	$	433		$	45	$	(4	)

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

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

			Total		Total
			Unrealized		Unrealized
	Fair Value		Gains		Losses
December 31, 2009
Equity securities	$	167	$	37	$	(6	)
Fixed income securities		247		11		(1	)
Net receivables (a)		1		—		—
Total	$	415	$	48	$	(7	)

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

The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

	Three Months Ended
	March 31,
	2010			2009
Realized gains	$	12		$	2
Realized losses		(2	)		(2	)
Proceeds from the sale of securities (a)		158			130

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2010 is as follows (dollars in millions):

	Fair Value
Less than one year	$	32
1 year – 5 years		79
5 years – 10 years		77
Greater than 10 years		110
Total	$	298

See Note 19 for a discussion of fair value measurements.

19. 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 investments in Treasury securities.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 derivative 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.

Level 3 — Model-derived valuations with 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, certain options, transactions in locations where observable market data does not exist, and common and collective trusts with significant restrictions on our ability to transact in the fund. 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 and 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.

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 is not reflective of material inactive markets.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The nuclear decommissioning trust invests in fixed income securities directly and equity securities indirectly through commingled funds. The commingled equity funds are valued based on the fund’s net asset value (“NAV”) and are classified within Level 2. We may transact in the fund on a semi-monthly 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’ nuclear decommissioning obligations (see Note 18).

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 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable			Counterparty			Balance at
	Assets			Inputs			Inputs (a)			Netting &			March 31,
	(Level 1)			(Level 2)			(Level 3)			Other (b)			2010
Assets
Risk management activities (c)	$	2		$	132		$	55		$	(73	)	$	116
Nuclear decommissioning trust:
U.S. Treasury debt securities		66			—			—			—			66
Commingled U.S. equity funds		—			150			—			—			150
Corporate debt securities		—			64			—			—			64
Mortgage-backed securities		—			63			—			—			63
Municipality debt securities		—			49			—			—			49
Other		—			56			—			(15	)		41
Total	$	68		$	514		$	55		$	(88	)	$	549
Liabilities
Risk management activities (c)	$	(12	)	$	(372	)	$	(86	)	$	338		$	(132	)

(a)	Primarily consists of long-dated electricity contracts.
(b)	Primarily represents netting under master netting arrangements, including margin and collateral. See Note 10.
(c)	Commodity contracts. See Note 10.

35

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 2009 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices			Significant
	in Active			Other			Significant
	Markets for			Observable			Unobservable			Counterparty			Balance at
	Identical Assets			Inputs			Inputs (a)			Netting &			December 31,
	(Level 1)			(Level 2)			(Level 3)			Other (b)			2009
Assets
Cash equivalents	$	97		$	—		$	—		$	—		$	97
Risk management activities (c)		1			100			42			(64	)		79
Nuclear decommissioning trust:
U.S. Treasury debt securities		55			—			—			—			55
Commingled U.S. equity funds		—			167			—			—			167
Corporate debt securities		—			62			—			—			62
Mortgage-backed securities		—			60			—			—			60
Municipality debt securities		—			49			—			—			49
Other		—			21			—			1			22
Total	$	153		$	459		$	42		$	(63	)	$	591
Liabilities
Risk management activities (c)	$	(14	)	$	(246	)	$	(52	)	$	194		$	(118	)

(a)	Primarily consists of long-dated electricity contracts.
(b)	Primarily represents netting under master netting arrangements, including margin and collateral. See Note 10.
(c)	Commodity Contracts. See Note 10.

36

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 months ended March 31, 2010 and 2009 (dollars in millions):

	Three Months Ended
	March 31,
	2010			2009
Net derivative balance at beginning of period	$	(10	)	$	(7	)
Total net gains (losses) realized/unrealized:
Included in earnings (a)		(1	)		2
Included in other comprehensive income (“OCI”)		(6	)		(1	)
Deferred as a regulatory asset		(12	)		(3	)
Transfers into Level 3 from Level 2 (b)		—			(14	)
Transfers from Level 3 into Level 2 (b)		(2	)		—
Net derivative balance at end of period	$	(31	)	$	(23	)
Net unrealized gains (losses) included in earnings related to instruments still held at end of period	$	(1	)	$	2

(a)	Earnings are recorded in regulated electricity segment revenue or regulated electricity segment fuel and purchased power.
(b)	We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 reflect the fair market value at the beginning of the period. Transfers are triggered by a change in the lowest significant input during the period. Transfers are typically related to our 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.

We apply nonrecurring fair value measurements to certain real estate assets. These adjustments to fair value are the result of write-downs of individual assets due to impairment. Certain of our real estate assets have been impaired due to the distressed real estate market. We determine fair value for our real estate assets primarily based on the future cash flows that we estimate will be generated by each asset discounted for market risk. These fair value determinations require significant judgment regarding key assumptions. Due to these unobservable inputs, the valuation of real estate assets are considered Level 3 measurements.

As of March 31, 2010, the fair value of our impaired real estate assets that are measured at fair value on a nonrecurring basis was $72 million, all of which was valued using significant unobservable inputs (Level 3). Total impairment charges included in net income for the three months ended March 31, 2010 were approximately $15 million. See Note 20 for additional information.

37

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Financial Instruments Not Carried at Fair Value

The following table represents the carrying amount and estimated fair value of our debt which is not carried at fair value on the balance sheet. The carrying value of our cash, net accounts receivable, accounts payable and short-term borrowings approximate fair value. 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. Our debt fair value estimates are based on quoted market prices of the same or similar issues (dollars in millions):

	As of				As of
	March 31, 2010				December 31, 2009
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Pinnacle West	$	175	$	180	$	175	$	180
APS		3,529		3,727		3,530		3,667
SunCor		92		92		95		95
Total	$	3,796	$	3,999	$	3,800	$	3,942

20. Real Estate Impairment Charge

In 2009, SunCor undertook and completed a review of its assets and strategies within its various markets as a result of the distressed conditions in real estate and credit markets. Based on the results of the review, on March 27, 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce SunCor’s outstanding debt. During 2009, we recorded impairment charges of approximately $266 million pre-tax and $161 million after income taxes. In the first quarter of 2010, we recorded impairment charges of approximately $15 million pre-tax and $9 million after income taxes related to held and used assets. We believe that the assets to be sold, which are classified as “Real Estate Investments — Net” on the Condensed Consolidated Balance Sheets, do not meet the held for sale and discontinued operations criteria as of March 31, 2010, because of the uncertainties related to the current market conditions and obtaining necessary approvals. The detail of the impairment charge is as follows (dollars in millions, and before income taxes):

	Three Months Ended
	March 31,
	2010		2009
Homebuilding and master-planned communities	$	1	$	140
Land parcels and commercial assets		9		51
Golf courses		1		18
Other		4		—
Subtotal		15		209
Discontinued operations		—		7
Less noncontrolling interests		—		(14	)
Total	$	15	$	202

38

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We estimate the fair value of our real estate assets primarily based on either the future cash flows that we estimate will be generated by each asset discounted at a rate we believe market participants would use, on independent appraisals, or other market information, including comparison to comparable properties. Our impairment assessments and fair value determinations require significant judgment regarding key assumptions such as future sales prices, future construction and land development costs, future sales timing, and discount rates. The assumptions are specific to each project and may vary among projects. The weighted average discount rates we used to estimate fair values during 2009 and 2010 ranged from 11% to 29%. Due to the judgment and assumptions applied in the estimation process, with regard to impairments, it is possible that actual results could differ from those estimates.

SunCor also recorded $8 million of pretax severance and other charges relating to these actions during the three months ended March 31, 2009. Pinnacle West does not expect that any of the impairment charges will result in future cash expenditures, other than immaterial disposition costs.

See Note 4 for a discussion of SunCor’s debt and liquidity matters, and the impact of impairment charges on the SunCor Secured Revolver.

39

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands)

	Three Months Ended
	March 31,
	2010			2009
ELECTRIC OPERATING REVENUES	$	611,476		$	602,660
OPERATING EXPENSES
Fuel and purchased power		215,540			247,388
Operations and maintenance		203,881			191,185
Depreciation and amortization		100,609			99,937
Income taxes		(5,440	)		(6,744	)
Other taxes		31,451			33,780
Total		546,041			565,546
OPERATING INCOME		65,435			37,114
OTHER INCOME (DEDUCTIONS)
Income taxes		843			1,182
Allowance for equity funds used during construction		5,389			4,992
Other income (Note S-2)		1,783			415
Other expense (Note S-2)		(3,626	)		(4,358	)
Total		4,389			2,231
INTEREST DEDUCTIONS
Interest on long-term debt		54,752			49,734
Interest on short-term borrowings		842			2,975
Debt discount, premium and expense		1,137			1,189
Allowance for borrowed funds used during construction		(3,019	)		(3,724	)
Total		53,712			50,174
NET INCOME (LOSS)		16,112			(10,829	)
Less: Net income attributable to noncontrolling interests (Note 9)		5,128			4,650
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDER	$	10,984		$	(15,479	)

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

40

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	March 31,			December 31,
	2010			2009
ASSETS
UTILITY PLANT
Electric plant in service and held for future use	$	12,781,326		$	12,781,256
Less accumulated depreciation and amortization		4,335,052			4,326,908
Net		8,446,274			8,454,348
Construction work in progress		521,980			460,748
Palo Verde sale leaseback, net of accumulated depreciation (Note 9)		144,528			146,722
Intangible assets, net of accumulated amortization		169,726			164,183
Nuclear fuel, net of accumulated amortization		142,254			118,243
Total utility plant		9,424,762			9,344,244
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 18)		433,399			414,576
Assets from risk management activities (Note 10)		40,763			28,855
Other assets		70,478			68,839
Total investments and other assets		544,640			512,270
CURRENT ASSETS
Cash and cash equivalents		1,644			120,798
Customer and other receivables		197,921			280,226
Accrued unbilled revenues		86,466			110,971
Allowance for doubtful accounts		(5,810	)		(6,063	)
Materials and supplies (at average cost)		171,118			176,020
Fossil fuel (at average cost)		37,907			39,245
Assets from risk management activities (Note 10)		75,421			50,619
Deferred income taxes		77,915			53,990
Other current assets		34,223			25,724
Total current assets		676,805			851,530
DEFERRED DEBITS
Regulatory assets		863,233			813,161
Income tax receivable		65,498			65,498
Unamortized debt issue costs		20,395			20,959
Other		80,311			73,909
Total deferred debits		1,029,437			973,527
TOTAL ASSETS	$	11,675,644		$	11,681,571

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

41

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	March 31,			December 31,
	2010			2009
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital		2,126,863			2,126,863
Retained earnings		1,218,610			1,250,126
Accumulated other comprehensive loss:
Pension and other postretirement benefits		(28,469	)		(29,114	)
Derivative instruments		(128,180	)		(80,682	)
Total APS shareholder equity (Note S-1)		3,366,986			3,445,355
Noncontrolling interest (Note 9)		87,452			82,324
Total equity		3,454,438			3,527,679
Long-term debt less current maturities (Note 4)		3,180,434			3,180,406
Palo Verde sale leaseback lessor notes (Notes 4 and 9)		126,000			126,000
Total capitalization		6,760,872			6,834,085
CURRENT LIABILITIES
Short-term borrowings		195,000			—
Current maturities of long-term debt (Note 4)		222,825			222,959
Accounts payable		194,143			213,833
Accrued taxes (Note 8)		132,055			158,051
Accrued interest		52,499			54,099
Customer deposits		70,302			70,780
Liabilities from risk management activities (Note 10)		52,469			55,908
Other current liabilities		91,459			124,995
Total current liabilities		1,010,752			900,625
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,666,281			1,582,945
Deferred fuel and purchased power regulatory liability (Note 5)		105,378			87,291
Other regulatory liabilities		670,023			679,072
Liability for asset retirements		306,868			301,783
Liabilities for pension and other postretirement benefits (Note 6)		682,595			766,378
Customer advances for construction		134,030			136,595
Liabilities from risk management activities (Note 10)		79,194			62,443
Coal mine reclamation		92,303			92,060
Unrecognized tax benefits (Note 8)		75,202			140,638
Other		92,146			97,656
Total deferred credits and other		3,904,020			3,946,861
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	11,675,644		$	11,681,571

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

42

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)

	Three Months Ended
	March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	16,112		$	(10,829	)
Adjustments to reconcile net income (loss) to net cash used for operating activities:
Depreciation and amortization including nuclear fuel		113,195			110,089
Deferred fuel and purchased power		44,040			28,238
Deferred fuel and purchased power amortization		(25,953	)		28,961
Allowance for equity funds used during construction		(5,389	)		(4,992	)
Deferred income taxes		47,754			(6,335	)
Change in mark-to-market valuations		1,842			3,823
Changes in current assets and liabilities:
Customer and other receivables		61,239			71,551
Accrued unbilled revenues		24,505			15,365
Materials, supplies and fossil fuel		6,240			(11,796	)
Other current assets		(8,499	)		(2,042	)
Accounts payable		(22,275	)		(70,828	)
Accrued taxes		(25,996	)		17,371
Other current liabilities		(35,614	)		(43,964	)
Change in margin and collateral accounts — assets		(11,280	)		(23,876	)
Change in margin and collateral accounts — liabilities		(124,495	)		(162,012	)
Change in unrecognized tax benefits		(61,683	)		(797	)
Change in other long-term assets		(23,033	)		(1,165	)
Change in other long-term liabilities		(34,918	)		19,797
Net cash flow used for operating activities		(64,208	)		(43,441	)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(199,276	)		(188,973	)
Contributions in aid of construction		2,949			18,762
Capitalized interest		(3,019	)		(3,724	)
Proceeds from nuclear decommissioning trust sales		158,448			129,816
Investment in nuclear decommissioning trust		(164,552	)		(135,264	)
Other		(1,639	)		1,500
Net cash flow used for investing activities		(207,089	)		(177,883	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		—			496,475
Repayment and reacquisition of long-term debt		(357	)		(233	)
Short-term borrowings-net		195,000			(285,508	)
Dividends paid on common stock		(42,500	)		(42,500	)
Net cash flow provided by financing activities		152,143			168,234
NET DECREASE IN CASH AND CASH EQUIVALENTS		(119,154	)		(53,090	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		120,798			71,544
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,644		$	18,454
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of refunds	$	65,498		$	13,704
Interest, net of amounts capitalized	$	54,174		$	40,867

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

43

Certain notes to APS’ 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’ 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	APS’
	Consolidated	Supplemental
	Footnote	Footnote
	Reference	Reference
Consolidation and Nature of Operations	Note 1		—
Condensed Consolidated Financial Statements	Note 2		—
Quarterly Fluctuations	Note 3		—
Long-term Debt and Liquidity Matters	Note 4		—
Regulatory Matters	Note 5		—
Retirement Plans and Other Benefits	Note 6		—
Business Segments	Note 7		—
Income Taxes	Note 8		—
Variable Interest Entities	Note 9		—
Derivative and Energy Trading Accounting	Note 10		—
Changes in Equity	Note 11	Note S-1
Commitments and Contingencies	Note 12		—
Nuclear Insurance	Note 13		—
Other Income and Other Expense	Note 14	Note S-2
Guarantees	Note 15		—
Earnings Per Share	Note 16		—
Discontinued Operations	Note 17		—
Nuclear Decommissioning Trust	Note 18		—
Fair Value Measurements	Note 19		—
Real Estate Impairment Charge	Note 20		—

44

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-1. Changes in Equity

The following tables show APS’ changes in shareholder equity and changes in equity of noncontrolling interests for the three months ended March 31, 2010 and 2009 (dollars in thousands):

	Three Months Ended March 31, 2010								Three Months Ended March 31, 2009
	Shareholder			Noncontrolling					Shareholder			Noncontrolling
	Equity			Interests		Total			Equity			Interests		Total
Beginning balance, January 1	$	3,445,355		$	82,324	$	3,527,679		$	3,339,150		$	77,601	$	3,416,751
Net income (loss)		10,984			5,128		16,112			(15,479	)		4,650		(10,829	)
Other comprehensive loss:
Net unrealized losses on derivative instruments (a)		(91,667	)		—		(91,667	)		(138,548	)		—		(138,548	)
Net reclassification of realized losses to income (b)		13,185			—		13,185			25,365			—		25,365
Reclassification of pension and other postretirement benefits to income		1,064			—		1,064			987			—		987
Income tax benefit related to items of other comprehensive income		30,565			—		30,565			44,363			—		44,363
Total other comprehensive loss		(46,853	)		—		(46,853	)		(67,833	)		—		(67,833	)
Total comprehensive income (loss)		(35,869	)		5,128		(30,741	)		(83,312	)		4,650		(78,662	)
Common stock dividends		(42,500	)		—		(42,500	)		(42,500	)		—		(42,500	)
Other		—			—		—			4,503			—		4,503
Ending balance, March 31	$	3,366,986		$	87,452	$	3,454,438		$	3,217,841		$	82,251	$	3,300,092

(a)	These amounts primarily include unrealized gains and 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 gains and losses to realized gains and losses for contracted commodities delivered during the period.

45

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-2. Other Income and Other Expense

The following table provides detail of APS’ other income and other expense for the three months ended March 31, 2010 and 2009 (dollars in thousands):

	Three Months Ended
	March 31,
	2010			2009
Other income:
Interest income	$	462		$	183
Investment gains — net		1,165			—
Miscellaneous		156			232
Total other income	$	1,783		$	415
Other expense:
Non-operating costs (a)	$	(1,958	)	$	(1,335	)
Asset dispositions		(39	)		(83	)
Investment losses — net		—			(1,323	)
Miscellaneous		(1,629	)		(1,617	)
Total other expense	$	(3,626	)	$	(4,358	)

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

46

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 Arizona Public Service Company’s Condensed Consolidated Financial Statements and the related Notes that appear in Item 1 of this report. For purposes of this report, a “Note” refers to a Note to Pinnacle West’s Condensed Consolidated Financial Statements 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 2009 Form 10-K.

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and 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

Operations

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 renewals of its operating licenses for each of the three Palo Verde units, and is making preparations to secure necessary resources to operate the plant during this extended period of time. In April 2010, APS signed an agreement on behalf of the Palo Verde participants with five cities to provide cooling water essential to power production at Palo Verde for the next forty years.

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 developing legislation and increased regulation concerning greenhouse gas emissions, and the potential impacts on its coal fleet. Recent concern over climate change and other emission-related issues could have a significant impact on APS’ 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 the 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. In particular, Southern California Edison, 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 plant.

Transmission and Delivery. APS’ 2010 transmission plan projects that it will invest approximately $520 million in new transmission over the next ten years, which includes 270 miles of new lines. 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 a variety of benefits both to APS and its customers. This technology is designed 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.

47

Renewable Energy. APS is committed to increasing the amount of energy produced by renewable energy resources. The ACC adopted a renewable energy standard several years ago, recognizing the importance of renewable energy to our state. In the Settlement Agreement for the 2008 general retail rate case, APS agreed to exceed these standards, committing that approximately 10% of APS’ energy will come from renewable resources by the year 2015. A variety of other provisions in the Settlement Agreement reinforce APS’ dedication to renewable energy through initiatives such as building photovoltaic solar plants, installing solar rooftop panels on schools and government buildings and seeking an Arizona wind generation project.

On March 3, 2010, the ACC approved the AZ Sun program, under which APS plans to own 100 MW of photovoltaic power plants across Arizona by investing up to $500 million through 2014. These projects will be purchased upon completion from developers that will be selected through competitive procurement processes to build the plants. APS currently anticipates that this solar capacity would be placed into service in the 2011 to 2014 timeframe. The ultimate timing depends on the outcome of current and future procurement processes. See Note 5 for additional details of this program, including the related cost recovery. APS also issued two requests for proposal (“RFP”) for renewable resources in early 2010. These RFPs are part of the process for procuring the additional renewable resources required under the rate case settlement. The first RFP is for utility-scale solar photovoltaic projects between 15 and 50 MW. This RFP serves as the first procurement step for implementing the AZ Sun program. The second RFP is for wind projects between 15 and 100 MW to be located within Arizona.

Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. APS’ 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 twenty-one of the twenty-three other parties to APS’ general retail rate case, with modifications that did not materially affect the overall economic terms of the agreement. The rate case settlement should strengthen APS’ financial condition by allowing for rate stability and a greater level of cost recovery and return on investment. It also authorizes and requires equity infusions into APS of at least $700 million prior to the end of 2014. The settlement demonstrates cooperation among APS, the ACC staff, the Residential Utility Consumer Office (RUCO) and other intervenors to the rate case, and establishes a future rate case filing plan that allows APS the opportunity to help shape Arizona’s energy future outside of continual rate cases. See Note 5 for a discussion of the Settlement Agreement terms and information on APS’ 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 energy efficiency, demand-side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 5.

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, ensuring adequate liquidity for each company. In early February 2010, APS entered into a $500 million revolving credit facility, replacing its $377 million revolving credit facility that would have otherwise terminated in December 2010. At that same time, Pinnacle West entered into a $200 million revolving credit facility that replaces its $283 million facility that also would have otherwise terminated in December 2010. Pinnacle West and APS also accessed the commercial paper markets, which neither company had utilized since the third quarter of 2008 due to negative market conditions.

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In April 2010, we issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the proceeds from this offering to APS. APS anticipates using these capital contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

SunCor Real Estate Operations. As a result of the distressed conditions in the real estate markets, during 2009 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. As a result, during 2009, we recorded impairment charges of approximately $266 million pre-tax and $161 million after income taxes. In the first quarter of 2010, we recorded impairment charges of approximately $15 million pre-tax and $9 million after income taxes. See “Pinnacle West Consolidated – Liquidity and Capital Resources – Other Subsidiaries – SunCor” below for a discussion of SunCor’s outstanding debt and related matters and Note 20 for a further discussion of impairment charges.

Subsidiaries. The operations of our other first tier subsidiaries, El Dorado and APSES, 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.

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.

Regulated Electricity Segment Revenues. For the years 2007 through 2009, retail electric revenues comprised approximately 94% of our total electric operating revenues. Our electric operating revenues are affected by customer growth, 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’ 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. Customer growth in APS’ service territory for the three-month period ended March 31, 2010 was 0.6% compared with the prior year period. For the three years 2007 through 2009, APS’ customer growth averaged 1.8% per year. We currently expect annual customer growth to average about 1% for 2010 through 2012 due to economic conditions both nationally and in Arizona. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for the three-month period ended March 31, 2010 declined 1.7% compared to the same period in the prior year, reflecting the poor economic conditions and the effects of our energy efficiency programs. For the three years 2007 through 2009, APS’ actual retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, grew at an average annual rate of 0.2%. We currently estimate that total annual retail electricity sales in kilowatt-hours will remain flat on average during 2010 through 2012, including the effects of APS’ 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. The customer and sales growth referred to in this paragraph apply to Native Load customers.

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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 amortization thereof.

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 its recent retail rate case settlement, APS committed to operational expense reductions from 2010 through 2014 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. The “Capital Expenditures” section below provides information regarding the planned additions to our facilities. We have also applied to the NRC for renewed operating licenses for each of the Palo Verde units. If the NRC grants the extension, we estimate that our annual pretax depreciation expense will decrease by approximately $34 million at the later of the license extension date or January 1, 2012.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 7.5% of the assessed value for 2009 and 7.8% of the assessed value for 2008. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities described below under “Capital Additions”) and as we improve our existing facilities.

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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 4.) The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.

PINNACLE WEST CONSOLIDATED — RESULTS OF OPERATIONS

Our results of operations, provided below, are based upon our two reportable business segments:

• 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; and

• our real estate segment, which consists of SunCor’s real estate development and investment activities.

Operating Results — Three-month period ended March 31, 2010 compared with three-month period ended March 31, 2009

Our consolidated net loss attributable to common shareholders for the three months ended March 31, 2010 was $6 million, compared with a net loss of $157 million for the comparable prior-year period. The improved results were primarily due to lower real estate impairment charges recorded in 2010 compared with the prior-year period by SunCor, the Company’s real estate subsidiary.

In addition, regulated electricity segment net income increased approximately $27 million from the prior-year period primarily due to increased revenues related to APS’ retail rate increases.

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

							Increase
							(Decrease)
							in Net Income
	Three Months Ended						Attributable
	March 31,						to Common
	2010			2009			Shareholders
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	396		$	355		$	41
Operations and maintenance		(207	)		(194	)		(13	)
Depreciation and amortization		(101	)		(100	)		(1	)
Taxes other than income taxes		(32	)		(34	)		2
Other income (expenses), net		—			(4	)		4
Interest charges, net of capitalized financing costs		(52	)		(48	)		(4	)
Income taxes		8			10			(2	)
Noncontrolling interests (Note 9)		(5	)		(5	)		—
Regulated electricity segment net income ( loss)		7			(20	)		27
Real Estate Segment:
Real estate impairment charges (Note 20)		(15	)		(202	)		187
Other real estate operations		(6	)		(15	)		9
Income taxes		8			85			(77	)
Real estate segment net loss		(13	)		(132	)		119
All other (a)		—			(5	)		5
Net Loss Attributable to Common Shareholders	$	(6	)	$	(157	)	$	151

(a) Includes activities related to APSES and El Dorado. None of the activities of either of these companies constitutes a reportable segment.

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 $41 million higher for the three months ended March 31, 2010 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Purchased
	Operating			power and fuel
	revenues			expenses			Net change
	(dollars in millions)
Retail regulatory settlement effective January 1, 2010:
Retail base rate increases, net of deferrals	$	51		$	27		$	24
Line extension revenues (Note 5)		5						5
Transmission rate increases		4						4
Higher demand-side management surcharges (substantially offset in operations and maintenance expense)		7						7
Lower retail revenues related to recovery of PSA deferrals, substantially offset by amortization of fuel and purchased power expense		(55	)		(56	)		1
Miscellaneous items, net		(3	)		(3	)		—
Total	$	9		$	(32	)	$	41

Operations and maintenance Operations and maintenance expenses increased $13 million for the three months ended March 31, 2010 compared with the prior-year period primarily because of:

• An increase of $11 million related to higher labor expenses;

• An increase of $6 million related to demand-side management programs, which are primarily offset in operating revenues;

• A decrease of $8 million in generation costs, including timing of fossil-plant planned maintenance; and

• An increase of $4 million due to other miscellaneous factors.

Other income (expenses), net Other income (expenses), net, improved $4 million for the three months ended March 31, 2010 compared with the prior-year period primarily because of improved investment results. Other income (expenses), net, is comprised of the regulated electricity segment portions of the line items other income and other expense from the Condensed Consolidated Statements of Income.

Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $4 million for the three months ended March 31, 2010 compared with the prior-year period primarily because of higher debt balances. Interest charges, net of capitalized financing costs are comprised of the regulated electricity segment portions of the line items interest expense, capitalized interest and allowance for equity funds used during construction from the Condensed Consolidated Statements of Income.

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Income taxes Income tax benefits were $2 million lower for the three months ended March 31, 2010 compared with the prior-year period primarily because of higher pretax income in the current-year period, partially offset by $8 million related to a reduction in the Company’s 2010 effective income tax rate.

Real estate segment

During the first quarter of 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of substantially all of SunCor’s assets. This decision resulted in impairment charges of approximately $202 million pretax in the first quarter of 2009. The real estate segment net loss attributable to common shareholders was $119 million lower for the three months ended March 31, 2010 compared with the prior-year period primarily because of:

• A decrease in real estate impairment charges of $187 million;

• A decrease in the loss from other real estate operations of $9 million; and

• A decrease in income tax benefits of $77 million primarily because of a lower net loss for the 2010 period.

All Other

All other earnings were $5 million higher for the three months ended March 31, 2010 compared to the prior-year period primarily because of 2009 investment losses at El Dorado.

PINNACLE WEST CONSOLIDATED – LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table presents net cash provided by (used for) operating, investing and financing activities for the three months ended March 31, 2010 and 2009 (dollars in millions):

	Three Months Ended
	March 31,
	2010			2009
Net cash flow used for operating activities	$	(14	)	$	(56	)
Net cash flow used for investing activities		(210	)		(182	)
Net cash flow provided by financing activities		82			166

The decrease of approximately $42 million in net cash used for operating activities is primarily due to decreased collateral and margin cash provided as a result of changes in commodity prices and other changes in working capital partially offset by a voluntary pension contribution in 2010 of approximately $100 million.

The increase of approximately $28 million in net cash used for investing activities is primarily due to higher levels of capital expenditures, net of related contributions in aid of construction (see table and discussion below).

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The decrease of approximately $84 million in net cash provided by financing activities is primarily due to APS’ issuance of $500 million of unsecured senior notes in 2009. This is partially offset by the reduction of short-term borrowings in 2009 and the incurrence of short-term borrowings in 2010.

Liquidity

Capital Expenditure Requirements

The following table summarizes the actual capital expenditures for the three months ended March 31, 2009 and 2010 and the estimated capital expenditures for the next three years:

CAPITAL EXPENDITURES
(dollars in millions)

	Three Months Ended				Estimated for the Year Ended
	March 31,				December 31,
	2009		2010		2010		2011		2012
APS Generation (a)	$	60	$	77	$	309	$	417	$	520
Distribution		70		59		281		322		328
Transmission		31		36		145		161		192
Other (b)		5		11		84		71		48
Subtotal		166		183		819		971		1,088
Other		6		1		1		—		—
Total	$	172	$	184	$	820	$	971	$	1,088

(a)	Generation includes nuclear fuel expenditures of approximately $60 million to $80 million per year for 2010, 2011 and 2012.
(b)	Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS’ 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. Environmental expenditures for the years 2010, 2011 and 2012 are approximately $20 million, $80 million and $220 million, respectively. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures. (See “Business of Arizona Public Service Company – Environmental Matters – EPA Environmental Regulation – Regional Haze Rules and Mercury and other Hazardous Air Pollutants” in Item 1 of the 2009 Form 10-K.)

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and 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.

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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 a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

On April 21, 2010, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on June 1, 2010, to shareholders of record on May 3, 2010.

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 common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At March 31, 2010, APS’ common equity ratio, as defined, was 50%. Its total common equity was approximately $3.4 billion, and total capitalization was approximately $6.7 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.7 billion, assuming APS’ total capitalization remains the same.

Pinnacle West and APS maintain credit facilities in order to enhance liquidity and provide credit support. During the first quarter of 2010, Pinnacle West and APS refinanced existing revolving credit facilities that would have matured in December 2010. In addition, Pinnacle West and APS accessed the commercial paper market, which neither company had utilized since the third quarter of 2008 due to negative market conditions.

On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. The new facility matures February 2013. 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. Pinnacle West will use the facility for general corporate purposes, repayment of long-term debt, commercial paper support and for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. As a result of the downsized revolving credit facility, the Company also reduced the size of its commercial paper program to $200 million from $250 million.

At March 31, 2010, the $200 million revolver was available to support the issuance of up to $200 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit up to $100 million. At March 31, 2010 the Company had outstanding $10 million of borrowings under its revolving credit facility and no letters of credit. In addition, Pinnacle West had commercial paper borrowings of $80 million at March 31, 2010.

In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the proceeds from this offering to APS. APS anticipates using these capital contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.

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Pinnacle West expects to recognize approximately $131 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 20), which will not be fully realized until all the asset sale transactions are completed. Approximately $6 million of these benefits were recorded in the three months ended March 31, 2010 as reductions to income tax expense related to the current impairment charges. The additional $125 million of tax benefits were recorded as reductions to income tax expense related to SunCor impairment charges recorded on or before December 31, 2009.

The $85 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 and the current year tax benefits related to the SunCor strategic asset sales that closed prior to March 31, 2010.

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 and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made no contribution to our pension plan in 2009. We currently estimate that our pension contributions could average around $100 million for several years, assuming the discount rate remains at approximately current levels. During the first quarter of 2010, we made a voluntary contribution of approximately $100 million to our pension plan. The contribution to our other postretirement benefit plans in 2010 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.

See Note 5 for information regarding the recent retail rate case settlement, which includes ACC authorization and requires equity infusions into APS of at least $700 million by December 31, 2014. Pinnacle West intends to issue equity to provide most of the funds for the equity infusions into APS. Such equity issuances may occur at any time in the period through 2014, in Pinnacle West’s discretion.

APS

APS’ capital requirements consist primarily of capital expenditures and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, equity infusions from Pinnacle West and external financings. 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 12, 2010, APS refinanced its $377 million revolving credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2013. APS has the option to 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 support and for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.

At March 31, 2010 APS had two committed revolving credit facilities totaling $989 million, including the $500 million credit facility described above and $489 million that terminates in September 2011. The revolvers are available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit up to $739 million. At March 31, 2010, APS had borrowings of $70 million under its $489 million credit facility and no letters of credit under its revolving credit facilities. APS had commercial paper borrowings of $125 million at March 31, 2010.

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On January 1, 2010, due to the adoption of amended accounting guidance relating to VIEs, APS began consolidating the Palo Verde Lessor Trusts (see Note 9) and, as a result of consolidation of these VIEs, we have reported the Lessor Trusts’ long-term debt on our Condensed Consolidated Balance Sheets. Interest rates on these debt instruments are 8%, and are fixed for the remaining life of the debt. As of March 31, 2010 approximately $26 million was classified as current maturities of long-term debt and $126 million was classified as long-term debt relating to these VIEs. These debt instruments mature on December 30, 2015 and have sinking fund features that are serviced by the lease payments. See Note 9 for additional discussion of the VIEs.

Other Financing Matters — See Note 5 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.

See Note 5 for information regarding the recent retail rate case settlement, which includes ACC authorization and requires equity infusions into APS of at least $700 million by December 31, 2014.

See Note 10 for information related to the change in our margin accounts.

Other Subsidiaries

The SunCor Secured Revolver is secured primarily by an interest in land, commercial properties and land contracts. At March 31, 2010, SunCor had outstanding borrowings of approximately $54 million under the SunCor Secured Revolver, which matured on January 30, 2010. SunCor and the lenders under the SunCor Secured Revolver have signed a forbearance agreement under which the lenders have agreed not to exercise any remedies prior to June 30, 2010 to allow time for SunCor to continue discussions concerning the potential sale of additional properties. In addition to the SunCor Secured Revolver, at March 31, 2010, SunCor had approximately $42 million of outstanding debt under other credit facilities ($26 million of which has matured and remains outstanding). To date, the lenders under these credit facilities have taken no enforcement action. At March 31, 2010, $92 million was classified as current maturities of long-term debt and $4 million was classified as short-term borrowings on our Condensed Consolidated Balance Sheets.

If SunCor is unable to obtain extensions or renewals of the SunCor Secured Revolver or its other matured debt, or if it is unable to comply with the mandatory repayment and other provisions of any new or modified credit agreements, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such an immediate repayment obligation would have a material adverse impact on SunCor’s business and financial position and impair its ongoing viability.

SunCor cannot predict the outcome of negotiations with its lenders or its ability to sell assets for sufficient proceeds to repay its outstanding debt (see Note 20). SunCor’s ability to generate sufficient cash from operations while it pursues lender negotiations and further asset sales is uncertain.

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Neither Pinnacle West nor any of its other subsidiaries has guaranteed any SunCor indebtedness. A SunCor debt default would not result in a cross-default of any of the debt of Pinnacle West or any of its other subsidiaries. While there can be no assurances as to the ultimate outcome of this matter, Pinnacle West does not believe that SunCor’s inability to obtain extensions or renewals from SunCor’s lenders would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

As of March 31, 2010, SunCor could not transfer any cash dividends to Pinnacle West as a result of the covenants mentioned above. The restriction does not affect Pinnacle West’s ability to meet its ongoing capital requirements.

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.

APSES — APSES expects minimal capital expenditures over the next three years.

Debt Provisions

Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At March 31, 2010, the ratio was approximately 54% for Pinnacle West and 53% for APS. The provisions regarding interest coverage require minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.5 times under APS’ bank financing agreements as of March 31, 2010. 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’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank financial agreements contain a pricing grid in which the interest costs we pay 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’ 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 revolver borrowings.

See Note 4 for further discussions of liquidity matters.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of May 5, 2010 are shown below. 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’ securities and serve to increase the cost of and limit access to capital. It may also require 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.

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	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Senior unsecured (a)	Baa3 (P)	BB+ (prelim)	N/A
Commercial paper	P-3	A-3	F3
Outlook	Stable	Stable	Negative
APS
Senior unsecured	Baa2	BBB-	BBB
Secured lease obligation bonds	Baa2	BBB-	BBB
Commercial paper	P-2	A-3	F3
Outlook	Stable	Stable	Stable

(a) Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.

Off-Balance Sheet Arrangements

On January 1, 2010 we adopted amended accounting guidance relating to VIEs and, as a result, we have consolidated certain entities which were previously not consolidated. The consolidation of these entities has impacted our consolidated financial statement results. See Note 9 for a discussion of these impacts.

Guarantees and Letters of Credit

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries.

Our parental guarantees for APS relate to commodity energy products. In addition, Pinnacle West has obtained approximately $9 million of surety bonds related to APS’ operations, which primarily relate to self-insured workers’ compensation. Our credit support instruments enable APSES to offer energy-related products. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. At March 31, 2010, we had no guarantees that were in default. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. 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 15 for additional information regarding guarantees and letters of credit.

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Contractual Obligations

Our future contractual obligations, including contingent obligations, related to purchased power and fuel contracts and renewable energy credits have increased from approximately $8.7 billion at December 31, 2009 to $9.2 billion at March 31, 2010 as follows (dollars in billions):

2010		2011-2012		2013-2014		Thereafter		Total
$	0.5	$	0.8	$	1.0	$	6.9	$	9.2

These amounts have increased since the 2009 Form 10-K primarily due to increased solar contracts and renewable energy credits associated with the Renewable Energy Standard.

See Note 4 for a list of payments due on total long-term debt and capitalized lease requirements.

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 2009 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2009 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

On January 1, 2010 we adopted amended accounting guidance relating to VIEs, and as a result we have consolidated certain entities which were previously not consolidated. The consolidation of these entities has impacted our consolidated financial statement results. See Note 9 for a discussion of these impacts.

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 18). 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.

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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 three months ended March 31, 2010 and 2009 (dollars in millions):

	Three Months Ended
	March 31,
	2010			2009
Mark-to-market of net positions at beginning of period	$	(169	)	$	(282	)
Recognized in earnings:
Change in mark-to-market losses for future period deliveries		(3	)		(6	)
Mark-to-market losses realized including ineffectiveness during the period		1			2
Increase in regulatory asset		(31	)		(40	)
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (a)		(92	)		(139	)
Mark-to-market losses realized during the period		13			25
Change in valuation techniques		—			—
Mark-to-market of net positions at end of period	$	(281	)	$	(440	)

(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) at March 31, 2010 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 2009 Form 10-K and Note 19 for more discussion of our valuation methods.

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																			Total
																Years			fair
Source of Fair Value	2010			2011			2012			2013			2014			thereafter			value
Prices actively quoted	$	(9	)	$	(1	)	$	—		$	—		$	—		$	—		$	(10	)
Prices provided by other external sources		(121	)		(93	)		(23	)		(3	)		—			—			(240	)
Prices based on models and other valuation methods		(8	)		(4	)		(1	)		(5	)		(5	)		(8	)		(31	)
Total by maturity	$	(138	)	$	(98	)	$	(24	)	$	(8	)	$	(5	)	$	(8	)	$	(281	)

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 March 31, 2010 and December 31, 2009 (dollars in millions):

	March 31, 2010					December 31, 2009
	Gain (Loss)					Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings
Electricity	$	1	$	(1	)	$	1	$	(1	)
Natural gas		1		(1	)		1		(1	)
Regulatory asset, liability or OCI (a)
Electricity		20		(20	)		21		(21	)
Natural gas		46		(46	)		59		(59	)
Total	$	68	$	(68	)	$	82	$	(82	)

(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.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 19 – “Fair Value Measurements” for a discussion of our credit valuation adjustment policy. See Note 10 for further discussion of credit risk.

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ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS

Operating Results — Three-month period ended March 31, 2010 compared with three-month period ended March 31, 2009

APS’ net income attributable to common shareholder for the three months ended March 31, 2010 was $11 million, compared with a net loss of $15 million for the comparable prior-year period. The improved results were primarily due to increased revenues related to APS’ retail rate increases.

The following table presents net income (loss) attributable to common shareholder compared with the prior-year period:

							Increase
							(Decrease)
							in Net Income
	Three Months Ended						Attributable
	March 31,						to Common
	2010			2009			Shareholder
	(dollars in millions)
Operating revenues less fuel and purchased power expenses	$	396		$	355		$	41
Operations and maintenance		(204	)		(191	)		(13	)
Depreciation and amortization		(101	)		(100	)		(1	)
Taxes other than income taxes		(31	)		(34	)		3
Other income (expenses), net		(2	)		(3	)		1
Interest charges, net of capitalized financing costs		(48	)		(45	)		(3	)
Income taxes		6			8			(2	)
Noncontrolling interests (Note 9)		(5	)		(5	)		—
Net income (loss) attributable to common shareholder	$	11		$	(15	)	$	26

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Operating revenues less fuel and purchased power expenses

Electric operating revenues less fuel and purchased power expenses were $41 million higher for the three months ended March 31, 2010 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Purchased
	Operating			power and fuel
	revenues			expenses			Net change
	(dollars in millions)
Retail regulatory settlement effective January 1, 2010:
Retail base rate increases, net of deferrals	$	51		$	27		$	24
Line extension revenues (Note 5)		5						5
Transmission rate increases		4						4
Higher demand-side management surcharges (substantially offset in operations and maintenance expense)		7						7
Lower retail revenues related to recovery of PSA deferrals, substantially offset by amortization of fuel and purchased power expense		(55	)		(56	)		1
Miscellaneous items, net		(3	)		(3	)		—
Total	$	9		$	(32	)	$	41

Operations and maintenance Operations and maintenance expenses increased $13 million for the three months ended March 31, 2010 compared with the prior-year period primarily because of:

• An increase of $11 million related to higher labor expenses;

• An increase of $6 million related to demand-side management programs, which are primarily offset in operating revenues;

• A decrease of $8 million in generation costs, including timing of fossil-plant planned maintenance; and

• An increase of $4 million due to other miscellaneous factors.

Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $3 million for the three months ended March 31, 2010 compared with the prior-year period primarily because of higher debt balances. Interest charges, net of capitalized financing costs are comprised of portions of the line items interest expense, allowance for borrowed funds used during construction and allowance for equity funds used during construction from the APS Condensed Consolidated Statements of Income.

Income taxes Income tax benefits were $2 million lower for the three months ended March 31, 2010 compared with the prior-year period primarily because of higher pretax income in the current-year period partially offset by $8 million related to a reduction in APS’ 2010 effective income tax rate.

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ARIZONA PUBLIC SERVICE COMPANY — LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table presents net cash provided by (used for) operating, investing and financing activities for the three months ended March 31, 2010 and 2009 (dollars in millions):

	Three Months Ended
	March 31,
	2010			2009
Net cash flow used for operating activities	$	(64	)	$	(43	)
Net cash flow used for investing activities		(207	)		(178	)
Net cash flow provided by financing activities		152			168

The increase of approximately $21 million in net cash used for operating activities is primarily due to the payment of income taxes and a voluntary pension contribution in 2010 of approximately $100 million, partially offset by decreased collateral and margin cash provided as a result of changes in commodity prices and other changes in working capital.

The increase of approximately $29 million in net cash used for investing activities is primarily due to higher levels of capital expenditures net of related contribution in aid of construction (see table and discussion above).

The decrease of approximately $16 million in net cash provided by financing activities is primarily due to APS’ issuance of $500 million of unsecured senior notes in 2009. This is substantially offset by the reduction of short-term borrowings in 2009 and the incurrence of short-term borrowings in 2010.

Contractual Obligations

APS’ future contractual obligations, including contingent obligations, related to purchased power and fuel contracts and renewable energy credits have increased from approximately $8.7 billion at December 31, 2009 to $9.2 billion at March 31, 2010 as follows (dollars in billions):

2010		2011-2012		2013-2014		Thereafter		Total
$	0.5	$	0.8	$	1.0	$	6.9	$	9.2

These amounts have increased since the 2009 Form 10-K primarily due to increased solar contracts and renewable energy credits associated with the Renewable Energy Standard.

See Note 4 for a list of payments due on total long-term debt and capitalized lease requirements.

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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 March 31, 2010. 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’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of March 31, 2010. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ 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’ internal control over financial reporting occurred during the fiscal quarter ended March 31, 2010 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ 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 “Business of Arizona Public Service Company – Environmental Matters” in Item 1 of the 2009 Form 10-K in regard to pending or threatened litigation or other disputes.

See Note 12 with regard to a lawsuit brought by APS on behalf of itself and the other Palo Verde owners against the DOE, for information relating to FERC proceedings on California and Pacific Northwest energy market issues and for information regarding bankruptcy proceedings involving the landlord for our corporate headquarters building.

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 2009 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 2009 Form 10-K are not the only risks facing Pinnacle West and APS. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS.

Item 5. OTHER INFORMATION

Construction and Financing Programs

See “Liquidity and Capital Resources” in Part I, Item 2 of this report for a discussion of construction and financing programs of Pinnacle West and its subsidiaries.

Regulatory Matters

See Note 5 for a discussion of regulatory developments.

Environmental Matters

Superfund

See “Superfund” in Note 12 for a discussion of a Superfund site.

Climate Change

Legislative and Regulatory Initiatives. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions. On June 26, 2009, the House of Representatives approved the American Clean Energy and Security Act of 2009, H.R. 2454. In addition to establishing clean energy programs, H.R. 2454 would establish a greenhouse gas emission cap-and-trade system starting in 2012 applicable to about 85% of all emission sources in the nation. A similar bill (Kerry-Boxer Bill, S. 1733) is pending before the Senate. Both of these bills would allocate a certain number of allowances to local distribution companies (such as APS) through 2030.

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To the extent APS’ emissions exceed the allowances allocated to it under these proposed bills, APS would have an “allowance gap.” APS would have to purchase enough allowances from the market to fill these gaps. The table below illustrates the estimated cost impacts to APS in 2012 to acquire allowances to fill its allowance gap, and the associated retail rate impacts to customers under H.R. 2454 and S. 1733. For purposes of this illustration, the table provides three assumed allowance prices of $20, $50 and $75 per metric ton.

		H.R. 2454					S. 1733
Allowance Cost		Annual Cost					Annual Cost
($ per metric ton)		($ in millions)		Rate Impact			($ in millions)		Rate Impact
$	20	$	68		2	%	$	101		3	%
$	50	$	170		5	%	$	252		8	%
$	75	$	255		8	%	$	379		12	%

The actual economic and operational impact of this or any similar legislation on APS depends on a variety of factors, none of which can be fully known until such legislation passes and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed emissions; whether the permitted emissions allowances will be allocated to source operators free of cost or auctioned; the cost to reduce emissions or buy allowances in the marketplace; and the availability of offsets and mitigating factors to moderate the costs of compliance. At the present time, we cannot predict what form of legislation, if any, will ultimately pass.

In December 2009, the EPA determined that greenhouse gas emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that greenhouse gases fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, the EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under the Clean Air Act. The endangerment finding could result in the EPA issuing new regulatory requirements under the Clean Air Act for new and modified major greenhouse gas emitting sources, including power plants. On September 30, 2009, the EPA announced a proposed rule under the Clean Air Act, known as the “tailoring rule,” establishing new greenhouse gas emissions thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. Several groups have filed lawsuits challenging the EPA’s endangerment finding. At the present time we cannot predict whether the proposed tailoring rule will be adopted in its current or a revised form, what other rules or regulations may ultimately result from the EPA’s finding, whether the parties challenging the endangerment finding will be successful, and what impact the proposed rule and potential other rules or regulations will have on APS’ operations.

In anticipation of potential future regulation of greenhouse gases under the Clean Air Act as described above, on September 22, 2009, the EPA issued a mandatory greenhouse gas reporting rule. On March 10, 2010, the EPA proposed additions and amendments to the rule. The rule applies to direct greenhouse gas emissions from facilities such as APS’ power plants. We expect that our incremental costs to comply with this rule will be immaterial since APS already routinely reports CO₂ and other greenhouse gas emissions from its plants.

In addition to federal legislative initiatives, state specific initiatives may also impact our business. While Arizona has not yet enacted any state specific legislation regarding greenhouse gas emissions, the California legislature enacted AB 32 and SB 1368 in 2006 to address greenhouse gas emissions and New Mexico is currently considering proposed legislation to address these issues. We are monitoring these and other state legislative developments to understand the extent to which they may affect our business, including our sales into the impacted states or the ability of our out-of-state power plant participants to continue their participation in certain coal-fired power plants. In particular, Southern California Edison, a participant in Four Corners, has indicated that SB 1368 may prohibit it from making emission control expenditures at the plant.

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If any emission reduction legislation or regulations are enacted, we will assess our compliance alternatives, which may include replacement of existing equipment, installation of additional pollution control equipment, purchase of allowances, retirement or suspension of operations at certain coal-fired facilities, or other actions. Although associated capital expenditures or operating costs resulting from greenhouse gas emission regulations or legislation could be material, we believe that we would be able to recover the costs of these environmental compliance initiatives through our rates.

Regional Initiative. In 2007, six western states (Arizona, California, New Mexico, Oregon, Utah and Washington) and two Canadian provinces (British Columbia and Manitoba) entered into an accord, the Western Climate Initiative (“WCI”), to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. Montana, Quebec and Ontario have also joined WCI. WCI participants set a goal of reducing greenhouse gas emissions 15% below 2005 levels by 2020. After soliciting public comment, in September 2008 WCI issued the design of a cap-and-trade program for greenhouse gas emissions. Due in part to the recent activity at the federal level discussed above, the initiative’s momentum and the movement toward detailed proposed rules has slowed. On February 2, 2010, Arizona’s Governor issued an executive order stating that Arizona will continue to be a member of WCI to monitor its advancements in this area, but it will not implement the WCI regional cap-and-trade program. As a result, while we continue to monitor the progress of WCI, at the present time we do not believe it will have a material impact on our operations.

Company Response to Climate Change Initiatives. We have undertaken a number of initiatives to address emission concerns, including renewable energy procurement and development, promotion of programs and rates that promote energy conservation, renewable energy use and energy efficiency, and implementation of an active technology innovation effort to evaluate potential emerging new technologies. APS currently has a diverse portfolio of renewable resources, including wind, geothermal, solar and biomass and we are focused on increasing the percentage of our energy that is produced by renewable resources.

On May 18, 2009, we submitted a comprehensive Climate Change Management Plan to the ACC to comply with an ACC order that directed APS to undertake a climate management plan, carbon emission reduction study and commitment and action plan with public input and ACC review. The Climate Change Management Plan details scientific, legislative and policy issues, potential physical and financial risks to APS, greenhouse gas emission inventory, APS technology innovation and greenhouse gas reduction efforts, and our companies’ strategic approach to climate change management.

In January 2008, APS joined the Climate Registry as a Founding Reporter. Founding Reporters are companies that voluntarily joined the non-profit organization before May 2008 to measure and report greenhouse gas emissions in a common, accurate and transparent manner consistent across industry sectors and borders. Beginning in 2010, APS will no longer participate in the Climate Registry because it will be reporting substantially the same information under the new EPA reporting rule. Pinnacle West has also reported, and will continue to report, greenhouse gas emissions in its annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com). In addition to emissions data, the report provides information related to the Company, its approach to sustainability and its workplace and environmental performance, as well as a copy of our Climate Change Management Plan discussed above. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.

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Climate Change Lawsuits. 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.  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 court in November 2009.  We believe the action is without merit and intend to continue to defend against the claims.

Similar nuisance lawsuits are currently pending in the 2nd and 5th Circuits. In the fall of 2009, the U.S. Courts of Appeals for each of these Circuits reversed lower court decisions and ruled that the plaintiffs in both cases could bring common law nuisance lawsuits against coal-burning utilities allegedly contributing to global warming. Both cases, as well as the Kivalina case, raise political and legal considerations, including whether the courts can or should be making climate change policy decisions. We are not a party to either of these two lawsuits, but will monitor these developments and their potential industry impacts.

Coal Combustion Waste

On May 4, 2010, the EPA released its proposed regulations governing the handling and disposal of coal combustion byproducts (“CCBs”), such as fly ash and bottom ash. APS currently disposes of CCBs in ash ponds and dry storage areas at Cholla and Four Corners, and also sells a portion of its fly ash for beneficial reuse as a constituent in concrete production. The EPA proposes regulating CCBs as either non-hazardous waste or hazardous waste and is seeking comment on three different alternatives. The hazardous waste proposal would phase out the use of ash ponds for disposal of CCBs. The other two proposals regulate CCBs as non-hazardous waste and impose performance standards for ash disposal. One of these proposals would require retrofitting or closure of currently unlined ash ponds, while the other proposal would not require the installation of liners or pond closures. The EPA has not yet indicated a preference for any of the alternatives.

APS intends to file comments on the proposed rule during a 90-day comment period. We do not know when the EPA will issue a final rule, including required compliance dates. We cannot currently predict the outcome of the EPA’s actions or whether such actions will have a material adverse impact on our financial position, results of operations or cash flows.

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Item 6. EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
10.1	Pinnacle West APS	Municipal Effluent Purchase and Sale Agreement dated April 29, 2010, by and between City of Phoenix, City of Mesa, City of Tempe, City of Scottsdale, City of Glendale, APS and Salt River Project Agricultural Improvement and Power District.
10.2	Pinnacle West APS	Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated as of April 16, 2010
10.3	Pinnacle West APS	Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated as of April 16, 2010
10.4	Pinnacle West	Letter Agreement dated May 21, 2009, between Pinnacle West Capital Corporation and David P. Falck
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

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Exhibit No.	Registrant(s)	Description
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 1850, 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 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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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			Previously Filed as	Date
No.	Registrant(s)	Description	Exhibit1	Filed
3.1	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
3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of January 21, 2009	3.2 to Pinnacle West/APS December 31, 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-20-09
3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’ 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: May 6, 2010	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: May 6, 2010	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)

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