10-Q

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, 2009

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 April 30, 2009: 101,083,117
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of April 30, 2009: 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.

          This combined Form 10-Q is separately provided by Pinnacle West Capital Corporation and Arizona Public Service Company. 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.

TABLE OF CONTENTS

	Page
Glossary		2
Part I		4
Item 1. Financial Statements		4
Pinnacle West Capital Corporation		4
Arizona Public Service Company		35
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
Item 3. Quantitative and Qualitative Disclosures About Market Risk		61
Item 4. Controls and Procedures		61
Part II		62
Item 1. Legal Proceedings		62
Item 1A. Risk Factors		62
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		62
Item 5. Other Information		62
Item 6. Exhibits		67
Signatures		70
EX-10.1
EX-10.2
EX-10.3
EX-12.1
EX-12.2
EX-12.3
EX-31.1
EX-31.2
EX-31.3
EX-31.4
EX-32.1
EX-32.2
Ex-99.1

GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

ALJ – Administrative Law Judge

APS – Arizona Public Service Company, a subsidiary of the Company

APSES – APS Energy Services Company, Inc., a subsidiary of the Company

Base Fuel Rate – the portion of APS’ retail base rates attributable to fuel and purchased power costs

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

DOE – United States Department of Energy

El Dorado – El Dorado Investment Company, a subsidiary of the Company

EPA – United States Environmental Protection Agency

FASB – Financial Accounting Standards Board

FERC – United States Federal Energy Regulatory Commission

FIN – FASB Interpretation Number

FIP – Federal Implementation Plan

Fitch – Fitch, Inc.

Four Corners – Four Corners Power Plant

GAAP – accounting principles generally accepted in the United States of America

IRS – United States Internal Revenue Service

kWh – kilowatt-hour, one thousand watts per hour

MMBTU – one million British thermal units

Moody’s – Moody’s Investors Service, Inc.

Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation

Note – a Note to Pinnacle West’s Condensed Consolidated Financial Statements in Item 1 of this report

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned or contracted by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts

Palo Verde – Palo Verde Nuclear Generating Station

Pinnacle West – Pinnacle West Capital Corporation, the Company

2

Pinnacle West Marketing & Trading – Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company

PRP – potentially responsible parties under Superfund

PSA – power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate

Salt River Project – Salt River Project Agricultural Improvement and Power District

SEC – United States Securities and Exchange Commission

SFAS – Statement of Financial Accounting Standards

Standard & Poor’s – Standard & Poor’s Ratings Services

SIP – State Implementation Plan

SunCor – SunCor Development Company, a subsidiary of the Company

SunCor Secured Revolver – SunCor’s principal loan facility

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

2008 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2008

VIE – variable-interest entity

3

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,
	2009			2008
OPERATING REVENUES
Regulated electricity segment	$	602,578		$	622,801
Real estate segment		18,366			26,266
Marketing and trading		—			30,452
Other revenues		8,449			8,737
Total		629,393			688,256
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		247,388			269,378
Real estate segment operations		30,281			30,957
Real estate impairment charge (Note 21)		211,306			—
Marketing and trading fuel and purchased power		—			23,986
Operations and maintenance		207,531			193,023
Depreciation and amortization		99,921			95,594
Taxes other than income taxes		34,128			33,152
Other expenses		6,467			5,938
Total		837,022			652,028
OPERATING INCOME (LOSS)		(207,629	)		36,228
OTHER
Allowance for equity funds used during construction		4,992			6,124
Other income (Note 14)		380			3,839
Other expense (Note 14)		(9,741	)		(4,896	)
Total		(4,369	)		5,067
INTEREST EXPENSE
Interest charges		55,806			54,702
Capitalized interest		(3,834	)		(5,679	)
Total		51,972			49,023
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(263,970	)		(7,728	)
INCOME TAXES		(96,174	)		(1,541	)
LOSS FROM CONTINUING OPERATIONS		(167,796	)		(6,187	)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(1,892) and $1,103 (Note 17)		(2,924	)		1,714
NET LOSS		(170,720	)		(4,473	)
Less: Net loss attributable to noncontrolling interests		(14,210	)		—
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(156,510	)	$	(4,473	)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		100,986			100,521
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		100,986			100,521
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Loss from continuing operations attributable to common shareholders — basic	$	(1.52	)	$	(0.06	)
Net loss attributable to common shareholders — basic	$	(1.55	)	$	(0.04	)
Loss from continuing operations attributable to common shareholders — diluted	$	(1.52	)	$	(0.06	)
Net loss attributable to common shareholders — diluted	$	(1.55	)	$	(0.04	)
DIVIDENDS DECLARED PER SHARE	$	0.525		$	0.525
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Loss from continuing operations, net of tax	$	(153,586	)	$	(6,187	)
Discontinued operations, net of tax		(2,924	)		1,714
Net loss attributable to common shareholders	$	(156,510	)	$	(4,473	)

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,
	2009			2008
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	32,804		$	105,245
Customer and other receivables		217,238			292,682
Accrued utility revenues		84,724			100,089
Allowance for doubtful accounts		(2,667	)		(3,383	)
Materials and supplies (at average cost)		182,961			173,252
Fossil fuel (at average cost)		31,839			29,752
Deferred income taxes		119,694			79,729
Home inventory (Note 21)		15,185			50,688
Assets held for sale (Note 17)		32,015			—
Assets from risk management and trading activities (Note 10)		63,969			32,581
Other current assets		23,802			21,847
Total current assets		801,564			882,482
INVESTMENTS AND OTHER ASSETS
Real estate investments — net (Note 21)		213,478			415,296
Assets from long-term risk management and trading activities (Note 10)		34,194			33,675
Nuclear decommissioning trust (Note 18)		336,091			343,052
Other assets		96,081			117,935
Total investments and other assets		679,844			909,958
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		12,329,865			12,264,805
Less accumulated depreciation and amortization		4,205,068			4,141,546
Net		8,124,797			8,123,259
Construction work in progress		622,186			572,354
Intangible assets, net of accumulated amortization		143,138			131,722
Nuclear fuel, net of accumulated amortization		99,304			89,323
Total property, plant and equipment		8,989,425			8,916,658
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		—			7,984
Other regulatory assets		825,069			787,506
Other deferred debits		121,864			115,505
Total deferred debits		946,933			910,995
TOTAL ASSETS	$	11,417,766		$	11,620,093

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

5

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

	March 31,			December 31,
	2009			2008
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	170,057		$	261,029
Accrued taxes		27,952			109,798
Accrued interest		45,282			40,741
Short-term borrowings		407,005			670,469
Current maturities of long-term debt (Note 4)		166,931			177,646
Customer deposits		78,181			78,745
Liabilities from risk management and trading activities (Note 10)		63,954			69,585
Other current liabilities		73,194			97,915
Total current liabilities		1,032,556			1,505,928
LONG-TERM DEBT LESS CURRENT MATURITIES (NOTE 4)		3,529,109			3,031,603
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,393,921			1,403,318
Deferred fuel and purchased power regulatory liability (Note 5)		49,215			—
Other regulatory liabilities		591,601			587,586
Liability for asset retirements		280,615			275,970
Liabilities for pension and other postretirement benefits (Note 6)		688,803			675,788
Liabilities from risk management and trading activities (Note 10)		136,068			126,532
Other		518,610			520,000
Total deferred credits and other		3,658,833			3,589,194
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 11)
Common stock, no par value		2,147,245			2,151,323
Treasury stock		(4,405	)		(2,854	)
Total common stock		2,142,840			2,148,469
Retained earnings		1,234,688			1,444,208
Accumulated other comprehensive loss:
Pension and other postretirement benefits		(46,762	)		(47,547	)
Derivative instruments		(167,864	)		(99,151	)
Total accumulated other comprehensive loss		(214,626	)		(146,698	)
Total Pinnacle West shareholders’ equity		3,162,902			3,445,979
Noncontrolling real estate interests		34,366			47,389
Total equity		3,197,268			3,493,368
TOTAL LIABILITIES AND EQUITY	$	11,417,766		$	11,620,093

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

6

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

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(170,720	)	$	(4,473	)
Adjustments to reconcile net loss to net cash (used for) provided by operating activities:
Depreciation and amortization including nuclear fuel		110,073			104,418
Deferred fuel and purchased power		28,238			9,722
Deferred fuel and purchased power amortization		28,961			50,709
Allowance for equity funds used during construction		(4,992	)		(6,124	)
Real estate impairment charge		215,869			—
Deferred income taxes		(3,901	)		(44,781	)
Change in mark-to-market valuations		3,822			(14,709	)
Changes in current assets and liabilities:
Customer and other receivables		76,390			50,521
Accrued utility revenues		15,365			12,764
Materials, supplies and fossil fuel		(11,796	)		(11,418	)
Other current assets		(711	)		(511	)
Accounts payable		(78,090	)		(84,556	)
Accrued taxes		(81,846	)		47,025
Other current liabilities		(20,744	)		(16,968	)
Expenditures for real estate investments		(1,459	)		(10,967	)
Other changes in real estate assets		(264	)		23,678
Change in margin and collateral accounts — assets		(23,476	)		93,449
Change in margin and collateral accounts — liabilities		(162,013	)		6,647
Change in unrecognized tax benefits		(1,050	)		13,223
Change in other long-term assets		8,897			16,145
Change in other long-term liabilities		17,281			12,060
Net cash flow (used for) provided by operating activities		(56,166	)		245,854
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(193,014	)		(248,264	)
Contributions in aid of construction		18,762			10,040
Capitalized interest		(3,834	)		(5,679	)
Proceeds from nuclear decommissioning trust sales		129,816			67,177
Investment in nuclear decommissioning trust		(135,264	)		(72,362	)
Other		1,501			970
Net cash flow used for investing activities		(182,033	)		(248,118	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		499,683			43,690
Repayment and reacquisition of long-term debt		(16,386	)		(29,295	)
Short-term borrowings and payments — net		(263,464	)		1,965
Dividends paid on common stock		(51,196	)		(52,759	)
Common stock equity issuance		815			2,815
Other		(3,694	)		(2,940	)
Net cash flow provided by (used for) financing activities		165,758			(36,524	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(72,441	)		(38,788	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		105,245			56,321
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	32,804		$	17,533
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of refunds	$	17,602		$	9,860
Interest, net of amounts capitalized	$	46,040		$	45,949

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

7

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, APSES, El Dorado and Pinnacle West Marketing & Trading. By the end of 2008, substantially all of Pinnacle West Marketing & Trading’s contracts were transferred to APS or expired. Intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with 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 unaudited 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 statements and notes should be read in conjunction with the consolidated financial statements and related notes included in our 2008 Form 10-K. These condensed consolidated financial statements and notes have been prepared consistently with the 2008 Form 10-K with the exception of the reclassification of certain prior-year amounts on our Condensed Consolidated Statement of Income, Condensed Consolidated Balance Sheets and Condensed Consolidated Statement of Cash Flows in accordance with SFAS No. 160 (see Note 19) and SFAS No. 144 (see Note 17).

3. Quarterly Fluctuations

     Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate activities, such as the real estate impairment charge recorded in the first quarter of 2009 (see Note 21), 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. 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, 2009 (dollars in millions):

		Consolidated
Year		Pinnacle West		APS
	2009	$	65	$	1
	2010		299		197
	2011		578		401
	2012		376		376
	2013		2		—
Thereafter			2,384		2,384
Total		$	3,704	$	3,359

8

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     The credit and liquidity markets experienced significant stress beginning the week of September 15, 2008. While Pinnacle West’s and APS’ ability to issue commercial paper has been negatively impacted by market conditions, they have both been able to access existing credit facilities, ensuring adequate liquidity. Cash on hand is being invested in money market funds consisting of U.S. Treasury and government agency securities and repurchase agreements collateralized fully by U.S. Treasury and government agency securities.

     Pinnacle West (parent company) has a $283 million revolving credit facility that terminates in December 2010. The revolver is available to support the issuance of up to $250 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit of up to $94 million. At March 31, 2009, the parent company had outstanding $166 million of borrowings under its revolving credit facility and approximately $7 million of letters of credit. It also had no commercial paper outstanding at March 31, 2009. At March 31, 2009, the parent company had remaining capacity available under its revolver of approximately $110 million and had cash and investments of approximately $3 million.

     On February 26, 2009, APS issued $500 million of 8.75% unsecured senior notes that mature on March 1, 2019. Net proceeds from the sale of the notes were used to repay short-term borrowings under two committed revolving lines of credit incurred to fund capital expenditures and for general corporate purposes.

     APS has two committed revolving credit facilities totaling $866 million, of which $377 million terminates in December 2010 and $489 million terminates in September 2011. The revolvers are available either to support the issuance of up to $250 million in commercial paper (see discussion above) or to be used for bank borrowings, including issuances of letters of credit up to $583 million. At March 31, 2009, APS had borrowings of approximately $236 million and no letters of credit under its revolving lines of credit. At March 31, 2009, APS had remaining capacity available under its revolvers of $630 million and had cash and investments of approximately $18 million.

     The interest rates on eleven issues of APS’ pollution control bonds, in the aggregate amount of approximately $343 million, are reset every seven days through auction processes. These bonds are supported by bond insurance policies provided by Ambac Assurance Corporation (“Ambac”), and the interest rates on the bonds can be directly affected by the rating of the bond insurer. Certain bond insurers, including Ambac, have had downgrades of their credit ratings. Downgrades of bond insurers result in downgrades of the insured bonds, which increases the possibility of a “failed auction” and results in higher interest rates during the failed auction periods. When auctions of APS bonds fail, the APS bondholders receive the maximum 14% annual interest rate for the week of the failed auction. For the three months ended March 31, 2009, we had 15 failed auctions, which represented about 11% of all of our auctions. The average interest rate at March 31, 2009 on the auction rate securities was 7.0%. We continue to closely monitor this market and, if market and business conditions allow, we are planning on refunding and reissuing these bonds during 2009. We do not expect, however, that our auction rate interest exposure will have a material adverse impact on our financial position, results of operations, cash flows or liquidity.

     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, 2009, APS’ common equity ratio, as defined, was 49%. Its total common equity was approximately $3.2 billion,

9

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

and total capitalization was approximately $6.6 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.6 billion, assuming APS’ total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

     The SunCor Secured Revolver was recently extended for a twelve-month period to January 2010 and requires SunCor to reduce its outstanding borrowings by specified amounts over the term of the facility. As of March 31, 2009, approximately $108 million of borrowings were outstanding under the SunCor Secured Revolver and approximately $67 million of debt was outstanding under other SunCor credit facilities. SunCor intends to apply the proceeds of planned asset sales (see Note 21) to the accelerated repayment of the SunCor Secured Revolver and SunCor’s other outstanding debt, including several project loans totaling approximately $24 million which recently matured. The impairment charges discussed in Note 21 and the maturity and non-payment of the project loans resulted in violations of certain covenants contained in the SunCor Secured Revolver and SunCor’s other credit facilities. If SunCor is unable to obtain waivers or similar relief from its lenders, which it is currently seeking, SunCor could be required to immediately repay its outstanding indebtedness under the SunCor Secured Revolver and its other credit facilities. Such debt acceleration would have a material adverse impact on SunCor’s business and its financial position. 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. As a result, Pinnacle West does not believe that SunCor’s inability to obtain waivers or similar relief from SunCor’s lenders would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

     As of March 31, 2009, SunCor could not transfer any cash dividends to Pinnacle West as a result of the covenants mentioned above. The restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

5. Regulatory Matters

     2008 General Retail Rate Case

     Summary of APS Request and Interim Rate Surcharge — On June 2, 2008, APS filed with the ACC updated financial statements, testimony and other data in the general rate case originally filed on March 24, 2008. In its filing, APS requested a net retail rate increase of $278.2 million effective no later than October 1, 2009, which represents a base rate increase of $448.2 million less the reclassification of $170 million of fuel and purchased power revenues from the existing PSA to base rates.

     On December 18, 2008, the ACC approved an emergency interim base rate surcharge for APS. This surcharge became effective for retail customer bills issued after December 31, 2008 and will continue in effect until a decision in the general rate case becomes effective. This surcharge increased annual pretax retail revenues by approximately $65.2 million, and is subject to refund with interest pending the final outcome of APS’ general retail rate case.

     The interim rate decision required APS to, among other things, examine its operations and expenses, targeting additional cuts of at least $20 million, report the results of its study to the ACC no later than March 18, 2009, and reinvest the savings and surcharge revenues in infrastructure and technology necessary to serve APS customers and reduce the need for external debt financing. On March 18, 2009, APS filed a letter with the ACC identifying a minimum of $25.9 million of specific pretax annualized cost reductions, including decreases in operations and maintenance and other expenses, as well as some capital expenditure reductions.

     Proposed Settlement— APS and the other parties to the rate case began settlement discussions on January 30, 2009 and, on May 4, 2009, they filed a term sheet with the ACC outlining the major terms for settlement of the rate case as agreed to by the parties. The parties also filed a request for procedural order, indicating that the parties will file the definitive settlement agreement on June 12, 2009, and proposing that testimony filings be made by APS and other parties to the case in July and August, and that the hearing begin on August 17, 2009. The ACC must approve any definitive settlement agreement entered into by the parties. We cannot predict whether the parties will enter into a definitive settlement agreement or, if the parties do so, whether or when the ACC would approve the agreement.

     The settlement term sheet includes the following key provisions:

• A non-fuel base rate increase in annual pretax revenues of $196.3 million to be effective January 1, 2010, a portion of which will replace the $65.2 million interim base rate surcharge described above;

• A net increase in annual pretax revenues of $11.2 million for fuel and purchased power costs reflected in base rates to be effective January 1, 2010, which reflects the reclassification of fuel and purchased power revenues from the existing PSA to base rates;

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• A Base Fuel Rate of $0.0376 per kWh (compared to the current Base Fuel Rate of $0.0325 per kWh);

• Revenue accounting treatment for line extension payments received for new or upgraded service during 2010, 2011 and 2012 (or until new rates are established in APS’ next general rate case, if that is before the end of 2012) resulting in estimated increased revenues of $23 million, $25 million and $49 million, respectively (after such time the proceeds will be treated as contributions in aid of construction rather than revenues, unless the ACC orders continued revenue treatment);

• An authorized return on common equity of 11%;

• Additional expense reductions of at least $10 million to be implemented beginning in 2010, such that total average annual cost and expense reductions (after considering the $20 million of cuts pursuant to the interim rate decision) will be at least $30 million in 2010 through 2014 ($150 million for the five-year period);

• Equity infusions into APS of at least $700 million during the period beginning with the execution of the definitive settlement agreement through December 31, 2014; and

• Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that would require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy.

     The parties also agreed to a rate case filing plan in which APS may file its next two general rate cases on or after June 1, 2011 and June 1, 2013, respectively. APS may not request its next general retail rate increase to be effective prior to July 1, 2012. In addition, the parties intend to process these subsequent rate cases within twelve months of sufficiency findings from the ACC staff.

     The following disclosure addresses the rate request that APS filed in June 2008 and the recommendations of various intervenors, including the ACC staff, in response to APS’ request. Although the settlement term sheet contains a framework for the settlement of the rate case, APS’ request and the intervenors’ recommendations would reflect the parties’ current positions if a settlement of the rate case is not reached or is not approved by the ACC.

     Key Provisions of APS’ June 2, 2008 Request — In its June 2, 2008 filing, APS requested a net retail rate increase of $278.2 million effective no later than October 1, 2009, which represents a base rate increase of $448.2 million less the reclassification of $170 million of fuel and purchased power revenues from the existing PSA to base rates. As proposed by APS, the updated request would result in an average rate increase of 8.5% for existing customers plus the establishment of a new growth-related impact fee to be charged to new connections.

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     The key financial provisions of the updated request include:

• an increase of $264.3 million in non-fuel base rates and a net increase of $13.9 million for fuel and purchased power costs reflected in base rates, and recovery of up to $53 million of such increases through the impact fee;

• a rate base of $5.4 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2007, which includes certain adjustments, such as the inclusion of Units 5 and 6 of the Yucca Power Plant (near Yuma in southwestern Arizona), the steam generator replacement at Palo Verde Unit 3, environmental upgrades to APS coal plants, and other plant additions under construction at the end of the test year that are currently in service or expected to go into service before the proposed rates are requested to become effective;

• the following proposed capital structure and costs of capital:

	Capital			Cost of
	Structure			Capital
Long-term debt		46.2	%		5.77	%
Common stock equity		53.8	%		11.50	%
Weighted-average cost of capital					8.86	%

• a Base Fuel Rate of $0.0388 per kWh based on estimated 2010 prices (compared to the current Base Fuel Rate of $0.0325 per kWh);

• an attrition adjustment of $79.3 million to address erosion in APS’ earnings and return on equity through 2010; and

• a new super-peak residential time-of-use rate and a commercial and industrial critical peak pricing proposal to allow eligible customers additional options to manage their electric bills, as well as other conservation-related rate design proposals.

     The update also requested that the ACC adopt certain goals for APS to improve its financial strength, which include: allowing APS’ internal cash flow generation to cover its operating and capital costs of providing service; stabilizing and improving APS’ credit ratings; and providing a meaningful and ongoing opportunity for APS to achieve a reasonable return on the fair value of its property.

     In addition, APS requested various modifications to the Environmental Improvement Surcharge and the Demand Side Management Adjustment Clause that would allow APS to expand its conservation and demand-side management programs and support environmental upgrades to APS facilities in response to and in anticipation of future environmental requirements.

     ACC Staff Rate Case Recommendation — On December 19, 2008, the ACC staff and other intervenors filed their initial written testimony with the ACC in the general retail rate case. In its filed testimony, the ACC staff recommended a number of cost disallowances and test-year adjustments that decrease APS’ base rate request by $141.6 million. The principal

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components of the revenue increase recommended by the ACC staff are $155.1 million for non-fuel increases and $11.4 million for fuel and purchased power costs reflected in base rates (net of the reclassification of $140.1 million of existing PSA revenues to base rates).

     Other Intervenors’ Recommendations — Other intervenors in the rate case include the Arizona Residential Utility Consumer Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; and Arizonans for Electric Choice and Competition (“AECC”), a coalition that advocates on behalf of commercial and industrial utility customers. RUCO recommended no net rate change after reclassification of $170.0 million of PSA revenues to base rates, based on a rate base of $4.9 billion, a base fuel rate of $0.0388 per kWh, APS’ proposed capital structure, and a return on common equity of 9.6%. AECC recommended that APS’ request be reduced by $101.4 million (of which $42.5 million was a reduction in fuel and purchased power expense).

     PSA Balance

     The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for the three-month period ended March 31, 2009 and 2008 (dollars in millions):

	Three Months Ended
	March 31,
	2009			2008
Beginning balance	$	8		$	111
Deferred fuel and purchased power costs-current period		(28	)		(11	)
Interest on deferred fuel and purchased power		—			1
Amounts recovered through revenues		(29	)		(51	)
Ending balance	$	(49	)	$	50

     The PSA annual adjustor rate is reset for a “PSA Year” effective for a twelve-month period beginning February 1 each year. The PSA rate for the PSA Year that began February 1, 2008 was set at $0.004 per kWh. The PSA rate for the PSA year that began February 1, 2009 was set at $0.0053 per kWh. The PSA rate may not be increased more than $0.004 per kWh in a year without permission of the ACC. The $49 million regulatory liability at March 31, 2009 reflects the seasonal nature of fuel and purchased power costs and lower average prices. Any uncollected (overcollected) deferrals during the 2009 PSA Year resulting from this limit will be included in the historical component of the PSA rate for the PSA Year beginning February 1, 2010.

     Formula Transmission Tariff

     In July 2008, the 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. The formula rate is updated 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, and projected capital expenditures. A large portion of the rate represents charges for transmission services to serve APS’ retail

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with the ACC under the transmission cost adjustor (“TCA”) mechanism, by which changes in Retail Transmission Charges can be reflected in APS’ retail rates.

     In 2008, APS was authorized to implement increases in its annual transmission revenues based on calculations filed with the FERC using data for its 2006 and 2007 fiscal years. Increases in APS’ annual transmission revenues of $28 million became effective March 1, 2008 and $15 million became effective June 1, 2008. The ACC allowed APS to reflect the related increased Retail Transmission Charges in its retail rates through the TCA, resulting in increases of annual retail revenues of $27 million effective March 1, 2008 and $13 million effective July 3, 2008.

     Equity Infusion Approval

     On May 2, 2008, Pinnacle West filed a notice with the ACC that would allow Pinnacle West to infuse up to $400 million of equity into APS in the event Pinnacle West deems it appropriate to do so to strengthen or maintain APS’ financial integrity. Under Arizona law and implementing regulatory decisions, Pinnacle West is required to give such notice at least 120 days prior to an equity infusion into APS that exceeds $150 million in a single calendar year. On August 6, 2008, the ACC issued an order permitting the infusion to occur on or before December 31, 2009. Pursuant to the terms of the proposed retail rate case settlement, APS would have authorization to obtain equity infusions of up to $700 million during the period beginning with the execution of the definitive settlement agreement through December 31, 2014, and such authorization would replace the $400 million authorization described above.

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.

     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):

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	Pension Benefits						Other Benefits
	Three Months						Three Months
	Ended March 31,						Ended March 31,
	2009			2008			2009			2008
Service cost — benefits earned during the period	$	14		$	13		$	5		$	5
Interest cost on benefit obligation		29			27			10			10
Expected return on plan assets		(29	)		(29	)		(9	)		(11	)
Amortization of:
Transition obligation		—			—			1			1
Prior service cost		1			1			—			—
Net actuarial loss		3			4			3			1
Net periodic benefit cost	$	18		$	16		$	10		$	6
Portion of cost charged to expense	$	8		$	7		$	5		$	3
APS’ share of cost charged to expense	$	8		$	7		$	5		$	3

Contributions

     At December 31, 2008, we estimated the minimum contribution to our pension plan to be approximately $36 million in 2009 and approximately $25 million in 2010. A recent change in IRS regulations allows alternative measurement dates to determine the interest rate used to value pension liabilities for funding purposes. As a result of this change, we now estimate our minimum pension contribution to be zero in both 2009 and 2010. The expected contribution to our other postretirement benefit plans in 2009 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% 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 electricity service to 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, 2009 and 2008 and at March 31, 2009 and December 31, 2008 is provided as follows (dollars in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended
	March 31,
	2009			2008
Operating Revenues:
Regulated electricity segment	$	603		$	623
Real estate segment		18			26
All other (a)		8			39
Total	$	629		$	688
Net Income (Loss) attributable to common shareholders:
Regulated electricity segment	$	(20	)	$	(6	)
Real estate segment		(132	)		(1	)
All other (a)		(5	)		3
Total	$	(157	)	$	(4	)

	As of		As of
	March 31, 2009		December 31, 2008
Assets:
Regulated electricity segment	$	10,991	$	10,951
Real estate segment		293		523
All other (a)		134		146
Total	$	11,418	$	11,620

(a) Includes activities related to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.

8. Income Taxes

     As of March 31, 2009, the tax year ended December 31, 2005 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. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next 12 months.

     Pinnacle West expects to recognize approximately $100 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 21) which will not be realized until the asset sale transactions are completed. Approximately $80 million of these benefits were recorded in the first quarter of 2009 as reductions to income tax expense related to the current impairment charges. The additional $20 million of tax benefits were recorded as reductions to income tax expense related to the SunCor impairment charge recorded in the fourth quarter of 2008.

9. Variable-Interest Entities

     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     APS is exposed to losses under the Palo Verde sale leaseback agreements 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 assume the debt associated with the transactions, make specified payments to the equity participants, 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, 2009, APS would have been required to assume approximately $174 million of debt and pay the equity participants approximately $162 million.

     SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected in our Condensed Consolidated Balance Sheets related to these arrangements were approximately $29 million at March 31, 2009 and December 31, 2008.

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 instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter 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. As of March 31, 2009, we hedged certain exposures to the price variability of commodities for a maximum of 39 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

     We recognize all derivatives, except those which qualify for a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. Derivative commodity contracts 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 discussion and disclosures below.

     We enter into derivative instrument positions for economic hedging purposes. In some instances, these economic hedges may not qualify as accounting hedges, or have not been designated as hedges under SFAS No. 133. Those positions not designated or qualifying as accounting hedges under SFAS No. 133 are reported as “non-hedging” instruments in the tables below. The term “hedge,” as it is used in the following disclosure, is used to describe an accounting hedge. We may also invest in derivative instruments for trading purposes; however, for the quarter ended March 31, 2009, there was no material trading activity.

     We designate commodity forward contracts, futures, options and swaps as cash flow hedges. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. For cash flow hedges that are deemed an effective hedge, the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period during which the hedged transaction affects earnings. Hedge effectiveness is the degree to which the derivative contract and the hedged item are correlated and is measured based on the relative changes in

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

fair value between the derivative 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. 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.

     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 gains and losses on certain derivatives that would otherwise be recognized in income pursuant to the PSA mechanism. Unless otherwise noted, gains and losses from derivatives in the following tables represent the amounts reflected as income after the effect of PSA deferrals.

     We adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” on January 1, 2009. This new standard requires enhanced disclosures about derivative instruments and hedging activities. The adoption of SFAS No. 161 did not have a material impact on our financial statements.

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements.”

     As of March 31, 2009, we had the following gross notional amount of derivatives, which represent both purchases and sales:

Commodity	Quantity
Power	14,790,285 MWh
Gas	189,580,570 MMBTU

     The Effect of Derivative Instruments on the Condensed Consolidated Statements of
Income

     Amounts included in our Condensed Consolidated Statements of Income are net of amounts deferred under the PSA (see Note 5).

     Derivative Instruments in Hedging Relationships

     Gains and losses on derivative instruments in hedging relationships are reflected in operating expenses on the Regulated Electricity Segment Fuel and Purchased Power line on our Condensed Consolidated Statements of Income. This includes amounts reclassified from OCI into income (effective portion realized) and amounts recognized in income from derivatives (ineffective portion and amount excluded from effectiveness testing).

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     The following table provides information about these gains and losses and their impact on our Condensed Consolidated Statements of Income during the three months ended March 31, 2009 (dollars in thousands):

					Amount of Gain
					Recognized in Income
					from Derivative
	Amount of Loss		Amount of Loss		Instruments (Ineffective
	Recognized in OCI		Reclassified from		Portion and Amount
	on Derivative		OCI into Income		Excluded from
	Instruments		(Effective Portion		Effectiveness Testing)
	(Effective Portion)		Realized)		(a) (b)
Commodity contracts	$	138,548	$	25,365	$	99

(a)	Amount excludes net gains of $892 which were deferred under the PSA.
(b)	During the first quarter 2009 we had no amounts reclassified from OCI to earnings related to discontinued cash flow hedges.

     During the next twelve months, we estimate that a net loss of $157 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, at least 90% of these amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

     Derivative Instruments Not Designated as Hedges

     The following table provides information about our derivatives not designated as hedging instruments and their impact on our Condensed Consolidated Statements of Income during the three months ended March 31, 2009 (dollars in thousands):

		Amount of Gain (Loss)
	Location of Gain (Loss)	Recognized in Income from
	Recognized in Income	Derivative Instruments (a)
Commodity contracts	Regulated electricity segment revenues	$	108
Commodity contracts	Regulated electricity segment fuel and purchased power expense		(4,031	)
Total		$	(3,923	)

(a) Amounts exclude net losses of $41,373 which were deferred under the PSA.

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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. These amounts are located in the asset or liability from risk management and trading activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of March 31, 2009 (dollars in thousands):

				Long-term			Current			Long-term			Total Assets/
Commodity contracts	Current Assets			Assets			Liabilities			Liabilities			(Liability)
Derivatives designated as hedging instruments under SFAS No. 133:
Assets	$	105		$	—		$	7,970		$	32		$	8,107
Liabilities		(1,629	)		—			(172,538	)		(121,551	)		(295,718	)
Total hedging instruments		(1,524	)		—			(164,568	)		(121,519	)		(287,611	)
Derivatives not designated as hedging instruments under SFAS No. 133:
Assets		29,218			38,539			73,970			49,768			191,495
Liabilities		(1,023	)		(4,345	)		(209,138	)		(129,239	)		(343,745	)
Total non-hedging instruments		28,195			34,194			(135,168	)		(79,471	)		(152,250	)
Total derivatives		26,671			34,194			(299,736	)		(200,990	)		(439,861	)
Margin account		37,185			—			78,929			5,241			121,355
Collateral provided to counterparties		113			—			159,403			59,681			219,197
Collateral provided from counterparties		—			—			(2,550	)		—			(2,550	)
Balance Sheet Total	$	63,969		$	34,194		$	(63,954	)	$	(136,068	)	$	(101,859	)

     Derivative assets and liabilities in the table are reported on a gross basis and exclude cash collateral and margin accounts. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet, including cash collateral and margin in accordance with FSP FIN 39-1.

Credit Risk

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 69% of Pinnacle West’s $98 million of risk management and trading assets as of March 31, 2009. 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’ securities 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Credit Related Contingent Features

     Certain of our derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from the major credit rating agencies. If our debt were to fall below investment grade, these provisions could be violated, and the counterparties to the derivative instruments could demand immediate and ongoing full collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on March 31, 2009 was $515 million for which we had posted collateral of $219 million in the normal course of business. If the credit-risk-related contingent features underlying these agreements had been triggered on March 31, 2009, after off-setting asset positions under master netting arrangements we would have been required to post an additional $197 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 non-derivative contracts with credit related contingent features which could also require additional collateral if our debt were to fall below investment grade.

11. Changes in Equity

     The following table shows the Company’s changes in common stock equity and changes in equity of noncontrolling interests for the three months ended March 31, 2009 and 2008 (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended March 31, 2009									Three Months Ended March 31, 2008
	Common			Noncontrolling						Common			Noncontrolling
	Shareholders			Interests			Total			Shareholders			Interests			Total
Beginning balance, January 1	$	3,445,979		$	47,389		$	3,493,368		$	3,531,611		$	54,569		$	3,586,180
Net income (loss)		(156,510	)		(14,210	)		(170,720	)		(4,473	)		—			(4,473	)
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		(138,548	)		—			(138,548	)		119,806			—			119,806
Net reclassification of realized (gains) losses to income (b)		25,365			—			25,365			(2,065	)		—			(2,065	)
Reclassification of pension and other postretirement benefits to income		1,252			—			1,252			1,043			—			1,043
Income tax (expense) benefit related to items of other comprehensive income		44,003			—			44,003			(46,481	)		—			(46,481	)
Total other comprehensive income (loss)		(67,928	)		—			(67,928	)		72,303			—			72,303
Total comprehensive income (loss)		(224,438	)		(14,210	)		(238,648	)		67,830			—			67,830
Issuance of capital stock		2,629			—			2,629			2,815			—			2,815
Purchase of treasury stock, net of reissuances		(1,551	)		—			(1,551	)		(1,344	)		—			(1,344	)
Other (primarily stock compensation)		(6,707	)		(129	)		(6,836	)		(3,952	)		(322	)		(4,274	)
Common stock dividends		(53,010	)		—			(53,010	)		(52,759	)		—			(52,759	)
Capital contribution by noncontrolling interests		—			1,316			1,316			—			—			—
Ending balance, March 31	$	3,162,902		$	34,366		$	3,197,268		$	3,544,201		$	54,247		$	3,598,448

(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.

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 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least 2017. 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. In August 2008, the United States Court of Appeals for the Federal Circuit issued decisions in three damages actions brought by other nuclear utilities that could result in a decrease in the amount of our recoverable damages; however, additional appeals in those actions are possible and APS continues to monitor the status of those actions. The trial in the APS matter began on January 28, 2009. Testimony and evidence have been presented by both sides. The trial court has set a post-trial briefing schedule and is expected to hear closing arguments in the early summer of 2009.

     APS currently estimates it will incur $132 million (in 2009 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, 2009, APS had a regulatory liability of $25 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

California Energy Market Issues and Refunds in the Pacific Northwest

     FERC

     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 ALJ’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. Petitions for rehearing of this opinion were filed. Although the

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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

     Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, the 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. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.

Salt River Project

     Salt River Project previously notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserted that certain of these failures to bill APS for such losses and charges may have extended back to 1996 and, as a result, claimed that APS owed it approximately $29 million, which APS disputed.  The parties entered into a settlement agreement on April 9, 2009, resolving these matters. The resolution had no material adverse impact on our financial position, results of operations or cash flows.

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. We currently have several assets on our books related to our landlord, including an asset related to rent payments for the building of approximately $63 million. 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.

Litigation

     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

13. Nuclear Insurance

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an 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 of retrospective assessments APS could incur under the current NEIL policies totals approximately $21 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

14. Other Income and Other Expense

     The following table provides detail of other income and other expense for the three months ended March 31, 2009 and 2008 (dollars in thousands):

	Three Months Ended
	March 31,
	2009			2008
Other income:
Interest income	$	337		$	2,243
SunCor other income (a)		—			1,587
Miscellaneous		43			9
Total other income	$	380		$	3,839
Other expense:
Non-operating costs	$	(1,608	)	$	(1,920	)
Investment losses – net		(7,230	)		(2,666	)
Miscellaneous		(903	)		(310	)
Total other expense	$	(9,741	)	$	(4,896	)

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

15. Guarantees

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

     Our parental guarantees for APS relate to commodity energy products. As required by Arizona law, Pinnacle West has also obtained a $10 million bond on behalf of APS in connection with the interim base rate surcharge approved by the ACC in December 2008. In addition, Pinnacle West has obtained approximately $8 million of surety bonds related to APS operations, of which approximately $7 million relates to self-insured workers’ compensation. Our credit support instruments enable APSES to offer energy-related products and services. 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, 2009 we had no guarantees that were in default. Our guarantees have no recourse or collateral provisions to allow us to recover from our subsidiaries amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2009 are as follows (dollars in millions):

	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
APS	$	1		1	$	18		1
APSES		14		1		17		1
Total	$	15			$	35

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2009, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 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 $70 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 expire in 2010. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

16. Earnings Per Share

     The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2009 and 2008:

	Three Months Ended
	March 31,
	2009			2008
Basic loss per share:
Loss from continuing operations attributable to common shareholders	$	(1.52	)	$	(0.06	)
Income (loss) from discontinued operations		(0.03	)		0.02
Loss per share – basic	$	(1.55	)	$	(0.04	)
Diluted loss per share:
Loss from continuing operations attributable to common shareholders	$	(1.52	)	$	(0.06	)
Income (loss) from discontinued operations		(0.03	)		0.02
Loss per share – diluted	$	(1.55	)	$	(0.04	)

     For the three months ended March 31, 2009 and 2008 the weighted average common shares outstanding were the same for both basic and diluted shares. Options to purchase 625,524 shares of common stock for the three months ended March 31, 2009, and 703,875 shares for the three months ended March 31, 2008 were outstanding but were excluded from the computation of diluted earnings per share because the impact of including those options would be antidilutive.

17. Discontinued Operations

     SunCor (real estate segment) – In 2009 and 2008, SunCor sold or expects to sell properties that are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144. Assets held for sale relate to properties in the amount of $32 million at March 31, 2009. These properties were classified as home inventory at December 31, 2008. In addition, see Note 21 – Real Estate Impairment Charge.

     APSES (other) – Includes activities related to discontinued commodity-related energy services in 2008, and the associated revenues and costs that were reclassified to discontinued operations in 2008.

     The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2009 and 2008 (dollars in millions):

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	Three Months Ended
	March 31,
	2009			2008
Revenue:
SunCor	$	—		$	23
APSES		—			28
Total revenue	$	—		$	51
Income (loss) before taxes:
SunCor	$	(5	)	$	4
APSES		—			(1	)
Total income before taxes	$	(5	)	$	3
Income (loss) after taxes:
SunCor (a)	$	(3	)	$	3
APSES		—			(1	)
Total income after taxes	$	(3	)	$	2

(a) The three months ended March 31, 2009 includes a $2 million tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement.

18. Nuclear Decommissioning Trust

     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income securities and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments 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, 2009 and December 31, 2008 (dollars in millions):

				Total		Total
				Unrealized		Unrealized
March 31, 2009	Fair Value			Gains		Losses
Equity securities	$	104		$	12	$	(26	)
Fixed income securities		233			9		(6	)
Net payables (a)		(1	)		—		—
Total	$	336		$	21	$	(32	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

			Total		Total
			Unrealized		Unrealized
December 31, 2008	Fair Value		Gains		Losses
Equity securities	$	113	$	18	$	(18	)
Fixed income securities		228		10		(5	)
Net payables (a)		2		—		—
Total	$	343	$	28	$	(23	)

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

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

	Three Months Ended
	March 31,
	2009			2008
Realized gains	$	2		$	1
Realized losses		(2	)		(1	)
Proceeds from the sale of securities		130			67

     The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2009 is as follows (dollars in millions):

	Fair Value
Less than one year	$	6
1 year - 5 years		49
5 years - 10 years		59
Greater than 10 years		119
Total	$	233

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

19. New Accounting Standards

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted for our non-financial assets on January 1, 2009. This guidance was adopted for our financial assets on January 1, 2008.

     See Note 10 for a discussion of SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment to SFAS No. 133,” which we adopted January 1, 2009.

     We adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” on January 1, 2009. This guidance provides accounting and reporting

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standards for noncontrolling interests in a consolidated subsidiary and clarifies that noncontrolling interests should be reported as equity on the consolidated financial statements. As a result of adopting this guidance, we have disclosed on the face of our financial statements the portion of equity and net income attributable to the noncontrolling interests in consolidated subsidiaries. Additionally, we reclassified $47 million of noncontrolling interests from Other Deferred Credits to Equity on the December 31, 2008 balance sheet. Prior year’s net income attributable to noncontrolling interests was not material to our income statement and was not reclassified. The adoption of this guidance modified our financial statements presentation, but did not have an impact on our financial statement results.

     In December 2008, the FASB issued FASB Staff Position No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This guidance requires enhanced employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The guidance is effective for us on December 31, 2009. We do not expect it to have a material impact on our financial statements.

     In April 2009, the FASB issued various Staff Positions relating to fair value measurements and impairments. This guidance includes: FASB Staff Position No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”; FASB Staff Position Nos. FAS  115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”; and FASB Staff Position Nos. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” These Staff Positions were effective for us on April 1, 2009. We do not expect them to have a material impact on our financial statements.

     Effective January 1, 2009, we adopted FASB Staff Position No. EITF 03-6-1 (FSP EITF 03-6-1), “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” FSP EITF 03-6-1 requires companies to treat unvested share-based payment awards that have nonforfeitable rights to dividends or dividend equivalents as participating securities when computing earnings per share, pursuant to the two-class method described in SFAS No. 128, “Earnings Per Share.” Our awards do not have nonforfeitable rights to dividends or dividend equivalents and therefore the adoption of this FSP did not have any impact on our financial statements.

20. Fair Value Measurements

     SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and requires companies to 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.

     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.

     Level 3 — Model-derived valuations with unobservable inputs that are supported by little or no market activity.

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     As required by SFAS No. 157, assets and liabilities are classified 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 apply recurring fair value measurements to derivative instruments, nuclear decommissioning trusts, and certain cash equivalents. 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.

     In February 2008, the FASB issued FASB Staff Position No. FAS 157-2 (FSP 157-2), “Effective Date of FASB Statement No. 157,” which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and liabilities by one year. In accordance with FSP 157-2, we delayed the adoption of SFAS No. 157 for our nonfinancial assets and liabilities, except those items recognized or disclosed at fair value on a recurring basis, until January 1, 2009. We adopted SFAS No. 157 for our nonfinancial assets and liabilities on January 1, 2009, and it did not have a material impact on our financial statements.

     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.

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

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	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable						Balance at
	Assets			Inputs			Inputs			Counterparty			March 31,
Pinnacle West:	(Level 1)			(Level 2)			(Level 3)			Netting & Other (a)			2009
Assets
Cash equivalents	$	16		$	—		$	—		$	—		$	16
Risk management and trading activities		15			108			65			(90	)		98
Nuclear decommissioning trust		39			297			—			—			336
Total	$	70		$	405		$	65		$	(90	)	$	450
Liabilities
Risk management and trading activities	$	(99	)	$	(441	)	$	(88	)	$	428		$	(200	)

     The following table presents the fair value at December 31, 2008 of our assets and liabilities that are measured at fair value on a recurring basis for Pinnacle West Consolidated and APS (dollars in millions):

	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable						Balance at
	Assets			Inputs			Inputs			Counterparty			December 31,
Pinnacle West:	(Level 1)			(Level 2)			(Level 3)			Netting & Other (a)			2008
Assets
Cash equivalents	$	75		$	—		$	—		$	—		$	75
Risk management and trading activities		31			76			51			(92	)		66
Nuclear decommissioning trust		33			308			—			2			343
Total	$	139		$	384		$	51		$	(90	)	$	484
Liabilities
Risk management and trading activities	$	(85	)	$	(297	)	$	(58	)	$	244		$	(196	)

(a) Primarily represents netting under master netting arrangements, including margin and collateral. See Note 10.

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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, 2009 and 2008 for Pinnacle West Consolidated and APS (dollars in millions):

	Three Months Ended
	March 31,			March 31,
	2009			2008
Net derivative balance at beginning of period	$	(7	)	$	8
Total net gains (losses) realized/unrealized:
Included in earnings		2			(2	)
Included in OCI		(1	)		2
Deferred as a regulatory asset or liability		(3	)		(3	)
Purchases, issuances, and settlements		—			—
Level 3 transfers (a)		(14	)		2
Net derivative balance at end of period	$	(23	)	$	7
Net unrealized losses included in earnings related to instruments still held at end of period	$	2		$	2

(a) 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.

     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 weakened 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, 2009, the fair value of our impaired real estate assets that are measured at fair value on a nonrecurring basis was $146 million, all of which was valued using significant unobservable inputs (Level 3). Total impairment charges included in net loss were approximately $216 million (includes net losses attributable to noncontrolling interests of $14 million before income taxes). See Note 21 for additional information.

21. Real Estate Impairment Charge

     As a result of current and anticipated continuing distressed conditions in real estate and credit markets, SunCor undertook and has now completed a review of its assets and strategies within its various 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, and golf courses in order to reduce SunCor’s outstanding debt. SunCor currently plans to retain selected Arizona assets, including land parcels and commercial assets associated with SunCor’s Hayden Ferry Lakeside project in Tempe, Arizona, and approximately 2,000 acres of commercial land associated with its Palm Valley project located west of Phoenix, Arizona.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     Management plans to dispose of the assets in 2009. As a result of this decision, we recorded a pretax impairment charge in the first quarter of approximately $202 million, or $123 million after taxes on a Pinnacle West consolidated basis. Of the total $202 million impairment charge, approximately $9 million related to assets held for sale and approximately $193 million related to held and used assets. SunCor expects to reclassify most of the affected properties to assets held for sale beginning in the second quarter of 2009, as marketing of the assets commences and other criteria are met. The detail of the impairment charge is as follows (dollars in millions):

Homebuilding and master-planned communities	$	141
Land parcels and commercial assets		53
Golf courses		17
Subtotal		211
Discontinued operations		5
Less non-controlling interests		(14	)
Total	$	202

     We determine fair value for our real estate assets primarily based on either the future cash flows that we estimate will be generated by each asset discounted for market risk or market appraisals. 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 determine fair values at March 31, 2009 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. If conditions in the broader economy or the real estate markets worsen, or as a result of a change in SunCor’s strategy, we may be required to record additional impairments.

     SunCor also recorded in the first quarter approximately $8 million of pretax severance and other charges relating to these actions. Pinnacle West does not expect that any of the impairment charges will result in future cash expenditures, other than immaterial disposition costs.

     The SunCor Secured Revolver was recently extended for a twelve-month period to January 2010 and requires SunCor to reduce its outstanding borrowings by specified amounts over the term of the facility. As of March 31, 2009, approximately $108 million of borrowings were outstanding under the SunCor Secured Revolver and approximately $67 million of debt was outstanding under other SunCor credit facilities. SunCor intends to apply the proceeds of the asset sales described above to the accelerated repayment of the SunCor Secured Revolver and SunCor’s other outstanding debt, including several project loans totaling approximately $24 million which recently matured. The impairment charges discussed above and the maturity and non-payment of the project loans resulted in violations of certain covenants contained in the SunCor Secured Revolver and SunCor’s other credit facilities. If SunCor is unable to obtain waivers or similar relief from its lenders, which it is currently seeking, SunCor could be required to immediately repay its outstanding indebtedness under the SunCor Secured Revolver and its other credit facilities. Such debt acceleration would have a material adverse impact on SunCor’s business and its financial position. 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. As a result, Pinnacle West does not believe that SunCor’s inability to obtain waivers or similar relief from SunCor’s lenders would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended
	March 31,
	2009			2008
ELECTRIC OPERATING REVENUES	$	602,660		$	625,576
OPERATING EXPENSES
Fuel and purchased power		247,388			272,053
Operations and maintenance		201,100			188,135
Depreciation and amortization		98,011			93,885
Income taxes		(6,744	)		5,157
Other taxes		33,780			32,718
Total		573,535			591,948
OPERATING INCOME		29,125			33,628
OTHER INCOME (DEDUCTIONS)
Income taxes		1,182			1,115
Allowance for equity funds used during construction		4,992			6,124
Other income (Note S-2)		415			2,064
Other expense (Note S-2)		(4,358	)		(5,888	)
Total		2,231			3,415
INTEREST DEDUCTIONS
Interest on long-term debt		46,395			42,173
Interest on short-term borrowings		2,975			3,849
Debt discount, premium and expense		1,189			1,160
Allowance for borrowed funds used during construction		(3,724	)		(3,775	)
Total		46,835			43,407
NET LOSS	$	(15,479	)	$	(6,364	)

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

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

	March 31,			December 31,
	2009			2008
ASSETS
UTILITY PLANT
Electric plant in service and held for future use	$	12,263,329		$	12,198,010
Less accumulated depreciation and amortization		4,192,971			4,129,958
Net		8,070,358			8,068,052
Construction work in progress		619,142			571,977
Intangible assets, net of accumulated amortization		142,743			131,243
Nuclear fuel, net of accumulated amortization		99,304			89,323
Total utility plant		8,931,547			8,860,595
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 18)		336,091			343,052
Assets from long-term risk management and trading activities (Note 10)		34,194			33,675
Other assets		59,758			60,604
Total investments and other assets		430,043			437,331
CURRENT ASSETS
Cash and cash equivalents		18,454			71,544
Customer and other receivables		191,574			262,177
Accrued utility revenues		84,724			100,089
Allowance for doubtful accounts		(2,503	)		(3,155	)
Materials and supplies (at average cost)		182,961			173,252
Fossil fuel (at average cost)		31,839			29,752
Assets from risk management and trading activities (Note 10)		63,969			32,181
Deferred income taxes		119,920			79,694
Other current assets		21,254			19,866
Total current assets		712,192			765,400
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		—			7,984
Other regulatory assets		825,069			787,506
Unamortized debt issue costs		25,466			22,026
Other		88,166			82,735
Total deferred debits		938,701			900,251
TOTAL ASSETS	$	11,012,483		$	10,963,577

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

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

	March 31,			December 31,
	2009			2008
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital		2,122,292			2,117,789
Retained earnings		1,110,922			1,168,901
Accumulated other comprehensive loss (Note S-1):
Pension and other postretirement benefits		(26,362	)		(26,960	)
Derivative instruments		(167,173	)		(98,742	)
Common stock equity		3,217,841			3,339,150
Long-term debt less current maturities (Note 4)		3,349,912			2,850,242
Total capitalization		6,567,753			6,189,392
CURRENT LIABILITIES
Short-term borrowings		236,176			521,684
Current maturities of long-term debt (Note 4)		942			874
Accounts payable		145,316			233,529
Accrued taxes		236,500			219,129
Accrued interest		44,639			39,860
Customer deposits		77,093			77,452
Liabilities from risk management and trading activities (Note 10)		63,954			69,585
Other current liabilities		66,184			105,655
Total current liabilities		870,804			1,267,768
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,389,483			1,401,412
Regulatory liabilities		591,601			587,586
Deferred fuel and purchased power regulatory liability (Note 5)		49,215			—
Liability for asset retirements		280,615			275,970
Liabilities for pension and other postretirement benefits (Note 6)		647,831			635,327
Customer advances for construction		138,100			132,023
Liabilities from long-term risk management and trading activities (Note 10)		136,068			126,532
Other		341,013			347,567
Total deferred credits and other		3,573,926			3,506,417
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	11,012,483		$	10,963,577

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

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

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(15,479	)	$	(6,364	)
Adjustments to reconcile net loss to net cash (used for) provided by operating activities:
Depreciation and amortization including nuclear fuel		108,163			102,696
Deferred fuel and purchased power		28,238			9,721
Deferred fuel and purchased power amortization		28,961			50,709
Allowance for equity funds used during construction		(4,992	)		(6,124	)
Deferred income taxes		(6,335	)		(34,793	)
Change in mark-to-market valuations		3,823			(13,458	)
Changes in current assets and liabilities:
Customer and other receivables		71,551			43,922
Accrued utility revenues		15,365			12,764
Materials, supplies and fossil fuel		(11,796	)		(11,418	)
Other current assets		(2,042	)		163
Accounts payable		(70,828	)		(63,888	)
Other current liabilities		(17,680	)		44,391
Change in margin and collateral accounts — assets		(23,876	)		93,449
Change in margin and collateral accounts — liabilities		(162,012	)		6,648
Change in unrecognized tax benefits		(797	)		13,129
Change in other long-term assets		(1,165	)		13,200
Change in other long-term liabilities		17,460			10,858
Net cash flow provided by (used for) operating activities		(43,441	)		265,605
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(188,973	)		(239,808	)
Contributions in aid of construction		18,762			10,040
Allowance for borrowed funds used during construction		(3,724	)		(3,775	)
Proceeds from nuclear decommissioning trust sales		129,816			67,177
Investment in nuclear decommissioning trust		(135,264	)		(72,362	)
Other		1,500			(1,489	)
Net cash flow used for investing activities		(177,883	)		(240,217	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		496,475			—
Repayment of long-term debt		(233	)		(246	)
Short-term borrowings and payments-net		(285,508	)		(27,056	)
Dividends paid on common stock		(42,500	)		(42,500	)
Net cash flow provided by (used for) financing activities		168,234			(69,802	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(53,090	)		(44,414	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		71,544			52,151
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	18,454		$	7,737
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of refunds	$	13,704		$	5,704
Interest, net of amounts capitalized	$	40,867		$	39,946

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

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     Certain notes to APS’ Condensed 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 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	—
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	—
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	—
New Accounting Standards	Note 19	—
Fair Value Measurements	Note 20	—
Real Estate Impairment Charge	Note 21	—
Comprehensive Income	—	Note S-1

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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS

S-1. Comprehensive Income

     Components of APS’ comprehensive income (loss) for the three months ended March 31, 2009 and 2008 are as follows (dollars in thousands):

	Three Months Ended
	March 31,
	2009			2008
Net loss	$	(15,479	)	$	(6,364	)
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		(138,548	)		107,016
Net reclassification of realized losses to income (b)		25,365			3,318
Reclassification of pension and other postretirement benefits to income		987			795
Income tax (expense) benefit related to items of other comprehensive income		44,363			(43,740	)
Total other comprehensive income (loss)		(67,833	)		67,389
Comprehensive income (loss)	$	(83,312	)	$	61,025

(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.

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, 2009 and 2008 (dollars in thousands):

	Three Months Ended
	March 31,
	2009			2008
Other income:
Interest income	$	183		$	1,723
Miscellaneous		232			341
Total other income	$	415		$	2,064
Other expense:
Non-operating costs (a)	$	(1,335	)	$	(3,322	)
Asset dispositions		(83	)		(1,452	)
Investment losses — net		(1,323	)		(395	)
Miscellaneous		(1,617	)		(719	)
Total other expense	$	(4,358	)	$	(5,888	)

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

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

INTRODUCTION

     The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and Arizona Public Service Company’s Condensed Financial Statements and the related Notes that appear in Item 1 of this report.

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 has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so.

     While customer growth in APS’ service territory has been an important driver of our revenues and earnings, it has significantly slowed, reflecting recessionary economic conditions both nationally and in Arizona. Customer growth averaged 3% a year for the three years 2006 through 2008. We currently expect customer growth and retail electricity sales growth (excluding the effects of weather variations) to average about 1% per year during 2009 through 2011. We currently project that our customer growth will begin to accelerate as the economy recovers.

     The near-term economic conditions are reflected in the recent volatility and disruption of the credit markets, as discussed in detail under “Pinnacle West Consolidated — Liquidity and Capital Resources” below. Despite these conditions, 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.

     Our cash flows and profitability are affected by the electricity rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed below under “Pinnacle West Consolidated — Liquidity and Capital Resources,” are substantial because of increased costs related to environmental compliance and controls and system reliability, as well as continuing, though slowed, customer growth in APS’ service territory.

     APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. See “Factors Affecting Our Financial Outlook” below. On March 24, 2008, APS filed a rate case with the ACC, which it updated on June 2, 2008, requesting, among other things, an increase in retail rates to help defray rising infrastructure costs, approval of an impact fee and approval of new conservation rates. On January 30, 2009, APS and the other parties to the rate case began settlement discussions, and on May 4, 2009 they filed a proposed settlement term sheet with the ACC, a copy of which is attached to this Report on Form 10-Q as Exhibit 99.1. See Note 5 for details regarding this rate case, including the ACC’s approval of an interim base rate surcharge pending the outcome of the case and a discussion of the proposed settlement term sheet and related timeline.

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     As a result of current and anticipated continuing distressed conditions in real estate and credit markets, SunCor, our real estate subsidiary, undertook and has now completed a review of its assets and strategies within its various 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, and golf courses in order to reduce SunCor’s outstanding debt. Management plans to dispose of the assets in 2009. As a result of this decision, we recorded pretax impairment charges in the first quarter of $202 million, or $123 million after taxes on a Pinnacle West consolidated basis. SunCor currently plans to retain selected Arizona assets, with a book value of approximately $70 million. See “Liquidity and Capital Resources — Other Subsidiaries — SunCor” below for a discussion of SunCor’s outstanding debt and related matters.

     Our other principal 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.

     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the generation area, the NRC recently completed its inspections of corrective actions taken by Palo Verde to address certain performance deficiencies, and returned all three units of Palo Verde to routine inspection and oversight. See “NRC Inspection” in Part II, Item 5 below. In the delivery area, we focus on superior reliability and customer satisfaction. We plan to expand long-term energy resources and our transmission and distribution systems to meet the electricity needs of our growing retail customer base and to sustain reliability.

     See “Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.

EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

     Pinnacle West’s two reportable business segments are:

• our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to 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.

     The following table presents loss from continuing operations for our regulated electricity and real estate segments and reconciles those amounts to our consolidated net income (loss) (dollars in millions):

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	Three Months Ended
	March 31,
	2009			2008
Regulated electricity segment	$	(20	)	$	(6	)
Real estate segment (a)		(143	)		(4	)
All other (b)		(5	)		4
Loss from continuing operations		(168	)		(6	)
Income (loss) from discontinued operations — net of tax:
Real estate segment (a)		(3	)		3
All other (b)		—			(1	)
Net Loss		(171	)		(4	)
Less: Net loss attributable to noncontrolling interests — real estate segment (a) (c)		(14	)		—
Net loss attributable to common shareholders	$	(157	)	$	(4	)

(a)	We recorded an after-tax real estate impairment charge in the first quarter of 2009 of $123 million on a Pinnacle West consolidated basis.
(b)	Includes activities related to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.
(c)	See Note 19 regarding the adoption of SFAS No. 160.

PINNACLE WEST CONSOLIDATED — RESULTS OF OPERATIONS

Operating Results — Three-month period ended March 31, 2009 compared with three-month period ended March 31, 2008

     Our consolidated net loss attributable to common shareholders for the three months ended March 31, 2009 was $157 million, compared with a net loss of $4 million for the comparable prior-year period. The major factors that increased or decreased the net loss attributable to common shareholders for the three-month comparison are summarized in the following table (dollars in millions):

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	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment:
Interim retail rate increase effective January 1, 2009	$	13		$	8
Transmission rate increases effective July 1, 2008 (including related retail rates)		6			4
Lower mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals		(19	)		(12	)
Effects of milder weather on retail sales		(13	)		(8	)
Higher depreciation and amortization primarily due to increased utility plant in service		(4	)		(2	)
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances		(4	)		(3	)
Miscellaneous items, net		(1	)		(1	)
Increase in regulated electricity segment net loss		(22	)		(14	)
Real estate segment:
Real estate impairment charge (Note 21)		(211	)		(134	)
Higher real estate segment costs primarily related to employee severance and other disposition costs		(9	)		(5	)
All other:
Lower marketing and trading contributions primarily due to lower sales volumes		(7	)		(4	)
Increase in other expense, net of other income, primarily due to higher investment losses		(6	)		(4	)
Other miscellaneous items, net		(1	)		(1	)
Increase in loss from continuing operations	$	(256	)		(162	)
Decrease in discontinued operations primarily related to the impairment of certain real estate properties (Note 21)					(5	)
Increase in net loss					(167	)
Less: Net loss attributable to real estate noncontrolling interests primarily due to real estate impairment					(14	)
Increase in net loss attributable to common shareholders				$	(153	)

Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $20 million lower for the three months ended March 31, 2009 compared with the prior-year period primarily because of:

• a $22 million decrease in retail revenues due to the effects of weather;

• a $22 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 5);

• a $7 million decrease in retail revenues primarily related to lower average usage per customer, excluding weather effects;

• a $19 million increase in retail revenues due to an interim rate increase effective January 2009 and transmission rate increases in 2008 (including related retail rates);

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• a $16 million increase in renewable energy surcharges, which had no earnings effect because of amortization of the same amount recorded as operations and maintenance expense; and

• a $4 million net decrease due to miscellaneous factors.

Real Estate Segment Revenues

     Real estate segment revenues were $8 million lower for the three months ended March 31, 2009 compared with the prior-year period primarily because of lower residential property sales as a result of the distressed real estate markets.

All Other Revenues

     Other revenues were $31 million lower for the three months ended March 31, 2009 compared with the prior-year period because of planned reductions of marketing and trading activities.

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, 2009 and 2008 (dollars in millions):

	Three Months Ended
	March 31,
	2009			2008
Net cash flow provided by (used for) operating activities	$	(56	)	$	246
Net cash flow used for investing activities		(182	)		(248	)
Net cash flow provided by (used for) financing activities		166			(37	)

     The increase of approximately $302 million in net cash used for operating activities is primarily due to increased collateral and margin cash provided as a result of changes in commodity prices.

     The decrease of approximately $66 million in net cash used for investing activities is primarily due to lower levels of capital expenditures (see table and discussion below).

     The increase of approximately $203 million in net cash provided by financing activities is primarily due to APS’ issuance of $500 million of unsecured senior notes. A portion of these proceeds were used to repay short-term borrowings.

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CAPITAL EXPENDITURES
(dollars in millions)

	Three Months Ended				Estimated for the Year Ended
	March 31,				December 31,
	2008		2009		2009		2010		2011
APS
Distribution	$	88	$	60	$	276	$	266	$	356
Generation (a)		89		70		288		274		319
Transmission		37		31		275		99		185
Other (b)		4		5		44		37		50
Subtotal		218		166		883		676		910
Other		20		6		12		8		8
Total	$	238	$	172	$	895	$	684	$	918

(a)	Generation includes nuclear fuel expenditures of approximately $60 million to $80 million per year for 2009, 2010 and 2011.
(b)	Primarily information systems and facilities projects.

     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, partially offset by contributions in aid of construction in accordance with APS’ line extension policy.

     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 differ for each of the years 2009, 2010 and 2011, with the lowest year estimated at approximately $25 million, and the highest year estimated at approximately $80 million. 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” in Item 1 of the 2008 Form 10-K and “Environmental Matters — EPA Environmental Regulation — Mercury” in Part II, Item 5 below.)

     In early 2008, we announced and began implementing a cost reduction effort that included the elimination of approximately $200 million of capital expenditures for the years 2008 — 2012. These capital expenditure reductions are reflected in the estimates provided above. Due primarily to our reduced customer growth outlook as well as the deferral of upgrades and other capital projects, we have identified additional capital expenditure reductions of over $500 million at APS (net of the change in amounts collected for projected line extensions) over the years 2009 — 2011. These reductions are across all areas — distribution, generation, transmission and general plant, and are reflected in the estimates provided above. (See “Pinnacle West Consolidated — Factors Affecting Our Financial Outlook — Customer and Sales Growth” below for additional information on our growth outlook.)

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     Capital expenditures will be funded with internally generated cash and/or 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 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 22, 2009, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on June 1, 2009, to shareholders of record on May 1, 2009.

     Our primary sources of cash are dividends from APS, external debt and equity financings and cash distributions from our other subsidiaries. In addition, Pinnacle West expects to recognize approximately $100 million of cash tax benefits related to SunCor’s strategic asset sales which will not be realized until the asset sale transactions are completed. Approximately $80 million of these benefits were recorded in the first quarter of 2009 as reductions to income tax expense related to the current impairment charges. The additional $20 million of tax benefits were recorded as reductions in income tax expense related to the impairment charge recorded in the fourth quarter of 2008.

     An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. 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, 2009, APS’ common equity ratio, as defined, was approximately 49%.

     The credit and liquidity markets experienced significant stress beginning the week of September 15, 2008. While Pinnacle West’s and APS’ ability to issue commercial paper has been negatively impacted by the market stress, they have both been able to access existing credit facilities, ensuring adequate liquidity. Cash on hand is being invested in money market funds consisting of U.S. Treasury and government agency securities and repurchase agreements collateralized fully by U.S. Treasury and government agency securities.

     Pinnacle West (parent company) has a $283 million revolving credit facility that terminates in December 2010. The revolver is available to support the issuance of up to $250 million in commercial paper (see discussion above) or to be used as bank borrowings, including issuances of letters of credit of up to $94 million. At March 31, 2009, the parent company had outstanding $166 million of borrowings under its revolving credit facility and approximately $7 million of letters of credit. It also had no commercial paper outstanding at March 31, 2009. At March 31, 2009, the parent company had remaining capacity available under its revolver of approximately $110 million and had cash and investments of approximately $3 million.

     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

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tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity, real estate and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We contributed $35 million to our pension plan in 2008. At December 31, 2008, we estimated the minimum contribution to our pension plan to be approximately $36 million in 2009 and approximately $25 million in 2010. A recent change in IRS regulations allows alternative measurement dates to determine the interest rate used to value pension liabilities for funding purposes. As a result of this change, we now estimate our minimum pension contribution to be zero in both 2009 and 2010. The expected contribution to our other postretirement benefit plans in 2009 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

     See Note 5 for information regarding Pinnacle West’s approval from the ACC regarding a potential equity infusion into APS of up to $400 million. In addition, see Note 5 for details regarding terms of the proposed retail rate case settlement under which APS would have authorization to obtain additional equity infusions.

     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. APS has historically paid its dividends to Pinnacle West with cash from operations. 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 26, 2009, APS issued $500 million of 8.75% unsecured senior notes that mature on March 1, 2019. Net proceeds from the sale of the notes were used to repay short-term borrowings under two committed revolving lines of credit incurred to fund capital expenditures and for general corporate purposes.

     APS has two committed revolving credit facilities totaling $866 million, of which $377 million terminates in December 2010 and $489 million terminates in September 2011. The revolvers are available either to support the issuance of up to $250 million in commercial paper (see discussion above) or to be used for bank borrowings, including issuances of letters of credit up to $583 million. At March 31, 2009, APS had borrowings of approximately $236 million and no letters of credit under its revolving lines of credit. APS had no commercial paper outstanding at March 31, 2009. At March 31, 2009, APS had remaining capacity available under its revolvers of $630 million and had cash and investments of approximately $18 million.

     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 an ACC order permitting Pinnacle West to infuse up to $400 million of equity into APS, on or before December 31, 2009, if Pinnacle West deems it appropriate to do so to strengthen or maintain APS’ financial integrity. In addition, see Note 5 for details regarding terms of the proposed retail rate case settlement under which APS would have authorization to obtain additional equity infusions.

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

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     Other Subsidiaries

     SunCor - As a result of current and anticipated continuing distressed conditions in real estate and credit markets, SunCor, our real estate subsidiary, undertook and has now completed a review of its assets and strategies within its various 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, and golf courses in order to reduce SunCor’s outstanding debt. SunCor currently plans to retain selected Arizona assets, including land parcels and commercial assets associated with SunCor’s Hayden Ferry Lakeside project in Tempe, Arizona, and approximately 2,000 acres of commercial land associated with its Palm Valley project located west of Phoenix, Arizona. SunCor’s book value of the retained assets will be approximately $70 million.

     Management plans to dispose of the assets in 2009. As a result of this decision, we recorded pretax impairment charges in the first quarter of $202 million, or $123 million after taxes on a Pinnacle West consolidated basis. SunCor also recorded in the first quarter approximately $8 million of pretax severance and other charges relating to these actions. SunCor expects to reclassify most of the affected properties to discontinued operations beginning in the second quarter of 2009, as marketing of the assets commences and other criteria are met. Pinnacle West does not expect that any of the impairment charges will result in future cash expenditures, other than immaterial disposition costs.

     The SunCor Secured Revolver was recently extended for a twelve-month period to January 2010 and requires SunCor to reduce its outstanding borrowings by specified amounts over the term of the facility. As of March 31, 2009, approximately $108 million of borrowings were outstanding under the SunCor Secured Revolver and approximately $67 million of debt was outstanding under other SunCor credit facilities. SunCor intends to apply the proceeds of the asset sales described above to the accelerated repayment of the SunCor Secured Revolver and SunCor’s other outstanding debt, including several project loans totaling approximately $24 million which recently matured. The impairment charges discussed above and the maturity and non-payment of the project loans resulted in violations of certain covenants contained in the SunCor Secured Revolver and SunCor’s other credit facilities. If SunCor is unable to obtain waivers or similar relief from its lenders, which it is currently seeking, SunCor could be required to immediately repay its outstanding indebtedness under the SunCor Secured Revolver and its other credit facilities. Such debt acceleration would have a material adverse impact on SunCor’s business and its financial position. 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. As a result, Pinnacle West does not believe that SunCor’s inability to obtain waivers or similar relief from SunCor’s lenders would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

     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 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,

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these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At March 31, 2009, the ratio was approximately 54% for Pinnacle West and 50% for APS. The provisions regarding interest coverage require minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.4 times under APS’ bank financing agreements as of March 31, 2009. 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 1, 2009 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 collateral related to certain derivative instruments, natural gas transportation, fuel supply, and other energy-related contracts.

	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

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(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

     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.

     APS is exposed to losses under the Palo Verde sale leaseback agreements 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 assume the debt associated with the transactions, make specified payments to the equity participants, 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, 2009, APS would have been required to assume approximately $174 million of debt and pay the equity participants approximately $162 million.

     SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected on our Condensed Consolidated Balance Sheets related to these arrangements were approximately $29 million at March 31, 2009 and December 31, 2008.

     Guarantees and Letters of Credit

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

     Our parental guarantees for APS relate to commodity energy products. As required by Arizona law, Pinnacle West has also obtained a $10 million bond on behalf of APS in connection with the interim base rate surcharge approved by the ACC in December 2008. In addition, Pinnacle West has obtained approximately $8 million of surety bonds related to APS operations, of which approximately $7 million relates to self-insured workers’ compensation. Our credit support instruments enable APSES to offer energy-related products and services. 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, 2009, 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 have not changed materially from the amounts disclosed in Part II, Item 7 of the 2008 Form 10-K, with the exception of our long-term and short-term debt payments. See Note 4 for a discussion of APS’ recent long-term debt issuance and 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. Our most critical accounting policies include the impacts of regulatory accounting, accounting for our pension and other postretirement benefits, derivative accounting, fair value measurements and real estate investment impairments. There have been no changes to our critical accounting policies since our 2008 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2008 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted for our non-financial assets on January 1, 2009. This guidance was adopted for our financial assets on January 1, 2008.

     See Note 10 for a discussion of SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment to SFAS No. 133,” which we adopted January 1, 2009.

     We adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51,” on January 1, 2009. This guidance provides accounting and reporting standards for noncontrolling interests in a consolidated subsidiary and clarifies that noncontrolling interests should be reported as equity on the consolidated financial statements. As a result of adopting this guidance, we have disclosed on the face of our financial statements the portion of equity and net income attributable to the noncontrolling interests in consolidated subsidiaries. Additionally, we reclassified $47 million of noncontrolling interests from Other Deferred Credits to Equity on the December 31, 2008 balance sheet. Prior year’s net income attributable to noncontrolling interests was not material to our income statement and was not reclassified. The adoption of this guidance modified our financial statements presentation, but did not have an impact on our financial statement results.

     In December 2008, the FASB issued FASB Staff Position No. FAS  132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This guidance requires enhanced employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The guidance is effective for us on December 31, 2009. We do not expect it to have a material impact on our financial statements.

     In April 2009, the FASB issued various Staff Positions relating to fair value measurements and impairments. This guidance includes: FASB Staff Position No. FAS  157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”; FASB Staff Position Nos.  FAS 115-2 and FAS 124-2, “Recognition and

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Presentation of Other-Than-Temporary Impairments”; and FASB Staff Position No. FAS  107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” These Staff Positions were effective for us on April 1, 2009. We do not expect them to have a material impact on our financial statements.

     Effective January 1, 2009, we adopted FASB Staff Position No. EITF  03-6-1 (FSP EITF 03-6-1), “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” FSP EITF 03-6-1 requires companies to treat unvested share-based payment awards that have nonforfeitable rights to dividends or dividend equivalents as participating securities when computing earnings per share, pursuant to the two-class method described in SFAS No. 128, “Earnings Per Share.” Our awards do not have nonforfeitable rights to dividends or dividend equivalents and therefore the adoption of this FSP did not have any impact on our financial statements.

PINNACLE WEST CONSOLIDATED — FACTORS AFFECTING
OUR FINANCIAL OUTLOOK

     General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. For the years 2006 through 2008, retail electric revenues comprised approximately 91% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer growth, variations in weather from period to period, customer mix, average usage per customer, electricity rates and tariffs and the recovery of PSA deferrals. 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 economic generation or other energy resources and wholesale market conditions, including demand and prices.

     Rate Proceedings Our cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed below under “Pinnacle West Consolidated - Liquidity and Capital Resources,” are substantial because of environmental compliance and controls, system reliability, and continuing, though slowed, customer growth in APS’ service territory. APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. On March 24, 2008, APS filed a rate case with the ACC, which it updated on June 2, 2008, requesting, among other things, an increase in retail rates to help defray rising infrastructure costs, approval of an impact fee and approval of new conservation rates. On January 30, 2009, APS and the other parties to the rate case began settlement discussions, and on May 4, 2009 they filed a proposed settlement term sheet with the ACC. See Note 5 for details regarding this rate case, including the ACC’s approval of an interim base rate surcharge pending the outcome of the case and a discussion of the proposed settlement term sheet and related timeline.

     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, since April 1, 2005, PSA deferrals and the amortization thereof. See Note 5 for information regarding the PSA. APS’ recovery of PSA deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.

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     Customer and Sales Growth The customer and sales growth referred to in this paragraph apply to Native Load customers and sales to them. Customer growth in APS’ service territory for the three-month period ended March 31, 2009 was 0.8% compared with the prior-year period. Customer growth averaged 3% a year for the three years 2006 through 2008. We currently expect customer growth to average about 1% per year for 2009 through 2011 due to factors reflecting the economic conditions both nationally and in Arizona. For the three years 2006 through 2008, APS’ actual retail electricity sales in kilowatt-hours grew at an average annual rate of 2.9%; adjusted to exclude the effects of weather variations, such retail sales growth averaged 2.9% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 1% on average per year during 2009 through 2011, excluding the effects of weather variations. We currently expect our retail sales growth in 2009 to be below average because of potential effects on customer usage from the economic conditions mentioned above and retail rate increases (see Note 5).

     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 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 retail sales growth, 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.

     Wholesale Market Our marketing and trading activities focus primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. Our marketing and trading activities include, subject to specified parameters, marketing, hedging and trading in electricity and fuels. See “Formula Transmission Tariff” in Note 5 for information regarding APS’ recent approval by the FERC to implement a formula rate.

Other Factors Affecting Financial Results

     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 and other factors. APS recently identified certain operations and maintenance expense reductions for 2009. See “2008 General Retail Rate Case — Summary of APS Request and Interim Rate Surcharge” in Note 5.

     Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditures” above for information regarding planned additions to our facilities.

     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 7.8% of the assessed value for 2008 and 8.3% of the assessed value for 2007. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities) and as we

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improve our existing facilities. See “Capital Expenditures” above for information regarding planned additions to our facilities.

     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.

     Climate Change Recent concern over climate change could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades. The timing and type of compliance measures and related costs are impacted by current and future regulatory and legislative actions, which we are closely monitoring. See “Climate Change” in Part II, Item 5 for more information regarding climate change initiatives.

     Retail Competition Although some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail electric service providers providing unbundled energy or other utility services to APS’ customers. We cannot predict when, and the extent to which, additional electric service providers will re-enter APS’ service territory.

     Subsidiaries SunCor’s net loss was approximately $26 million in 2008. SunCor’s net loss in 2008 included a $53 million (pre-tax) real estate impairment charge. In addition, see Note 21 for further discussion of impairment charges in the first quarter of 2009. These results reflect conditions in the real estate and credit markets. See “Liquidity and Capital Resources — Other Subsidiaries — SunCor” and Note 4 for a discussion of SunCor’s long-term debt, liquidity, and capital requirements.

     The historical results of SunCor, APSES and El Dorado are not indicative of future performance.

     General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” below and “Risk Factors” in Item 1A of the 2008 Form 10-K for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.

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 energy risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading 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 tables show the net pretax changes in mark-to-market value of our derivative positions for the three months ended March 31, 2009 and 2008 (dollars in millions):

	Three Months Ended
	March 31,
	2009			2008
Mark-to-market of net positions at beginning of period	$	(282	)	$	40
Recognized in earnings:
Change in mark-to-market gains (losses) for future period deliveries		(6	)		13
Mark-to-market losses realized including ineffectiveness during the period		2			2
Decrease (increase) in regulatory asset		(40	)		98
Recognized in OCI:
Change in mark-to-market gains (losses) for future period deliveries (a)		(139	)		119
Mark-to-market (gains) losses realized during the period		25			(2	)
Change in valuation techniques		—			—
Mark-to-market of net positions at end of period	$	(440	)	$	270

(a) The changes are primarily due to changes in forward natural gas prices.

     The table below shows the net fair value of maturities of our derivative contracts (dollars in millions) at March 31, 2009 by yearly maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2008 Form 10-K and Note 20 for more discussion of our valuation methods.

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																			Total
Source of Fair Value	2009			2010			2011			2012			2013			Years thereafter			Fair Value
Level 1 — Quoted prices in active markets	$	(72	)	$	(12	)	$	—		$	—		$	—		$	—		$	(84	)
Level 2 — Significant other observable inputs		(165	)		(102	)		(60	)		(6	)		—			—			(333	)
Level 3 — Significant unobservable inputs		(8	)		—			(2	)		3			(4	)		(12	)		(23	)
Total by maturity	$	(245	)	$	(114	)	$	(62	)	$	(3	)	$	(4	)	$	(12	)	$	(440	)

     The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at March 31, 2009 and December 31, 2008 (dollars in millions):

	March 31, 2009					December 31, 2008
	Gain (Loss)					Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings
Electricity	$	2	$	(2	)	$	2	$	(2	)
Natural gas		2		(2	)		3		(3	)
Regulatory asset (liability) or OCI (a)
Electricity		14		(14	)		20		(20	)
Natural gas		50		(50	)		64		(64	)
Total	$	68	$	(68	)	$	89	$	(89	)

(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 1, “Derivative Accounting,” in Item 8 of our 2008 Form 10-K 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, 2009 compared with three-month period ended March 31, 2008

     APS’ net loss for the three months ended March 31, 2009 was $15 million, compared with a net loss of $6 million for the comparable prior-year period. The major factors that increased (decreased) the net loss for the three-month comparison is summarized in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Interim retail rate increase effective January 1, 2009	$	13		$	8
Transmission rate increases which became effective in 2008 (including related retail rates)		6			4
Lower mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals		(19	)		(12	)
Effects of milder weather on retail sales		(13	)		(8	)
Higher depreciation and amortization primarily due to increased utility plant in service		(4	)		(2	)
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances		(5	)		(3	)
Other miscellaneous items, net		1			4
Increase in net loss	$	(21	)	$	(9	)

Regulated Electricity Segment Revenues

     Electric operating revenues were $23 million lower for the three months ended March 31, 2009 compared with the prior-year period primarily because of:

• a $22 million decrease in retail revenues due to the effects of weather;

• a $22 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 5);

• a $7 million decrease in retail revenues primarily related to lower average usage per customer, excluding weather effects;

• a $19 million increase in retail revenues due to an interim rate increase effective January 2009 and transmission rate increases in 2008 (including related retail rates);

• a $16 million increase in renewable energy surcharges, which had no earnings effect because of amortization of the same amount recorded as operations and maintenance expense; and

• a $7 million net decrease due to miscellaneous factors.

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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, 2009 and 2008 (dollars in millions):

	Three Months Ended
	March 31,
	2009			2008
Net cash flow provided by (used for) operating activities	$	(43	)	$	266
Net cash flow used for investing activities		(178	)		(240	)
Net cash flow provided by (used for) financing activities		168			(70	)

     The increase of approximately $309 million in net cash provided by operating activities is primarily due to increased collateral and margin cash provided as a result of changes in commodity prices.

     The decrease of approximately $62 million in net cash used for investing activities is primarily due to lower levels of capital expenditures (see table and discussion below).

     The increase of approximately $238 million in net cash provided by financing activities is primarily due to APS’ issuance of $500 million of unsecured senior notes. A portion of these proceeds were used to repay short-term borrowings.

Contractual Obligations

     APS’ future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2008 Form 10-K, with the exception of long-term and short-term debt payments. See Note 4 for a discussion of APS’ recent long-term debt issuance and a list of payments due on total long-term debt and capitalized lease requirements.

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 or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “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 results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the 2008 Form 10-K, these factors include, but are not limited to:

• state and federal regulatory and legislative decisions and actions, including the outcome or timing of the pending rate case of APS;

• increases in our capital expenditures and operating costs and our ability to achieve timely and adequate rate recovery of these increased costs;

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• our ability to reduce capital expenditures and other costs while maintaining reliability and customer service levels, and unexpected developments that would limit us from achieving all or some of our planned capital expenditure reductions;

• volatile fuel and purchased power costs, including fluctuations in market prices for natural gas, coal, uranium and other fuels used in our generating facilities, availability of supplies of such commodities, and our ability to recover the costs of such commodities;

• the outcome and resulting costs of regulatory, legislative and judicial proceedings, both current and future, including those related to environmental matters and climate change;

• the availability of sufficient water supplies to operate our generation facilities, including as the result of drought conditions;

• the potential for additional restructuring of the electric industry, including decisions impacting wholesale competition and the introduction of retail electric competition in Arizona;

• regional, national and international economic and market conditions, including the strength of the real estate, credit and financial markets;

• the potential adverse impact of current economic conditions on our results of operations;

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

• changes in the market price of our common stock;

• restrictions on dividends or other burdensome provisions in new or existing credit agreements;

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

• current credit ratings remaining in effect for any given period of time;

• the performance of the stock market and the changing interest rate environment, which affect the value of our nuclear decommissioning trust, pension, and other postretirement benefit plan assets, the amount of required contributions to Pinnacle West’s pension plan and contributions to APS’ nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits and our ability to recover such costs;

• volatile market liquidity, any deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);

• changes in accounting principles generally accepted in the United States of America, the interpretation of those principles and the impact of the adoption of new accounting standards;

• customer growth and energy usage;

• weather variations affecting local and regional customer energy usage;

• power plant performance and outages;

• transmission outages and constraints;

• the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;

• risks inherent in the operation of nuclear facilities, such as environmental, regulatory, health and financial risks, risk of terrorist attack, planned and unplanned outages, and unfunded decommissioning costs;

• the ability of our power plant participants to meet contractual or other obligations;

• technological developments in the electric industry;

• the results of litigation and other proceedings resulting from the California and Pacific Northwest energy situations;

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• the performance of Pinnacle West’s subsidiaries and any resulting effects on its cash flow;

• the strength of the real estate and credit markets and economic and other conditions affecting the real estate and credit markets in SunCor’s market areas, which include Arizona, Idaho, New Mexico and Utah; and

• other uncertainties, all of which are difficult to predict and many of which are beyond the control of Pinnacle West and APS.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     See “Pinnacle West Consolidated — Factors Affecting Our Financial Outlook” 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, 2009. 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, 2009. 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, 2009 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 Note 12 in regard to pending or threatened litigation or other disputes.

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 2008 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of APS and Pinnacle West. The risks described in the 2008 Form 10-K are not the only risks facing APS and Pinnacle West. 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 APS and Pinnacle West.

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

Issuer Purchases of Equity Securities

     The following table contains information about our purchases of our common stock during the first quarter of 2009.

					Total Number
					of Shares
	Total				Purchased as		Maximum Number
	Number		Average		Part of Publicly		of Shares that May
	of Shares		Price		Announced		Yet Be Purchased
	Purchased		Paid per		Plans or		Under the Plans or
Period	(1)		Share		Programs		Programs
January 1 — January 31, 2009		66,138	$	32.32		—		—
February 1 — February 28, 2009		—		—		—		—
March 1 — March 31, 2009		—		—		—		—
Total		66,138	$	32.32		—		—

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

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 the Company and its subsidiaries.

Regulatory Matters

     See Note 5 for a discussion of regulatory developments.

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NRC Inspection

     As more fully described under “Business of Arizona Public Service Company — Nuclear Generating Facility — NRC Inspection” in Item 1 of the 2008 Form 10-K, Palo Verde has been subject to a heightened level of oversight by the NRC. On March 24, 2009, the NRC informed APS that it is removing Palo Verde Unit 3 from the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), removing Units 1 and 2 from the “one degraded cornerstone” column (“Column 3”), and returning all three units of the plant to routine inspection and oversight by the NRC. This notification follows the NRC’s completion of its inspections of the corrective actions taken by Palo Verde to address performance deficiencies that caused the NRC to place Unit 3 into Column 4 and Units 1 and 2 into Column 3. The NRC has closed the confirmatory action letter that outlined the performance deficiencies and associated corrective actions.

Environmental Matters

     Superfund

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

     EPA Environmental Regulation

     Mercury On March 15, 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to control mercury emissions from coal-fired power plants. This rule establishes performance standards limiting mercury emissions from coal-fired power plants and establishes a two phased market-based emissions trading program. Under the trading program, the EPA has assigned each state a mercury emissions “budget” and each state must submit to the EPA a plan detailing how it will meet its “budget.”

     In November 2006, ADEQ submitted a SIP to the EPA to implement the CAMR. ADEQ’s SIP generally incorporates the EPA’s model cap-and-trade program, but it includes additional requirements, including the requirement to meet a 90% mercury removal control level or 0.0087 lbs/GWh, whichever is greater; the requirement to obtain mercury allowances at a 2:1 ratio for any emissions that fall below the specified control level; and the requirement, beginning in 2013, to consider clean coal technologies as part of permitting any new generation.

     On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR and the EPA rule that allowed for the creation of the CAMR, and on March 14, 2008, the court issued the mandate to vacate these rules. On May 20, 2008, the D.C. Circuit denied the EPA’s request to reconsider its decision. On October 17, 2008, the U.S. Solicitor General, on behalf of the EPA, petitioned the Supreme Court for a writ of certiorari to review the judgment of the D.C. Circuit Court of Appeals’ vacatur of the CAMR. In filing the petition, the U.S. contended, among other things, that the Court of Appeals’ decision “effectively divests EPA of the discretion that Congress conferred on the agency to consider alternative regulatory approaches to combating air pollution from power plants.” On February 23, 2009, the Supreme Court denied EPA’s petition for certiorari. As a result, the law in effect prior to the adoption of the CAMR becomes the applicable law, and requires the EPA to develop an emission limit for mercury that represents the maximum achievable control technology. It is expected to take the EPA several years to establish its standard, followed by a period of several years during which existing plants would implement any controls needed to comply with such standard.

     The court’s ruling also invalidates CAMR-based portions of ADEQ’s mercury rule (the trading provisions of the rule), although the state-only emission limits remain in effect. On July 25, 2008, the

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Arizona Utilities Group (comprised of APS, Arizona Electric Power Cooperative, Salt River Project, Tucson Electric Power Company, and Tri-State Generation and Transmission Association) filed with ADEQ a Petition for Reconsideration and Repeal of the state mercury rule. The petition asserts that ADEQ does not have statutory authority to administer and enforce the state mercury rule, in light of the vacatur of the CAMR and the requirement that EPA promulgate a Maximum Achievable Control Technology (“MACT”) standard. ADEQ granted the petition in part and agreed to begin rulemaking efforts to repeal those portions of ADEQ’s mercury rule that are no longer valid in light of the vacatur of the federal CAMR. However, ADEQ denied the petition with respect to certain compliance deadlines, meaning that APS and others would have to comply with the 90% mercury removal or 0.0087 lbs/GWh levels discussed above by 2013. However, on February 17, 2009, APS signed a consent order with ADEQ under which APS will strive to achieve 50% mercury removal commencing in 2011 and will fully comply with the ADEQ mercury rule by 2016, rather than by 2013 as the rule currently prescribes.

     While we continue to monitor this matter, we cannot predict the scope, timing or impact of any alternate rules that may be enacted to address mercury emissions.

     We have installed, and continue to install, certain of the equipment necessary to meet the anticipated mercury standards. However, due to the U.S. Court of Appeals decision described above, we will monitor the type and timing of any necessary equipment installation. The estimated costs expected to be incurred over the next three years for such equipment are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Capital Expenditures” in Part I, Item 2).

     Four Corners FIP On April 30, 2007, the EPA adopted a source specific FIP to set air quality standards at Four Corners. The FIP essentially federalizes the requirements contained in the New Mexico State Implementation Plan, which Four Corners has historically followed. The FIP also includes a requirement to maintain and enhance dust suppression methods. On July 2, 2007, APS filed a petition for review in the United States District Court of Appeals for the Tenth Circuit seeking revisions to the FIP to clarify certain requirements and allow operational flexibility. The Sierra Club intervened in this action. On July 6, 2007, the Sierra Club and other parties filed a petition for review with the same court challenging the FIP’s compliance with the Clean Air Act and we have intervened in their action. In our lawsuit, we challenge two key provisions of the FIP: a 20% opacity limit on certain fugitive dust emissions, and a 20% stack opacity limit on Units 4 and 5. During 2008, the EPA voluntarily moved to vacate the fugitive dust provisions of the FIP, and on April 14, 2009, the court granted EPA’s motion. The court also rejected the Sierra Club’s challenges to the FIP and ruled in favor of the 20% stack opacity limit. We do not believe that compliance with this limit will have a material adverse impact on our financial position, results of operations or cash flows.

     Section 114 Request On April 6, 2009, APS received a request from the EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. We are in the process of responding to this request and are currently unable to predict the timing or content of EPA’s response or any resulting actions.

     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, but such bills have not yet received sufficient Congressional approval to become law; however, there is growing consensus that some form of regulation or legislation is likely to occur in the near future at the federal level with respect

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to greenhouse gas emissions. The economic and operational impact of any such legislation on the Company 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 will be allocated or auctioned; the cost to reduce emissions or buy them in the marketplace; and the availability of offsets and mitigating factors to moderate the costs of compliance.

     In 2007, the United States Supreme Court ruled 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 EPA was charged with determining whether greenhouse gas emissions “endanger the public health and welfare of current and future generations.” On April 17, 2009, the EPA issued a proposed finding that such emissions do endanger the public. While the Supreme Court decision applies only to emissions from new motor vehicles, the EPA’s determination will likely impact other Clean Air Act programs as well, and could potentially result in new regulatory requirements for our power plants. The EPA’s proposal is subject to public review and comment for sixty days from April 24, 2009, the date it was published in the Federal Register. In addition, the EPA has drafted a proposed greenhouse gas reporting rule, which is currently available for public review and comment. This proposed rule, expected to be finalized by mid-2009, is in anticipation of future regulation of greenhouse gases under the Clean Air Act and applies to direct greenhouse gas emissions from facilities such as our power 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, AB 32 is a California statute mandating the reduction of greenhouse gas emissions to 1990 levels by 2020. In December 2008, the California Air Resources Board issued a final scoping plan, which is intended to form the basis of rules required under AB 32. On January 1, 2012, the regulations based on the 2009 scoping plan will become effective. We are monitoring this and other state legislative developments to evaluate whether, and the extent to which, any resulting statutes or rules in California or other states may affect our business, including our sales into the impacted states or the ability of our out-of-state power plant participants to meet their obligations.

     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, curtailing certain operations, 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 (the “Initiative”), to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. Montana, Quebec and Ontario have also joined the Initiative. In August 2007, the Initiative participants set a goal of reducing greenhouse gas emissions 15% below 2005 levels by 2020. Since May 2008, several draft documents have been issued for public comment. We are reviewing the recommendations and requirements in these documents, which currently provide only a general framework for the proposed program. Over the next year, the Initiative participants intend to develop detailed proposed rules to more fully establish and define the program. Since details are not yet available, such as the number of allowances each source may receive, we are unable to quantify the potential financial and operational impacts on our business should Arizona adopt and implement rules

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based on the Initiative’s proposed rules. In addition, we believe that in Arizona, the implementation of any such program and rules would require legislative action. As a result, while we continue to monitor the progress and impact of the Initiative, at the present time we cannot predict what detailed form it will ultimately take, whether it will be implemented or, if it is implemented, what impact it will have 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 related to 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. (See “Portfolio Resources — Alternative Generation Sources” in Part I, Item 1 of the 2008 Form 10-K.) In January 2009, we submitted a Resource Plan Report to the ACC proposing our future plans for additional diverse resources. See “Portfolio Resources — Resource Plan” in Part I, Item 1 of the 2008 Form 10-K for information regarding the Resource Plan Report, which was designed, in part, to increase Arizona’s commitment to non-fossil resources.

     In addition, we are currently developing a Climate Management Report 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. We expect to complete the report in the second quarter of 2009.

     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. 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. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.

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Item 6. EXHIBITS

     (a) Exhibits

Exhibit No.	Registrant(s)	Description
10.1	Pinnacle West APS	Career Recognition Award Agreement dated April 14, 2009 between Pinnacle West Capital Corporation and William J. Post
10.2	APS	Description of 2009 Palo Verde Specific Compensation Opportunity for Randall K. Edington
10.3	Pinnacle West APS	Form of Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of James R. Hatfield, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of James R. Hatfield, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 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
99.1	Pinnacle West APS	Proposed Settlement Framework Term Sheet filed with the Arizona Corporation Commission on May 4, 2009

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     In addition, the Company 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:

			Previously Filed as	Date
Exhibit 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
10.4	Pinnacle West APS	Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	10.6 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-7-08

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 5, 2009	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 5, 2009	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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EX-10.1

Exhibit 10.1

CAREER RECOGNITION AWARD AGREEMENT

     THIS CAREER RECOGNITION AWARD AGREEMENT (the “Agreement”), effective as of March 17, 2009, is entered into by and between William J. Post (the “Executive”) and Pinnacle West Capital Corporation (the “Company”).

     1. PURPOSE. Company recognizes Executive’s long and distinguished career with Company and to demonstrate its appreciation has decided to grant Executive a Career Recognition Award of $1,000,000, as described in this Agreement.

     2. SPECIAL CREDIT. Company agrees to credit the full Award of $1,000,000 to a record keeping account (the “Career Recognition Account”) on the date the Human Resources Committee of Company’s Board of Directors (the “Committee”) approves Executive’s Career Recognition Award. Interest shall be credited to the Career Recognition Account in accordance with Section 4, below. The Career Recognition Account will be charged (or debited) with any amounts distributed to Executive or those claiming through him pursuant to this Agreement. The Career Recognition Account is a record keeping account only and Executive shall not have any claim to any particular assets of Company.

     3. VESTING. Executive shall have a fully vested interest in amounts credited to his Career Recognition Account upon the earlier of his retirement from his position as Company’s Chief Executive Officer on April 30, 2009 or his death.

     4. INTEREST. Interest will be credited on the unpaid balance of Executive’s Career Recognition Account from May 1, 2009, until the full amount of the Career Recognition Account has been paid to Executive. The applicable interest rate for any calendar year will equal the “Preferred Rate” established pursuant to Section 1.25 of the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (the “Deferred Compensation Plan”). If the Deferred Compensation Plan is discontinued or is amended to remove all references to a Preferred Rate, the applicable interest rate will be determined by Company prior to the beginning of the next calendar year and shall remain in effect until subsequently changed by Company. Interest will not be compounded.

     5. PAYMENT. Executive’s Career Recognition Account will be paid to him in 10 annual installments of $100,000 each plus accrued interest as described below. The first installment payment will be made on December 1, 2009 and will include interest accrued from May 1, 2009. Subsequent installments will be made on the first business day of December in each of the next nine years and each installment will include interest accrued from the date of the previous payment.

     6. DEATH. If Executive dies before receiving all of the payments to which he is entitled, the remaining payments will be made to Executive’s designated Beneficiary. The payments will be made to the Beneficiary on the dates specified pursuant to Section 5. The payments will not be accelerated.

     7. DESIGNATION OF BENEFICIARY. Executive shall have the right to designate, on forms supplied by and delivered to Company, a beneficiary or beneficiaries (the

“Beneficiary” or “Beneficiaries”) to receive his benefits in the event of Executive’s death. Executive may change his Beneficiary designation from time to time in the manner described above. Upon receipt of such designation by Company, such designation or change of designation shall become effective as of the date of the notice, whether or not Executive is living at the time the notice is received. There shall be no liability on the part of Company with respect to any payment authorized by Company in accordance with the most recent valid Beneficiary designation of Executive in its possession before receipt of a more recent and valid Beneficiary designation. If no designated Beneficiary is living when benefits become payable, or if there is no designated Beneficiary, the Beneficiary shall be Executive’s spouse; or if no spouse is then living, Executive’s issue, including any legally adopted child or children, in equal shares by right of representation; or if no such designated Beneficiary and no such spouse or issue is living upon the death of Executive, or if all such persons die prior to the full distribution of Executive’s benefits, then the Beneficiary shall be the estate of Executive.

     8. WITHHOLDING. Company is authorized to withhold from any payments called for by this Agreement all withholding and other taxes due to the federal and any state governments and to take such other action as Company may deem necessary or advisable to enable Company and Executive to satisfy obligations for the payment of withholding taxes and other tax liabilities relating to any payment. Executive acknowledges that the full amount of the Career Recognition Award ($1,000,000) is subject to FICA tax on April 30, 2009, the date of his retirement. Unless Executive provides Company with the full amount of his FICA tax obligation, Company shall withhold that amount from Executive’s other earnings.

     9. UNDERPAYMENT OR OVERPAYMENT OF BENEFITS. In the event that through mistake or computational error benefits are underpaid or overpaid, there shall be no liability for any more than the correct amount of benefits under this Agreement. Overpayments may be deducted from future payments under this Agreement and underpayments may be added to future payments under the Agreement. In lieu of receiving reduced benefits under this Agreement, Executive or the Beneficiary may elect to make a lump sum repayment of any overpayment.

     10. BAN ON ACCELERATION OR DEFERRAL. Under no circumstances may the time or schedule of any payment made under this Agreement be accelerated or subject to a further deferral except as otherwise permitted or required pursuant to regulations and other guidance issued pursuant to Section 409A of the Code.

     11. MISCELLANEOUS PAYMENT PROVISIONS. If a payment is not made due to a dispute, payments may be delayed in accordance with regulations issued pursuant to Section 409A.

     12. NO ELECTIONS. Executive does not have any right to make any election regarding the time or form of payment due under this Agreement.

     13. COMPLIANCE WITH SECTION 409A. This Agreement shall be administered in compliance with Section 409A and each provision of the Agreement shall be interpreted, to the extent possible, to comply with Section 409A.

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     14. INALIENABILITY OF BENEFITS.

          (a) GENERAL PROHIBITION. Neither Executive, the Beneficiary, nor creditors of Executive or the Beneficiary, shall have any right to assign, pledge, hypothecate, anticipate or in any way create a lien upon Executive’s or Beneficiary’s interest created under this Agreement. All payments to be made to Executive or his Beneficiaries shall be made only upon their personal receipt or endorsement, and no interest under this Agreement shall be subject to assignment or transfer or otherwise be alienable, either by voluntary or involuntary act or by operation of law or equity, or subject to attachment, execution, garnishment, sequestration, levy or other seizure under any legal, equitable or other process, or be liable in any way for the debts or defaults of Executive or his Beneficiaries.

          (b) PERMITTED ARRANGEMENTS. This Section shall not preclude arrangements for the withholding of taxes from benefit payments, arrangements for the recovery of benefit overpayments, or arrangements for direct deposit of benefit payments to an account in a bank, savings and loan association or credit union (provided that such arrangement is not part of an arrangement constituting an assignment or alienation).

     15. CLAIMS. Executive and Executive’s Beneficiary need not file any claim or application to receive the benefits provided by this Agreement. If Executive, any Beneficiary, or any authorized representative acting on behalf of Executive or the Beneficiary (the “Claimant”) does not receive a benefit which he or she believes he or she is entitled to, the Claimant may file a written claim for benefits. If the Claimant disagrees with the manner in which the claim is resolved, the Claimant also may appeal the claim determination. Any claim and any appeal shall be filed and determined in accordance with the procedures set forth in the Pinnacle West Capital Corporation Savings Plan, as it may be amended or replaced from time to time.

     16. DISTRIBUTIONS TO MINORS. Distributions to minors or persons under legal disability may be made by Company in the discretion of its officers, either (a) directly to said persons, (b) to the guardian or custodian of said persons, or (c) by expending the same for the education and maintenance of said persons. Except as to (c), Company shall not be required to see to the application of any distributions so made.

     17. BINDING NATURE OF AGREEMENT. This Agreement shall be binding upon the heirs, executors, administrators, successors and assigns of any and all interested parties, present and future.

     18. NATURE OF PAYMENTS. Executive and his Beneficiary or Beneficiaries shall, for the purpose of this Agreement, be treated as general unsecured creditors of Company. Nothing in this Agreement or any action taken pursuant to this Agreement shall create or be construed to create a fiduciary relationship between Company and Executive, his designated Beneficiary or Beneficiaries, or any other person.

     19. UNFUNDED PLAN. This Agreement is intended to create an unfunded plan maintained for the purpose of providing deferred compensation to Executive, who is a member of a select group of management or highly compensated employees within the meaning of Title I of the Employment Retirement Income Security Act of 1974.

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     20. VALIDITY. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

     21. AMENDMENT AND TERMINATION. Any amendment, modification, change, or termination of this Agreement must be done so in writing and signed by both parties. Any amendment to this Agreement that violates the provisions of Section 409A of the Internal Revenue Code of 1986 (the “Code”) or any other applicable law shall be void.

     Section 409A imposes requirements on non-qualified deferred compensation plans. If such requirements are not satisfied, Executive’s tax liability could be accelerated and substantially increased. If any provision of this Agreement could require Executive to pay income tax (but not FICA tax) on amounts due pursuant to this Agreement before Executive’s receipt of such amounts, or subject Executive to any additional taxes or penalties, or impose any other material adverse tax consequences on Executive or Company which may be avoided by modifying the terms of the Agreement, Company may amend the Agreement, either prospectively or retroactively, for the purpose of avoiding such adverse tax consequences. No such modification shall deprive Executive of the economic benefits due under this Agreement. In addition, except as otherwise determined by Company in compliance with Section 409A, the termination of this Agreement will not result in an immediate payment to Executive. Rather, payments shall only be made in accordance with the provisions of Section 5.

     22. GOVERNING LAW. The validity, interpretation, construction, and performance of this Agreement shall be governed by the laws of the State of Arizona, except as otherwise preempted by the Employee Retirement Income Security Act of 1974.

     23. COUNTERPARTS. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same instrument.

     24. ENTIRE AGREEMENT. This Agreement sets forth the entire agreement between Executive and Company concerning the subject matter discussed in this Agreement and supersedes all prior agreements, promises, covenants, arrangements, communications, and representations or warranties, whether written or oral, by any officer, employee, or representative of Company. Any prior agreements or understandings with respect to the subject matter set forth in this Agreement are hereby terminated and canceled.

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     IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the 14th day of April, 2009.

PINNACLE WEST CAPITAL CORPORATION
By:	/s/ Roy A. Herberger, Jr.
	Roy A. Herberger, Jr.
	Chairman, Human Resources Committee of the Board of Directors
EXECUTIVE
/s/ William J. Post
William J. Post

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EX-10.2

Exhibit 10.2

Description of 2009 Palo Verde Specific Compensation Opportunity for
Randall K. Edington

Consistent with the letter agreement between the Company and Mr. Edington, dated December 20, 2006, the Company adopted the 2009 Palo Verde Specific Compensation Opportunity. Mr. Edington has the opportunity to receive up to $125,000 upon the achievement of performance measures tied to Palo Verde performance improvements as documented by INPO and Nuclear Regulatory Commission findings, and operational performance.

EX-10.3

Exhibit 10.3

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2009 Performance Share Award

PERFORMANCE SHARE AGREEMENT
UNDER THE
PINNACLE WEST CAPITAL CORPORATION
2007 LONG-TERM INCENTIVE PLAN

     THIS AWARD AGREEMENT is made and entered into as of                                         2009 (the “Date of Grant”), by and between Pinnacle West Capital Corporation (the “Company”), and                                         (“Employee”).

BACKGROUND

A.	The Board of Directors of the Company has adopted, and the Company’s shareholders have approved, the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan (the “Plan”), pursuant to which Performance Share Awards may be granted to employees of the Company and its Subsidiaries and certain other individuals.
B.	The Company desires to grant to Employee a Performance Share Award under the terms of the Plan.
C.	Pursuant to the Plan, the Company and Employee agree as follows:

AGREEMENT

1.	Grant of Award. Pursuant to action of the Committee, which was taken on the Date of Grant, the Company grants to Employee                                         (___) Performance Shares and Dividend Equivalents. The Performance Shares granted under this Section 1 are referred to in this Award Agreement as the “Base Grant.”
2.	Award Subject to Plan. This Performance Share Award is granted under and is expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement.
3.	Performance Period. The Performance Period for this Award begins January 1, 2009 and ends December 31, 2011.
4.	Payment.

(a) Performance Shares Payable In Stock. As soon as practicable in the fiscal year immediately following the end of the Performance Period, the Company will determine (i) the Company’s Earnings Per Share Growth Rate (as defined herein) as compared to the Earnings Per Share Growth Rates of the companies in the S&P 1500 Super Composite Electric Utility Index (the “Growth Index”) over the Performance Period and (ii) the Company’s Average Performance with respect to the Performance Metrics (as defined herein). The Company will then deliver to Employee one (1) share of the Company’s Stock for each then-outstanding Performance Share under this Award Agreement, subject to adjustment pursuant to Section 5 below. The Company anticipates that the Stock payout, if any, related to the Company’s Earnings Per Share Growth Rate will be made on or about April 1, 2012. The Company anticipates that the Stock payout, if any,

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	related to the Performance Metrics will be made on or about November 30, 2012. In no event will the Stock payouts described in this Subsection 5(a) be made later than December 31, 2012.
(b)	Retirement. In the case of Employee’s Retirement (as defined herein) during the Performance Period, Employee shall be deemed to have been employed by the Company through the end of the Performance Period and Employee will receive the Stock and Dividend Equivalents, if any, to which Employee is entitled at the time specified in this Section. For purposes of this Award Agreement, “Retirement” means a termination of employment which constitutes an “Early Retirement” or a “Normal Retirement” under the Pinnacle West Capital Corporation Retirement Plan.
(c)	Dividend Equivalents. In satisfaction of the Dividend Equivalent Award made pursuant to Section 1, at the time of the Company’s delivery of Stock to Employee pursuant to Subsection 4(a) above, the Company also will deliver to Employee a cash payment equal to the amount of dividends, if any, declared on the number of shares of Stock equal to the number of shares of Stock delivered to Employee from the Date of Grant to the date of the payment, plus interest on such amount at the rate of 5% percent, compounded quarterly, as determined pursuant to the Plan.

5. Performance Criteria and Adjustments.

(a) Adjustment of Base Grant for Earnings Per Share Growth Rate. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Earnings Per Share Growth Rate” as compared to the Earnings Per Share Growth Rates of the companies in the Growth Index during the Performance Period, as follows:

If the Company’s Earnings Per Share
Compound Growth Rate Over The
Performance Period As Compared to the	The Number of
Earnings Per Share Growth Rates of the	Performance Shares
Companies in the Growth Index is:	will be:
75th Percentile	.75 X Base Grant
50th Percentile	0.5 X Base Grant
25th Percentile	0.25 X Base Grant
Less than 25th Percentile	None

     If intermediate percentiles are achieved, the number of Performance Shares awarded will be prorated (partial shares will be rounded down to the nearest whole share when applicable). For example, if the Company’s Earnings Per Share Growth Rate during the Performance Period places the Company’s performance in the 60th percentile, then the number of Performance Shares would be increased to 0.60 (0.5 X 60/50) multiplied by the Base Grant. In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection 5(a) greater than .75 times the Base Grant, even if the Company’s Earnings Per Share Growth Rate during the Performance Period places the Company’s performance higher than the 75th percentile.

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(b) Adjustment of Base Grant for Performance Metrics. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Average Performance” with respect to the “Performance Metrics,” as follows:

	The Number of
	Performance Shares will
If the Company’s Average Performance is:	be:
75th Percentile	.75 X Base Grant
50th Percentile	0.5 X Base Grant
25th Percentile	0.25 X Base Grant
Less than 25th Percentile	None

     If intermediate percentiles are achieved, the number of Performance Shares awarded pursuant to this Subsection 5(b) will be prorated (partial shares will be rounded down to the nearest whole share when applicable). For example, if the Company’s Average Performance during the Performance Period places the Company’s performance in the 60th percentile, then the number of Performance Shares would be increased to .60 (0.5 X 60/50) multiplied by the Base Grant. In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection (b) greater than .75 times the Base Grant, even if the Company’s Average Performance during the Performance Period places the Company’s performance higher than the 75th percentile.

6. Definitions.

(a) Earnings Per Share Growth Rate. “Earnings Per Share Growth Rate” for the Performance Period is the compounded annual-growth rate (“CAGR”) of a company’s earnings per share from continuing operations, on a fully diluted basis, during the Performance Period; provided, however, that for purposes of calculating the Company’s Earnings Per Share Growth Rate, SunCor Development Company’s earnings or losses will be disregarded for each fiscal year during the Performance Period. Only those companies that were included in the Growth Index in each of the years of the Performance Period will be considered. The Earnings Per Share Growth Rates of the companies in the Growth Index will be determined using an independent third party data system. If the Growth Index is discontinued, the Committee shall select the most comparable index then in use for the sector comparison. In addition, if the sector comparison is no longer representative of the Company’s industry or business, the Committee shall replace the Growth Index with the most representative index then in use. Once the CAGR of the Company and all relevant companies in the Growth Index have been determined, the member companies will be ranked from greatest to least CAGR. Percentiles will be calculated based on a company’s relative ranking. For example, company 1 out of 26 companies is given a percentile of 96.2% (1.0 — 1/26). Percentiles will be carried out to one (1) decimal place. If the Company is not in the Growth Index, then its percentile will be interpolated between the companies listed in the relative ranking. These calculations will be verified by the Company’s internal auditors.

(b) Performance Metrics. The “Performance Metrics” for the Performance Period are (i) the JD Power Residential Survey for investor-owned utilities in the Western Region; (ii) the System Average Interruption Frequency Index (Major

Page 4 of 8

Events Excluded) (“SAIFI”); (iii) Arizona Public Service Company’s customer to employee improvement ratio; (iv) the OSHA rate (All Incident Injury Rate); (v) nuclear capacity factor; and (vi) coal capacity factor.

(1)	With respect to the Performance Metric described in clause (i) of this Subsection 6(b), the JD Power Residential Survey will provide data on an annual basis reflecting the Company’s percentile ranking, relative to other participating companies.
(2)	With respect to the Performance Metric described in clause (ii) of this Subsection 6(b), the Edison Electric Institute (“EEI”) will provide on an annual basis the quartile rankings (or percentile rankings, if available) associated with the SAIFI result of the participating companies; the Company will determine its SAIFI result for the year in question and determine its quartile ranking (or percentile ranking, if percentile rankings are available) based on the information provided by EEI.
(3)	With respect to the Performance Metric described in clause (iii) of this Subsection 6(b), SNL, an independent third party data system, will provide data on an annual basis regarding the customer and employee counts; the Company will use its customer and employee counts for the year in question and determine its percentile ranking based on the information provided by SNL. Only those companies whose customers and employees were included in the data provided by SNL in each of the years of the Performance Period will be considered.
(4)	With respect to the Performance Metric described in clause (iv) of this Subsection 6(b), EEI will provide data on an annual basis regarding the OSHA rate of the participating companies; the Company will calculate its OSHA rate for the year in question and determine its percentile ranking based on the information provided by EEI.
(5)	With respect to the Performance Metric described in clause (v) of this Subsection 6(b), SNL will provide data on an annual basis regarding the nuclear capacity factors of the participating nuclear plants; the Company will calculate its nuclear capacity factor for the year in question and determine its percentile ranking based on the information provided by SNL. Only those plants that were included in the data provided by SNL in each of the years of the Performance Period will be considered.
(6)	With respect to the Performance Metric described in clause (vi) of this Subsection 6(b), SNL will provide data on an annual basis regarding the coal capacity factors of the participating coal plants; the Company will calculate its coal capacity factor for the year in question and determine its percentile ranking based on the information provided by SNL. Only those plants that were included in the data provided by SNL in each of the years of the Performance Period will be considered.
(7)	The Company’s percentile ranking during the Performance Period for each Performance Metric will be the average of the Company’s percentile ranking for each Performance Metric during each of the three years of the

Page 5 of 8

Performance Period (each, an “Average Performance Metric”); provided, however, that if a Performance Metric for 2011 is not calculable by December 15, 2012, the Performance Metric shall consist of the three most recent years for which such Performance Metric is calculable. The Company’s “Average Performance,” for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b) above will be the average of the Average Performance Metrics. If only quartile, rather than percentile, rankings are available for a particular Performance Metric, the Average Performance Metric for any such Performance Metric shall be expressed as a percentile. For example, if the Performance Metric was in the top quartile for two Performance Periods and in the lowest quartile in the other Performance Period, the average of these quartiles would be 3 (the average of 4, 4, and 1) and the Average Performance Metric would be the 75th percentile (3 /4). The calculations in this Subsection 6(b)(7) will be verified by the Company’s internal auditors.

(8)

If either EEI or SNL discontinues providing the data specified above, the Committee shall select a data source that, in the Committee’s judgment, will provide data most comparable to the data provided by EEI or SNL, as the case may be. If the JD Power Residential Survey for investor-owned utilities in the Western Region (or a successor JD Power survey) is not available during each of the years of the Performance Period, the Performance Metric associated with the JD Power Residential Survey (Subsection 6(b)(1)) will be disregarded and not included in the Company’s Average Performance for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b).

7. Termination of Award. This Award Agreement will terminate and be of no further force or effect on the date that Employee is no longer actively employed by the Company or any of its Subsidiaries, whether due to voluntary or involuntary termination, death, retirement, disability, or otherwise, except as specifically set forth in Section 4. Employee will, however, be entitled to receive any Stock and Dividend Equivalents payable under Section 4 of this Award Agreement if Employee’s employment terminates after the end of the Performance Period but before Employee’s receipt of such Stock and Dividend Equivalents.

8. Section 409A Compliance.

(a)

Purpose of this Provision. Section 409A of the Code imposes a number of requirements on “non-qualified deferred compensation” plans and arrangements. Based on regulations issued by the Internal Revenue Service, the Company has concluded that this Performance Share Award is subject to Section 409A. As a result, unless the Plan and this Award Agreement are administered to comply with the new rules, Employee will be required to pay an additional 20% tax (in addition to regular income taxes) on the compensation provided by this Award Agreement. In addition, under Section 409A additional interest will be payable.

(b)

Compliance with Section 409A. The Company intends to comply with Section 409A by assuring that all amounts to which Employee becomes entitled hereunder are payable at a specified time or pursuant to a fixed schedule within the meaning of Treas. Reg. § 1.409A-3(a)(4). As a result, any payment or

Page 6 of 8

	transfer to Employee shall be made at the time specified in Section 4. The provisions of this Subsection 8(b) apply to all amounts due pursuant to this Award Agreement.
(c)	Miscellaneous Payment Provisions. If a payment is not made due to a dispute in payments, payments can be delayed in accordance with Treas. Reg. § 1.409A-3(g).
(d)	Ban on Acceleration or Deferral. Under no circumstances may the time or schedule of any payment made or benefit provided pursuant to this Award Agreement be accelerated or subject to a further deferral except as otherwise permitted or required pursuant to regulations and other guidance issued pursuant to Section 409A of the Code.
(e)	No Elections. Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement.
(f)	Compliant Operation and Interpretation. The Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of the Award Agreement and the Plan shall be interpreted, to the extent possible, to comply with Section 409A.

9.	Tax Withholding. Any and all payments made pursuant to this Award Agreement shall be subject to applicable tax withholding requirements and employment taxes. Employee must pay, or make arrangements acceptable to the Company for the payment of any and all required federal, state, and local income and payroll tax withholding. Employee may satisfy any such tax withholding obligation by paying the amount in cash or by check. In the alternative, Employee may elect to have the Company withhold shares of Stock having a Fair Market Value on the date of withholding sufficient to cover the minimum statutory withholding obligation. Within 45 days after the Date of Grant, Employee must elect, by providing written notice to the Company, to satisfy any tax withholding obligation by paying the amount in cash or by check or by having the Company withhold shares of Stock having a Fair Market Value on the date of withholding sufficient to cover the minimum statutory withholding obligation. In the absence of a timely election by Employee, Employee’s minimum statutory withholding obligation will be satisfied through the Company’s withholding shares of Stock as set forth above.
10.	Continued Employment. Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company to terminate Employee’s employment or services at any time. In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company.
11.	Voting Rights. Employee is not entitled to voting rights with respect to shares of Stock by virtue of this Award. Upon issuance of Stock in settlement of Employee’s Performance Share Awards, Employee will have voting rights with respect to such shares of Stock.
12.	Non-Transferability. Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except by will or the laws of

Page 7 of 8

	descent and distribution, and any attempted assignment, transfer, mortgage, pledge or encumbrance except as herein authorized, will be void and of no effect.
13.	Definitions: Copy of Plan and Plan Prospectus. To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan. Employee will receive a copy of the Plan and the related Plan Prospectus. In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.
14.	Amendment. Except as otherwise provided in the Plan, this Award Agreement may be amended only by a written agreement executed by the Company and Employee.
15.	Choice of Law. This Award Agreement will be governed by the laws of the State of Arizona, excluding any conflicts or choice of law rule or principle that might otherwise refer construction or interpretation of this Award Agreement to another jurisdiction.

       An authorized representative of the Company has signed this Award Agreement as of the Date of Grant.

PINNACLE	WEST CAPITAL CORPORATION
By:
Its:

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Pinnacle West Capital Corporation

PERFORMANCE SHARE AWARD
ELECTION FORM

INFORMATION ABOUT YOU

Last First Middle Initial Employee ID#

TAX WITHHOLDING ELECTION

I hereby elect to satisfy any tax withholding obligation associated with my receipt of Stock pursuant to my Performance Share Agreement in the following form (place an “X” in the “Cash” column or in the “Stock” column):

Cash	Stock
(I will write a check for my taxes that are due)	(The Company should withhold shares of my stock to cover my taxes)
o	o

PARTICIPANT NAME (PLEASE PRINT)
PARTICIPANT SIGNATURE	DATE

IMPORTANT NOTE: Please complete and return this Election Form to                    at Mail Station                    

EX-12.1

Exhibit 12.1

PINNACLE WEST CAPITAL CORPORATION
COMPUTATION OF EARNINGS TO FIXED CHARGES
(dollars in thousands)

	Three
	Months
	Ended
	March 31,			Twelve Months Ended December 31,
	2009			2008		2007		2006		2005		2004
Earnings:
Income (loss) from continuing operations	$	(153,586	)	$	223,613	$	298,744	$	316,265	$	227,288	$	242,887
Income taxes		(96,174	)		71,918		150,910		155,855		129,533		133,771
Fixed charges		61,708			241,724		235,705		225,119		214,430		214,803
Total earnings	$	(188,052	)	$	537,255	$	685,359	$	697,239	$	571,251	$	591,461
Fixed Charges:
Interest expense	$	55,806		$	216,038	$	208,521	$	196,826	$	185,087	$	183,527
Estimated interest portion of annual rents		5,902			25,686		27,184		28,293		29,343		31,276
Total fixed charges	$	61,708		$	241,724	$	235,705	$	225,119	$	214,430	$	214,803
Ratio of Earnings to Fixed Charges (rounded down)		(3.04	)		2.22		2.90		3.09		2.66		2.75

EX-12.2

Exhibit 12.2

ARIZONA PUBLIC SERVICE COMPANY
COMPUTATION OF EARNINGS TO FIXED CHARGES
(dollars in thousands)

	Three Months
	Ended
	March 31,			Twelve Months Ended December 31,
	2009			2008		2007		2006		2005		2004
Earnings:
Income (loss) from continuing operations	$	(15,479	)	$	262,344	$	283,940	$	269,730	$	170,479	$	199,627
Income taxes		(7,926	)		107,261		151,157		138,927		98,010		120,030
Fixed charges		56,366			213,583		202,044		191,174		178,437		181,372
Total earnings	$	32,961		$	583,188	$	637,141	$	599,831	$	446,926	$	501,029
Fixed Charges:
Interest charges	$	49,370		$	183,503	$	170,594	$	158,769	$	145,502	$	146,983
Amortization of debt discount		1,189			4,702		4,639		4,363		4,085		4,854
Estimated interest portion of annual rents		5,807			25,378		26,811		28,042		28,850		29,535
Total fixed charges	$	56,366		$	213,583	$	202,044	$	191,174	$	178,437	$	181,372
Ratio of Earnings to Fixed Charges (rounded down)		0.58			2.73		3.15		3.13		2.50		2.76

EX-12.3

Exhibit 12.3

PINNACLE WEST CAPITAL CORPORATION
COMPUTATION OF EARNINGS TO FIXED CHARGES
AND PREFERRED STOCK DIVIDEND REQUIREMENTS
(dollars in thousands)

	Three
	Months
	Ended
	March 31,			Twelve Months Ended December 31,
	2009			2008		2007		2006		2005		2004
Earnings:
Income (loss) from continuing operations	$	(153,586	)	$	223,613	$	298,744	$	316,265	$	227,288	$	242,887
Income taxes		(96,174	)		71,918		150,910		155,855		129,533		133,771
Fixed charges		61,708			241,724		235,705		225,119		214,430		214,803
Total earnings	$	(188,052	)	$	537,255	$	685,359	$	697,239	$	571,251	$	591,461
Fixed Charges:
Interest expense	$	55,806		$	216,038	$	208,521	$	196,826	$	185,087	$	183,527
Estimated interest portion of annual rents		5,902			25,686		27,184		28,293		29,343		31,276
Total fixed charges	$	61,708		$	241,724	$	235,705	$	225,119	$	214,430	$	214,803
Preferred Stock Dividend Requirements:
Income before income taxes	$	(249,760	)	$	295,531	$	449,654	$	472,120	$	356,821	$	376,658
Net income from continuing operations		(153,586	)		223,613		298,744		316,265		227,288		242,887
Ratio of income before income taxes to net income		1.626			1.322		1.505		1.493		1.570		1.551
Preferred stock dividends		—			—		—		—		—		—
Preferred stock dividend requirements – ratio (above) times preferred stock dividends	$	—		$	—	$	—	$	—	$	—	$	—
Fixed Charges and Preferred Stock Dividend Requirements:
Fixed charges	$	61,708		$	241,724	$	235,705	$	225,119	$	214,430	$	214,803
Preferred stock dividend requirements		—			—		—		—		—		—
Total	$	61,708		$	241,724	$	235,705	$	225,119	$	214,430	$	214,803
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements (rounded down)		(3.04	)		2.22		2.90		3.09		2.66		2.75

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Donald E. Brandt, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 5, 2009.

/s/ Donald E. Brandt  

Donald E. Brandt 

Chairman, President and
Chief Executive Officer 

2 

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James R. Hatfield, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 5, 2009.

/s/ James R. Hatfield  

James R. Hatfield 

Senior Vice President &
Chief Financial Officer 

EX-31.3

EXHIBIT 31.3

CERTIFICATION

I, Donald E. Brandt, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 5, 2009.

/s/ Donald E. Brandt  

Donald E. Brandt 

Chairman and Chief Executive Officer 

EX-31.4

EXHIBIT 31.4

CERTIFICATION

I, James R. Hatfield, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 5, 2009.

/s/ James R. Hatfield  

James R. Hatfield 

Senior Vice President &
Chief Financial Officer 

EX-32.1

Exhibit 32.1

CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the fiscal quarter ended March 31, 2009 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date: May 5, 2009.

/s/ Donald E. Brandt  

Donald E. Brandt 

Chairman, President and
Chief Executive Officer 

     I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the fiscal quarter ended March 31, 2009 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.

Date: May 5, 2009.

/s/ James R. Hatfield  

James R. Hatfield 

Senior Vice President and
Chief Financial Officer 

EX-32.2

Exhibit 32.2

CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the fiscal quarter ended March 31, 2009 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date: May 5, 2009.

/s/ Donald E. Brandt  

Donald E. Brandt 

Chairman and Chief Executive Officer 

     I, James R. Hatfield, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the fiscal quarter ended March 31, 2009 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date: May 5, 2009.

/s/ James R. Hatfield  

James R. Hatfield 

Senior Vice President and
Chief Financial Officer 

EX-99.1

Exhibit 99.1

BEFORE THE ARIZONA CORPORATION C

COMMISSIONERS

KRISTIN K. MAYES, Chairman
GARY PIERCE
PAUL NEWMAN
SANDRA D. KENNEDY
BOB STUMP

IN THE MATTER OF THE APPLICATION OF
ARIZONA PUBLIC SERVICE FOR A
HEARING TO DETERMINE THE FAIR
VALUE OF THE UTILITY PROPERTY OF
THE COMPANY FOR RULEMAKING
PURPOSES, TO FIX A JUST AND
REASONABLE RATE OF RETURN
THEREON, TO APPROVE RATE
SCHEDULES DESIGNED TO DEVELOP
SUCH RETURN. DOCKET NO. E-01345A-08-0172


NOTICE OF FILING
TERM SHEET

     The Settling Parties¹, in compliance with the filing deadline of May 4, 2009 set by the Chief Administrative Law Judge in the April 21, 2009 procedural conference in this matter, hereby file their “Term Sheet” in contemplation of their Proposed Settlement Agreement.

RESPECTFULLY SUBMITTED this 4^th day of May, 2009.

/s/ Maureen A. Scott  

Janet Wagner, Assistant Chief Counsel 

Maureen A. Scott, Senior Staff Counsel
Charles H. Hains, Attorney
Amanda Ho, Attorney
Legal Division
Arizona Corporation Commission
1200 West Washington Street
Phoenix, Arizona 85007
(602) 542-3402 

¹    Settling Parties include Arizona Corporation Commission Utilities Division Staff; Arizona Public Service Company (“APS”); the Residential Utility Consumer Office (“RUCO”); Arizona Association of School Business Officials; Arizona School Boards Association; Southwest Energy Efficiency Project (“SWEEP”); Arizonans for Electric Choice and Competition (“AECC”); Arizona Investment Council (“AIC”); Arizona Agricultural Group (“Az-Ag Group”); Cynthia Zwick; IBEW Locals 387, 640 and 769; Bowie Power Station, L.L.C, Freeport-McMoRan Copper & Gold Inc., Mesquite Power, L.L. C; Southwestern Power Group II; Western Resources Advocates; and the Kroger Company.

Docket No. E-01345A-08-0172
Notice of Filing — Term Sheet

/s/ Thomas L. Mumaw	MAS
Thomas L. Mumaw
Meghan H. Grabel PINNACLE WEST CAPITAL CORPORATION LAW DEPARTMENT P.O. Box 53999 Phoenix, Arizona 85072-3999 Attorney for Arizona Public Service Company
/s/ Daniel J. Pozefsky	MAS
Daniel J. Pozefsky
Residential Utility Consumer Office 1110 West Washington Street, Suite 220 Phoenix, Arizona 85007
/s/ Jay I. Moyes	MAS
Jay I. Moyes
MOYES SELLERS & SIMS 1850 North Central Avenue, Suite 1100 Phoenix, Arizona 85004-0001 Attorney for Arizona Agricultural Group
/s/ Timothy M. Hogan	MAS
Timothy M. Hogan
ARIZONA CENTER FOR LAW IN THE PUBLIC INTEREST 202 East McDowell Road, Suite 153 Phoenix, Arizona 85004 Attorney for Arizona Association of School Business Officials
/s/ Michael M. Grant	MAS
Michael M. Grant
GALLAGHER & KENNEDY 2575 East Camelback Road Phoenix, Arizona 85016-9225 Attorney for Arizona Investment Council
/s/ Timothy M. Hogan	MAS
Timothy M. Hogan
ARIZONA CENTER FOR LAW IN THE PUBLIC INTEREST 202 East McDowell Road, Suite 153 Phoenix, Arizona 85004 Attorney for Arizona School Boards Association

2

Docket No. E-01345A-08-0172
Notice of Filing — Term Sheet

/s/ C. Webb Crockett	MAS
C. Webb Crockett
FENNEMORE CRAIG P.C. 3003 North Central Avenue, Suite 2600 Phoenix, Arizona 85012-2913 Attorney for Arizonans for Electric Choice and Competition
/s/ Lawrence V. Robertson, Jr.	MAS
Lawrence V. Robertson, Jr.
Attorney at Law P.O. Box 1448 Tubac, Arizona 85646 Attorney for Bowie Power Station, L.L.C.
/s/ C. Webb Crockett	MAS
C. Webb Crockett
FENNEMORE CRAIG P.C. 3003 North Central Avenue, Suite 2600 Phoenix, Arizona 85012-2913 Attorney for Freeport-McMoRan Copper & Gold Inc.
/s/ Nicholas J. Enoch	MAS
Nicholas J. Enoch
Lubin & Enoch, P.C. 349 N. 4th Avenue Phoenix, Arizona 85003 Attorney for IBEW Locals 387, 640 and 769
/s/ Kurt M. Boehm	MAS
Kurt M. Boehm
BOEHM, KURTZ & LOWRY 36 East Seventh Street, Suite 1510 Cincinnati, Ohio 45202 Attorney for The Kroger Company
/s/ Lawrence V. Robertson, Jr.	MAS
Lawrence V. Robertson, Jr.
Attorney at Law P.O. Box 1448 Tubac, Arizona 85646 Attorney for Mesquite Power, L.L.C.

3

Docket No. E-01345A-08-0172
Notice of Filing — Term Sheet

/s/ Timothy M. Hogan	MAS
Timothy M. Hogan
ARIZONA CENTER FOR LAW IN THE PUBLIC INTEREST 202 East McDowell Road, Suite 153 Phoenix, Arizona 85004 Attorney for Southwest Energy Efficiency Project
/s/ Lawrence V. Robertson, Jr.	MAS
Lawrence V. Robertson, Jr.
Southwestern Power Group II, L.L.C. Attorney at Law P.O. Box 1448 Tubac, Arizona 85646
/s/ Timothy M. Hogan	MAS
Timothy M. Hogan
ARIZONA CENTER FOR LAW IN THE PUBLIC INTEREST 202 East McDowell Road, Suite 153 Phoenix, Arizona 85004 Attorney for Western Resource Advocates
/s/ Cynthla Zwick	MAS
Cynthla Zwick
1940 E. Luke Avenue Phoenix, Arizona 85016

4

Docket No. E-01345A-08-0172
Notice of Filing — Term Sheet

Original and thirteen (13) copies
of the foregoing were filed this
4^th day of May, 2009 with:

Docket Control
Arizona Corporation Commission
1200 West Washington Street
Phoenix, Arizona 85008

Copies of the foregoing mailed
this 4^th day of May, 2009 to:

Thomas L. Mumaw
Meghan H. Grabel
PINNACLE WEST CAPITAL CORPORATION LAW
DEPARTMENT P.O. Box 53999
Phoenix, Arizona 85072-3999

William J. Maledon
OSBORN MALEDON P.A.
2929 North Central Avenue
Phoenix, Arizona 85067-6379

Robert Metli
SNELL & WILMER L.L.P.
400 East Van Buren Street
Phoenix, Arizona 85004-2202

Barbara Klemstine
Zachary Fryer
Susan Casady
ARIZONA PUBLIC SERVICE COMPANY
P.O. Box 53999
Mail Station 9708
Phoenix, Arizona 85072-3999

Michael L. Kurtz
Kurt J. Boehm
BOEHM, KURTZ & LOWRY
36 East Seventh Street, Suite 1510
Cincinnati, Ohio 45202

C. Webb Crockett
Patrick J. Black
FENNEMORE CRAIG P.C.
3003 North Central Avenue, Suite 2600
Phoenix, Arizona 85012-2913

Lawrence V. Robertson, Jr.
Attorney at Law
P.O. Box 1448
Tubac, Arizona 85646

Michael A. Curtis
William P. Sullivan
Larry K. Udal1
CURTIS, GOODWIN, SULLIVAN,
     UDALL & SCHWAB, P.L.C.
501 East Thomas Road
Phoenix, Arizona 85012-3205

Timothy M. Hogan
ARIZONA CENTER FOR LAW IN
     THE PUBLIC INTEREST
202 East McDowell Road, Suite 153
Phoenix, Arizona 85004

Daniel W. Pozefsky
RUCO
1110 West Washington Street, Suite 220
Phoenix, Arizona 85007

Michael M. Grant
GALLAGHER & KENNEDY
2575 East Camelback Road
Phoenix, Arizona 85016-9225

Gary Yaquinto
ARIZONA INVESTMENT COUNCIL
2100 North Central Avenue, Suite 210
Phoenix, Arizona 85004

Jay I. Moyes
Karen E. Nally
MOYES SELLERS & SIMS
1850 North Central Avenue, Suite 1100
Phoenix, Arizona 85004-0001

David Berry
WESTERN RESOURCE ADVOCATES
P.O. Box 1064
Scottsdale, Arizona 85252

5

Docket No. E-01345A-08-0172
Notice of Filing — Term Sheet

Jeff Schlegel
SWEEP Arizona Representative
1167 West Samalayuca Drive
Tucson, Arizona 85704

Jeffrey J. Woner
K.R. SALINE & ASSOC., PLC
160 North Pasadena, Suite 101
Mesa, Arizona 85201

Scott Canty, General Counsel
THE HOPI TRIBE
P.O. Box 123
Kykotsmovi, Arizona 86039

Carlo Dal Monte
65 Front Street, Suite 201
Nanaimo, British Columbia V9R 5H9

Barbara Wyllie-Pecora
27458 N. 128^th Dr.
Peoria, Arizona 85383

Amanda Ormond
7650 S. McClintock, Suite 103-282
Tempe, Arizona 85284

Douglas Fant
3655 W. Anthem Way -A-109 PMB 411
Anthem, Arizona 85086

Lieutenant Colonel Karen White
AFLSA/JACL-ULT
139 Barnes Dr., Suite 1
Tyndall AFB, Florida 32403-5319

/s/ Karyn Christine

6

APS’ APPLICATION FOR A RATE INCREASE
DOCKET NO. E-01345A-08-0172
PROPOSED SETTLEMENT FRAMEWORK TERM SHEET
May 4, 2009

I. Introduction and General Overview of Settlement Agreement Framework.

     The Settling Parties¹ present this Term Sheet to reflect an Agreement in Principle (“Agreement”) regarding Arizona Public Service Company’s (“APS” or the “Company”) request to increase rates. The result of detailed, lengthy negotiations, the Agreement provides an opportunity for APS to regain sound financial health through the sustained reduction of expenses, a stronger capital structure and improved cash flow from increased rates.

          The settlement also advances Arizona’s sustainable energy future. It will establish the first energy efficiency standard for any Arizona utility, requiring APS to meet certain energy efficiency goals, to implement a customer repayment program for schools, municipalities and small businesses for certain energy efficiency technologies, and to implement programs to place renewable energy projects at Arizona schools and governmental institutions. APS will also acquire renewable energy resources (both distributed and non-distributed) at levels exceeding the Renewable Energy Standards, solicit for in-state wind generation in an effort to advance the commercialization of wind resources in Arizona, commit APS to the construction of transmission targeted at renewable resources, enhance its low income programs, and reopen a rate schedule for houses of worship, among other things.

          In recent years, certain of APS’ financial metrics have generally remained below the industry average and remain so today, despite multiple litigated proceedings and various forms of ameliorative action taken by the Commission, including grants of emergency rate relief. The Settling Parties collectively believe that having new rate cases filed immediately or shortly after the conclusion of a rate case is not in the public interest, and that greater rate stability, fewer proceedings, and improved coordination of future rate cases will benefit all participants in these processes and the public in general. Additionally, there are many critical social and policy issues facing Arizona-such as the need to increase renewable energy resources and infrastructure, expand energy efficiency opportunities, and develop new rate options and customer programs-which require a financially sound APS to ensure successful implementation.

¹ The Settling Parties include the Arizona Corporation Commission Utilities Division Staff (“Staff”); Arizona Public Service Company (“APS”); the Residential Utility Consumer Office (“RUCO”); Arizona Association of School Business Officials; Arizona School Boards Association; Southwest Energy Efficiency Project (“SWEEP”); Arizonans for Electric Choice and Competition (“AECC”); Arizona Investment Council (“AIC”); Arizona Agricultural Group (“Az-Ag Group”); Cynthia Zwick; IBEW Locals 387, 640 and 769; Bowie Power Station, L.L.C.; Freeport-McMoRan Copper & Gold Inc.; Mesquite Power, L.L.C.; Southwestern Power Group II, Western Resource Advocates; and The Kroger Company.

          In that spirit, the settlement reflected in this Term Sheet proposes the adoption of a Rate and Financial Stability Plan for APS (“Plan”), which seeks an appropriate balance of the risk and responsibilities of APS, its employees, its customers, and other interested parties.

          The plan additionally creates a strategic framework that could improve APS’ financial metrics and bond ratings, which over the long term will benefit customers by allowing APS to borrow at more attractive interest rates and optimize operational flexibility. This framework includes prefiling and coordination processes for subsequent rate cases, which are intended to expedite the resolution of such filings. It also provides for a comprehensive, independent benchmarking study of the Company’s performance, and establishes performance measures intended to encourage alignment of APS and Commission policies. APS will report annually on such measures in order to provide important information that will enhance the evaluation of future rate requests.

          If the Settlement Agreement is approved by the Commission, rates will increase by approximately $131.1 million over the current interim increase of $65.2 million. Together this represents a total non-fuel base rate increase in this case of $196.3 million. This is less than the amount requested by APS and the IBEW, but more than the amount previously recommended by several of the other Settling Parties. Under the Agreement, base rates cannot be increased again until at least July 1, 2012.

          The Settlement Agreement provides numerous benefits for customers as discussed below:

1. Investment in Arizona’s Energy Future.

a. Energy Efficiency.

• Establishment of energy efficiency goals, as well as tiered performance incentives and program enhancements to meet these goals and achieve significant benefits for customers including:

- Annualized energy savings of about 320,000 MWh in 2010, 400,000 MWh in 2011, and 490,000 MWh in 2012;

- At least 100 schools served by the existing or enhanced DSM programs by December 31, 2010; and,

- At least 1,000 customers in existing homes served by the Home Performance enhanced program element by December 31, 2010;

b. Renewable Resources.

• By December 31, 2015, acquisition by APS of new renewable resources, in addition to those already in service or for which APS has already made commitments, that provide 1,700,000 MWh of energy annually, including:

2

- A plan for a utility scale photovoltaic generation project;

- An RFP for an in-state wind generation project;

- Distributed solar energy projects for Arizona K-12 schools that produce or save 50,000 MWh annually; and,

- Distributed solar energy projects for government institutions;

• Construction of one or more renewable energy transmission lines or upgrades consistent with the Biennial Transmission Assessment Report.

2. Commitments Benefitting Low-Income Customers.

• Continued rate discounts for current and future low income customers of APS, holding these customers harmless from the rate increase;

• Creation of a new bill assistance program to benefit customers whose incomes exceed 150% of the Federal Poverty Income Guidelines but are less than or equal to 200% of the Federal Poverty Income Guidelines, funded by APS in an amount of $5.0 million; and,

• Waiving of additional security deposits for low income customers.

3. Rate Stability Plan.

• An increase in rate stability, including a period without base rate increases (no new rates before July 1, 2012) and a scheduled plan for future rate cases, resulting in greater administrative efficiency and reduced uncertainty for both APS and customers.

4. Rate Related Benefits.

• An improvement in APS’ ability to attract capital, maintain reliability and sustain growth;

• A limit on recovery of Annual Cash Incentive Compensation for executives depending upon achievement of certain performance measures;

• A sustained reduction of expenses of at least $30 million per year or $150 Million over a five-year period which will reduce the need for future rate increases;

• An infusion of at least $700 million of additional equity by December 31, 2014 resulting in an improvement in APS’ financial metrics strengthening its bond rating and reducing future debt costs;

• A plan to be submitted by the Company to maintain investment grade financial ratios and improve its financial metrics;

• An acceleration of any over-collected amounts in the Power Supply Adjustor (PSA), which should result in a lower adjustor rate to partially offset the base rate increase;

• A reduced Systems Benefits Charge if a Palo Verde license extension is approved before the conclusion of the next rate case; and,

• Continued 90/10 sharing of the PSA.

3

5. Creation of Performance Measurements and Increased Reporting Requirements.

• APS will be subject to periodic evaluation based upon the performance measures established in the Settlement Agreement and will also be subject to reporting requirements; and

• A benchmarking study will be conducted which compares APS’ performance on financial and other metrics to a comparable peer group of companies.

6. New Rate Design Options.

• Creation of an optional super-peak tariff for residential customers and other critical peak pricing rates;

• Twelve month reopening of the E-20 House of Worship tariff on an optional basis;

• Development of an Interruptible Rate schedule or other demand reduction program for E-34 or E-35 customers; and,

• A new TOU rate applicable to K-12 schools designed to provide daily and seasonal price signals to encourage load reductions during peak periods.

               The Settling Parties jointly believe that the settlement outlined in this Term Sheet is a balanced resolution of APS’ rate case for the Company, its customers, and the other parties to this Agreement; provides a framework to advance important public policy goals; and is in the public interest.

II. Summary of Major Settlement Agreement Provisions.

A. Rate Case Stability Provisions.

1. General Rate Case Filing Plan.

               The Settling Parties agree to a series of scheduled general base rate cases for APS to address plant additions and other rate matters. APS is prohibited from filing its next two general rate cases until on or after June 1, 2011 and June 1, 2013 respectively. No new base rates resulting from APS’ next general rate case will be effective before July 1, 2012.

The Settling Parties intend to process these subsequent rate cases within 12 months of a sufficiency finding. The Company shall provide a one hundred twenty (120) day notice to the Commission and the Settling Parties of its intent prior to filing a rate case. The notice shall specify the test year period to be utilized and other contents, including any major issues which APS, at the time of filing the notice of intent, expects to raise in conjunction with the application package.

4

2. Accelerated PSA Reset.

          If at the time new rates are implemented, the PSA has an over-collected balance, the PSA reset would be accelerated from February 1, 2010 so that the reduction in the PSA level would partially offset the increase to higher base rates.

B. Revenue Requirement and Related Issues.

1. Base Rate Increase.

          The Commission granted APS an interim increase of $65.2 million in 2008. APS will receive an additional non-fuel base rate increase of approximately $131 million. The total non-fuel base rate increase granted in this case (interim plus settlement) would be $196.3 million. This rate increase would take effect on January 1, 2010.

          The Parties agree that the base cost of fuel and purchase power will be $0.037571 per KWh. This base fuel amount shall be reflected in APS’ base rates.

          When adjusted for both the interim increase and an additional $11.2 million of revenue associated with establishing new base fuel levels, this settlement represents an approximate 7.9% increase in base rate revenue. The table below summarizes how this increase compares to the recommendations of APS, Staff, RUCO, and AECC.

Comparison of APS, Staff, RUCO and Settlement
Summary of Base Rate Increase	APS			Staff			RUCO			AECC
(Thousands of Dollars)	Proposed			Proposed			Proposed			Proposed			Settlement
Components of Total Rate Increase
Base Rate Increase	$	264,341		$	155,062		$	(27,281	)	$	205,444		$	196,300
Fuel Related Increase in Base Rates	$	13,876		$	11,436		$	13,876		$	10,695		$	11,203
Total Base Rate Increase	$	278,217		$	166,498		$	(13,405	)	$	216,139		$	207,503
Adjusted Base Cost of Fuel Related Increase	$	169,977		$	140,088		$	169,977		$	130,527		$	137,235
Total Rate Increase Requested	$	448,194		$	306,586		$	156,572		$	346,666		$	344,738
Percentage Increase Over Current Rates
Revenue from Sales to Ultimate Retail Customers
2007 Test Year Adjusted	$	2,637,447		$	2,637,447		$	2,748,697		$	2,637,447		$	2,637,447
Percentage Increase — Net of PSA		10.55	%		6.31	%		-0.49	%		8.20	%		7.87	%
Percentage Increase — Total		16.99	%		11.62	%		5.70	%		13.14	%		13.07	%
Revenue from Sales to Ultimate Retail Customers
2010 Base Rate Revenue per APS	$	2,654,236		$	2,654,236		$	2,654,236		$	2,654,236		$	2,654,236
Percentage Increase — Net of PSA		10.48	%		6.27	%		-0.51	%		8.14	%		7.82	%
Percentage Increase — Total		16.89	%		11.55	%		5.90	%		13.06	%		12.99	%

Note: the Parties are looking at transitioning DSM costs currently recovered in base rates into the DSM Adjustor Mechanism such that all DSM costs would be recovered via that Adjustor (similar to the TEP mechanism as discussed in Section II-G)

          The table does not show costs that will flow through existing adjustors such as the Demand Side Management Adjustor Clause (“DSMAC”), Renewable Energy Standards Tariff (“REST”) surcharge and Power Supply Adjustor (“PSA”).

          Additionally, certain provisions in the Proposed Settlement Agreement do not have a rate impact in the present case, but they will have an impact in future APS rate cases. Specifically, the rate impacts shown above do not include the increased cost to customers in a future APS rate case resulting from the treatments specified in this

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Settlement Agreement for recording Schedule 3 receipts as revenue (as opposed to Contributions in Aid of Construction (“CIAC”)), for limited pension and Other Post- Retirement Benefits (“OPEB”) deferrals, and for a Palo Verde depreciation rate change. The rate impacts shown above also do not reflect the settlement’s requirements that APS reduce future costs by $30 million annually (or 150 million over the next five years), which will reduce future revenue requirements.

          2. Authorized Return on Equity.

          A Return on Equity of 11 % will be adopted.

          3. Treatment of Schedule 3.

          Proceeds from Schedule 3 would be recorded as revenue during the period from January 1, 2010 through the earlier of December 31, 2012 or the conclusion of the Company’s next general rate case for an estimated increase of $23 million, $25 million and $49 million in revenues each respective year of this term. Thereafter, Schedule 3 receipts will be recorded as CIAC, unless otherwise ordered by the Commission.

          APS’ Impact Fee proposal in the rate case would be withdrawn.

          The System Facilities Charge proposed by APS shall be withdrawn.

          Upon Commission approval of this settlement, APS shall file in this docket a revised Schedule 3 that is consistent with the Decision and includes clarification of charges, definitions, a schedule of charges and a requirement by APS to itemize customer quotes among other matters. In light of the Commission’s continuing interest in this issue, the Settlement Agreement may contain additional provisions for Schedule 3 that are revenue neutral to this settlement.

          4. Pension and OPEB Deferrals.

     APS will be allowed to defer, in accordance with the provisions of SFAS No. 71, a portion of its annual pension and OPEB costs above (or below) the test year level in years 2011 and 2012, subject to the following maximum amounts:

• 2011: deferral cannot exceed the lower of $13.5 million or 50% of the cost above the test year level;

• 2012: deferral cannot exceed $29 million of the cost above the test year level.

          5. Expense Reduction Commitment.

     Starting in 2010, APS will reduce its expenses by an additional $10 million above the $20 million expense reduction commitment previously made by APS to the Commission. The $30 million average annual expense reduction will continue through

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December 31, 2014. The total expense reduction during the Plan Term shall be at least $150 million.

          6. Palo Verde License Extension.

     Upon the later date (1) of receiving NRC approval for Palo Verde license extension or (2) 1/1/2012, APS is authorized to adjust depreciation rates used for recording depreciation expense on the Palo Verde generating unit to reflect such license extension. Upon the later date (1) of receiving NRC approval for Palo Verde license extension or (2) 1/1/2012, APS shall adjust the System Benefit Charge (“SBC”) and reduce such charge to reflect a corresponding reduction of decommissioning trust funding obligations related to the Palo Verde license extension.

     APS has estimated that the change in depreciation rates due to the approved license extension will result in a reduction to APS’ depreciation expense. Once the reduced depreciation expense is recognized as an expense reduction in the context of the reestablishment of new base rates in APS’ next base rate case, it would begin to provide a benefit to customers.

     The changes in the recorded depreciation expense resulting from the Palo Verde depreciation rate change that would occur before the Company’s base rates are reestablished in the Company’s next rate case represent a benefit to APS, and will have an impact on APS’ rate base in the next APS rate case. During that period the lower recorded depreciation expense amounts mean that Accumulated Depreciation (a rate base offset) would be lower and APS’ rate base would be higher. The benefit to the Company associated with recording the new depreciation rates shall therefore be offset (in part) by the SBC reduction, which will reduce customer rates before the next rate case.

     C. Equity Infusions Required.

     APS will complete equity infusions of at least $700 million during the period beginning with the execution of the Settlement Agreement through December 31, 2014. The Opinion and Order approving the settlement shall constitute authorization to infuse $700 million into APS through December 31, 2014. This amount includes the “up to $400 million” which was previously authorized by the Commission in Decision No. 70454, which authorization expires on December 31, 2009

     The settlement also obliges the Company to use its best efforts to improve its financial metrics and bond ratings, by making timely equity infusions and taking other measures to strive to achieve a capital structure with no more than 52% debt/total capital, as calculated by the credit rating agencies, by December 31, 2012.

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     D. Limit on Annual Cash Incentive Compensation for Executives.

     The Settling Parties agree that Annual Cash Incentive Compensation for executives paid for 2010, 2011, and 2012 shall not exceed the test year level unless the Company: (1) has met all the components of the Performance Measurements; or (2) receives a Hardship Waiver from the Commission for failure to meet one or more of the Performance Measurements; or (3) issues Annual Cash Incentive Compensation in excess of the test year levels that are absorbed by the shareholders and not recovered from customers. For the purposes of this provision, an affected “executive” is an APS employee at the level of Vice President or higher.

     E. Periodic Evaluation.

     APS will be subject to periodic evaluation based upon the following performance measures, which include both “Performance Measurements” and “Reporting Requirements.”

          1. Performance Measurements.

• Compliance with the renewable energy goals set forth in the Agreement;

• Placement of renewable energy projects at Arizona schools consistent with the terms of the Agreement;

• Compliance with the energy efficiency goals set forth in the Agreement;

• Meeting the sustained cost reductions set forth in the Agreement;

• Striving to achieve a Capital Structure of no more than 52% total debt as set forth in the agreement;

• Compliance with the plan to be submitted by the Company to maintain investment grade financial ratios and to improve its financial metrics;

• $700 Million Equity Infusion pursuant to the terms of the Agreement;

• Annual Reporting of Financial and Customer Service Criteria

• Cooperating with the Commission Staff in its conduct of the Benchmark Study comparing APS with other similarly situated utilities

     The Commission shall decide the appropriateness of any waivers of limits on Annual Cash Incentive Compensation recoverability based upon failure to meet these Performance Measurements.

          2. Reporting Requirements — APS will report annually each April 30 to the Commission, on a detailed list of financial and customer service reliability and safety items including but not limited to PNW stock performance, stock and debt issuances, rating agency reports and communications, earnings and earned ROE, management expenses, the dividend payout ratio, O&M expense, customer and sales expenses per customer and capital expenditures. The Company shall also annually file a report with the

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Commission documenting its performance for the preceding year in relation to the Performance Measures set forth in the agreement.

          3. Benchmarking Study — By March 31, 2010, Staff shall select a benchmarking firm to conduct a benchmarking analysis of APS’ operational and cost performance relative to a peer group of other utilities. The scope of the analysis will cover factors that will be specified in the final Settlement Agreement.

     The Company shall incur all costs related to this benchmark study, which costs will be capped at $500,000. All costs associated with the study shall not be recoverable in rates.

     The Benchmark Study Report shall be presented to the Commission no later than December 31, 2010.

     F. Fuel and Power Supply Adjustor (“PSA”).

          1. The 90/10 sharing provision in the current PSA will be continued.

          2. Gains on SO2 Allowances over or under the normalized amount reflected in base rates shall be recovered and/or refunded through the PSA mechanism.

     G. Demand Side Management (“DSM”).

          1. Energy Efficiency goals shall be established, defined as annual energy savings of 1.0% in 2010, 1.25% in 2011, and 1.5% in 2012, expressed as a percent of total energy resources needed to meet retail load. Cumulative annualized energy savings from the programs in 2010-2012 would be approximately 3.75% (1.00% + 1.25% + 1.50%) of total energy resources needed to meet retail load in 2012. If higher goals are adopted by the Commission for 2010, 2011 or 2012 in another docket, then those higher goals will supersede the goals listed above, as will any higher performance incentives.

          2. The existing performance incentive for energy efficiency programs shall be modified to be a tiered performance incentive as a % of net benefits, capped at a tiered % of program costs.

Achievement Relative to	Incentive as % of Net	Capped at % of
MWh Target	Benefits	Program Costs
Less than 85%	0%	0%
85% to 95%	6%	12%
96% to 105%	7%	14%
106% to 115%	8%	16%
116% to 125%	9%	18%
Above 125%	10%	20%

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          3. “Self-direction” of DSM charges will be allowed for large commercial or large industrial customers who use more than 40 million kWh in a 12 month period; a single customer may aggregate its usage over more than one APS account. A self-directing customer may not participate directly in the standard DSM programs in any year in which the customer is self-directing its DSM charges. A self- directing customer must submit an application documenting the savings and costs of its energy efficiency project, and must also comply with utility reporting requirements for measurement, verification and validation. The self-direction program will be administered by APS. The energy savings from self-direction projects will count towards the APS energy efficiency goals. Additional details regarding this term will be memorialized in the Settlement Agreement.

          4. APS’ DSMAC will be modified to achieve more current recovery of program costs, similar to the DSMAC approved for Tucson Electric Power Company (“TEP”) in Decision No. 70628. Similar to paragraph 9.4 of the TEP settlement (Decision No. 70628, Exhibit A, page 12 of 51), APS shall apply interest whenever an over-collected balance results in a refund to customers. The interest rate shall be based on the one-year Nominal Treasury Constant Maturities rate contained in the Federal Reserve Statistical Release H-15 or its successor publication. The interest rate should be adjusted annually on the first business day of the calendar year.

          5. APS shall not recover unrecovered fixed costs through the recovery of DSM program costs. This provision will not preclude APS from seeking such recovery in other proceedings.

          6. APS shall file for the Commission’s consideration in this Docket an annual Energy Efficiency Implementation Plan for 2010, 2011, and 2012, with new and/or expanded programs or program elements necessary to achieve the energy efficiency goals. Each Implementation Plan shall include estimated energy savings by program and a range of estimated program costs by program necessary to meet the goal. Staff will review each Plan and provide its recommendations to the Commission. For any new programs, the Company and Staff will perform the cost effectiveness tests considering criteria and parameters reviewed by the DSM Collaborative. However, modifications to program elements of existing Commission-approved programs or adjustments to spending levels by program from year to year may not require an updated cost effectiveness test. The Company will file implementation plans on June 1, 2010 and June 1, 2011 for the 2011 and 2012 goals respectively.

          7. By July 15, 2009, APS shall file for the Commission’s consideration in this Docket the 2010 Energy Efficiency Implementation Plan with new and/or expanded programs or program elements necessary to achieve the 2010 energy efficiency goal, including the enhancements and program elements set forth below. Staff shall review the Plan and provide its recommendations to the Commission in sufficient time so that the Commission may consider the matter at its regular November Open Meeting. In an effort to achieve timely approval of the Plan, the Settling Parties’ will

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urge the Commission to take action on the Implementation Plan on or before the date it takes action on the Settlement Agreement.

          8. The 2010 Implementation Plan shall include:

a.	A customer repayment financing program element for schools, municipalities, and small businesses fully integrated in the non- residential programs;
b.	A goal for APS to serve, through its existing DSM programs or enhanced program elements, at least 100 schools by December 31, 2010;
c.	A review of the APS low income weatherization program for possible enhancement;
d.	A Home Performance direct installation program element within the Existing Home HVAC program. APS will design this program element with the goal of serving at least 1,000 existing homes by December 31, 2010;
e.	A non-residential high performance new construction program element with a second tier of performance and a higher financial incentive; and,
f.	A residential high performance new home program element with a second tier of performance and a higher financial incentive, which APS will file with the Commission on or before June 30, 2009 as part of its zero-net energy home filing.

     H. Renewable Energy.

          1. APS shall acquire by December 31, 2015 new renewable resources, in addition to those already in service or for which APS has already made commitments, which provide 1,700,000 MWh of energy annually. These new resources will be in addition to existing resource commitments as of the end of 2008.

          2. APS shall within 120 days of the Commission’s Order approving the Settlement Agreement file a plan for implementing a utility scale photovoltaic generation project, which shall have a construction initiation date not later than 18 months from the date of APS’ filing.

          3. APS shall issue a new request for proposals for in-state wind generation within 90 days of Commission approval of the Settlement.

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          4. APS shall initiate the process of constructing one or more renewable energy transmission lines or upgrades consistent with the Biennial Transmission Assessment report required by Decision No. 70635.

          5. APS shall file within 120 days of the Commission’s Order approving the Settlement Agreement a proposal for on-site solar energy for Arizona public schools (including charter schools), grades K-12, with a program goal of installing 50,000 MWhs of annual energy generation or savings within 36 months of program approval.

          6. APS shall file within 120 days of the Commission’s Order approving the Settlement Agreement a proposal for distributed solar energy projects for government institutions.

     I. Low Income Programs.

          1. The increase in base rate revenue will not apply to the existing low income schedules. As a result, all rate schedules except for the low income schedules will receive an equal percentage of base rate increase. This holds low income customers harmless from the rate increase and applies to both existing customers and those to be enrolled in the low income rate.

          2. APS shall establish a new bill assistance program to benefit customers whose incomes exceed 150% of the Federal Poverty Income Guidelines but are less than or equal to 200% of the Federal Poverty Income Guidelines. This program is to be funded by APS to be used by qualifying customers to assist them in the payment of customer electric bills. The level of the funding requirement during the Plan Term shall be established at $5 million.

          3. APS will waive the collection of an additional security deposit from customers on low-income rate schedules under the following circumstances: (1) the customer has had more than two late payments in the previous 12 months, or (2) the customer has been disconnected for non-payment.

     J. Demand Response.

     APS’ demand response program additions include super peak and critical peak pricing rates and other demand response programs that will be offered in conjunction with energy efficiency programs.

     K. Revenue Spread.

     1. Each retail rate schedule will receive an equal percentage total base rate increase, inclusive of the interim rate increase, and inclusive of fuel and purchased power costs that are incorporated into base rates.

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2. Within E-32, the percentage increase will be differentiated such that:

     a. E-32 (401 + kW) receives an increase that is 2.5% below average for the group;

     b. E-32 (101-400 kW) receives the group average increase;

     c. E-32 (21-100 kW) receives an increase that is 1% above the average for the group; and,

     d. E-32 (0-20 kW) receives an increase that is above the average for the group by the necessary residual amount (approximately 2.8%).

     L. Rate Design.

          1. The voltage discount for E-35 customers taking service at transmission voltage will be equal to the current discount adjusted by the overall E-35 percentage increase.

          2. The third-party transmission charge for Rates E-34 and E-35 proposed by APS is not adopted.

          3. The rate increase for Rates E-34, and E-35, and E-32 (400 + kW) will be implemented by adopting APS’ proposed changes in the customer charge with an equal percentage increase in the demand and energy charges.

     M. Interruptible Tariffs and Other Demand Reduction Programs.

     APS will develop an Interruptible Rate schedule or other demand reduction programs for E-34 or E-35 customers.

     N. Other Issues.

     Unfreeze existing Rate Schedule E-20 (House of Worship) tariff for a period of 12 months to allow for additional customer participation.

     Within 90 days of approval of the Settlement Agreement, APS will file a new TOU rate applicable to K-12 schools designed to provide daily and seasonal price signals to encourage load reductions during peak periods.

     O. Bill Impact Analysis.

          A bill impact analysis will be docketed on or before Friday, May 8, 2009.

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