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 September 30, 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 October 23, 2009: 101,281,436
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of October 23, 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
Forward-Looking Statements		2
Part I		3
Item 1. Financial Statements		3
Pinnacle West Capital Corporation		3
Arizona Public Service Company		41
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		49
Item 3. Quantitative and Qualitative Disclosures About Market Risk		75
Item 4. Controls and Procedures		75
Part II		77
Item 1. Legal Proceedings		77
Item 1A. Risk Factors		77
Item 5. Other Information		77
Item 6. Exhibits		81
Signatures		83
Exhibit 12.1
Exhibit 12.2
Exhibit 12.3
Exhibit 31.1
Exhibit 31.2
Exhibit 31.3
Exhibit 31.4
Exhibit 32.1
Exhibit 32.2

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations, and neither Pinnacle West Capital Corporation (“Pinnacle West”) nor Arizona Public Service Company (“APS”) assumes any obligation to update these statements, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2008 (“2008 Form 10-K”) and in Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operation herein, these factors include, but are not limited to:

• regulatory and judicial decisions, developments and proceedings, including the outcome and timing of APS’ pending retail rate case;

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

• our ability to reduce capital expenditures and other costs while maintaining reliability and customer service levels;

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

• power plant performance and outages;

• volatile fuel and purchased power costs;

• fuel and water supply availability;

• new federal legislation or regulation relating to greenhouse gas emissions, renewable energy mandates and energy efficiency standards;

• our ability to meet renewable energy requirements and recover related costs;

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

• competition in retail and wholesale power markets;

• the duration and severity of the economic decline in Arizona and current credit, financial and real estate market conditions;

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

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

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

• changes to our credit ratings;

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

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

• potential shortfalls in insurance coverage;

• new accounting requirements or new interpretations of existing requirements;

• transmission and distribution system conditions and operating costs;

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

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

• technological developments in the electric industry; and

• economic and other conditions affecting the real estate and credit markets in SunCor Development Company’s (“SunCor”) market areas, which include Arizona, Idaho, New Mexico and Utah.

2

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended
	September 30,
	2009			2008
OPERATING REVENUES
Regulated electricity segment	$	1,083,750		$	1,040,348
Real estate segment		48,474			16,152
Marketing and trading		—			4,663
Other revenues		10,853			8,925
Total		1,143,077			1,070,088
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		381,543			419,979
Real estate segment operations		26,863			26,129
Real estate impairment charge (Note 21)		36,993			—
Marketing and trading fuel and purchased power		—			1,456
Operations and maintenance		208,769			211,332
Depreciation and amortization		102,273			98,556
Taxes other than income taxes		34,111			28,423
Other expenses		8,014			8,321
Total		798,566			794,196
OPERATING INCOME		344,511			275,892
OTHER
Allowance for equity funds used during construction		2,197			4,673
Other income (Note 14)		4,488			1,786
Other expense (Note 14)		(1,934	)		(7,102	)
Total		4,751			(643	)
INTEREST EXPENSE
Interest charges		60,244			51,165
Capitalized interest		(1,423	)		(3,976	)
Total		58,821			47,189
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		290,441			228,060
INCOME TAXES		103,061			76,592
INCOME FROM CONTINUING OPERATIONS		187,380			151,468
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of ($848) and $81 (Note 17)		(1,310	)		118
NET INCOME		186,070			151,586
Less: Net loss attributable to noncontrolling interests		(582	)		—
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	186,652		$	151,586
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		101,223			100,750
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		101,385			101,018
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	1.86		$	1.50
Net income attributable to common shareholders — basic		1.84			1.50
Income from continuing operations attributable to common shareholders — diluted		1.85			1.50
Net income attributable to common shareholders — diluted		1.84			1.50
DIVIDENDS DECLARED PER SHARE	$	0.525		$	0.525
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	187,962		$	151,468
Discontinued operations, net of tax		(1,310	)		118
Net income attributable to common shareholders	$	186,652		$	151,586

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

3

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)

	Nine Months Ended
	September 30,
	2009			2008
OPERATING REVENUES
Regulated electricity segment	$	2,498,838		$	2,492,627
Real estate segment		80,333			62,165
Marketing and trading		—			57,623
Other revenues		30,084			26,824
Total		2,609,255			2,639,239
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		920,630			1,016,918
Real estate segment operations		76,893			83,822
Real estate impairment charge (Note 21)		247,509			—
Marketing and trading fuel and purchased power		—			44,129
Operations and maintenance		642,545			598,055
Depreciation and amortization		302,255			291,915
Taxes other than income taxes		101,126			94,826
Other expenses		22,214			21,081
Total		2,313,172			2,150,746
OPERATING INCOME		296,083			488,493
OTHER
Allowance for equity funds used during construction		11,919			16,211
Other income (Note 14)		4,452			9,489
Other expense (Note 14)		(8,887	)		(22,053	)
Total		7,484			3,647
INTEREST EXPENSE
Interest charges		174,985			157,371
Capitalized interest		(8,568	)		(14,593	)
Total		166,417			142,778
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		137,150			349,362
INCOME TAXES		45,307			91,154
INCOME FROM CONTINUING OPERATIONS		91,843			258,208
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of ($5,371) and $14,766 (Note 17)		(8,298	)		22,767
NET INCOME		83,545			280,975
Less: Net loss attributable to noncontrolling interests		(14,944	)		—
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	98,489		$	280,975
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		101,107			100,642
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		101,184			100,911
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	1.06		$	2.57
Net income attributable to common shareholders — basic		0.97			2.79
Income from continuing operations attributable to common shareholders — diluted		1.06			2.56
Net income attributable to common shareholders — diluted		0.97			2.78
DIVIDENDS DECLARED PER SHARE	$	1.575		$	1.575
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	106,787		$	258,208
Discontinued operations, net of tax		(8,298	)		22,767
Net income attributable to common shareholders	$	98,489		$	280,975

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

4

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
(dollars in thousands)

	September 30,			December 31,
	2009			2008
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	100,824		$	105,245
Customer and other receivables		383,694			292,682
Accrued utility revenues		156,509			100,089
Allowance for doubtful accounts		(3,955	)		(3,383	)
Materials and supplies (at average cost)		180,144			173,252
Fossil fuel (at average cost)		39,641			29,752
Deferred income taxes		58,640			79,729
Income tax receivable (Note 8)		167,747			—
Home inventory (Note 21)		7,881			50,688
Assets held for sale (Note 17)		6,273			—
Assets from risk management and trading activities (Note 10)		32,220			32,581
Other current assets		21,205			21,847
Total current assets		1,150,823			882,482
INVESTMENTS AND OTHER ASSETS
Real estate investments — net (Note 21)		150,253			415,296
Assets from risk management and trading activities (Note 10)		22,167			33,675
Nuclear decommissioning trust (Note 18)		399,808			343,052
Other assets		106,560			117,935
Total investments and other assets		678,788			909,958
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		12,636,322			12,264,805
Less accumulated depreciation and amortization		4,296,823			4,141,546
Net		8,339,499			8,123,259
Construction work in progress		540,991			572,354
Intangible assets, net of accumulated amortization		154,450			131,722
Nuclear fuel, net of accumulated amortization		126,767			89,323
Total property, plant and equipment		9,161,707			8,916,658
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		—			7,984
Other regulatory assets		726,883			787,506
Other deferred debits		113,022			115,505
Total deferred debits		839,905			910,995
TOTAL ASSETS	$	11,831,223		$	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)

	September 30,			December 31,
	2009			2008
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	208,134		$	261,029
Accrued taxes		156,667			109,798
Accrued interest		49,389			40,741
Short-term borrowings		142,252			670,469
Current maturities of long-term debt (Note 4)		148,677			177,646
Customer deposits		74,128			78,745
Liabilities from risk management and trading activities (Note 10)		50,976			69,585
Other current liabilities		124,213			97,915
Total current liabilities		954,436			1,505,928
LONG-TERM DEBT LESS CURRENT MATURITIES (NOTE 4)		3,519,934			3,031,603
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,542,402			1,403,318
Deferred fuel and purchased power regulatory liability (Note 5)		60,488			—
Other regulatory liabilities		668,567			587,586
Liability for asset retirements		289,921			275,970
Liabilities for pension and other postretirement benefits (Note 6)		726,756			675,788
Liabilities from risk management and trading activities (Note 10)		46,498			126,532
Customer advances		131,512			132,023
Coal mine reclamation		91,847			91,201
Unrecognized tax benefits		162,717			68,904
Other		210,982			227,872
Total deferred credits and other		3,931,690			3,589,194
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 11)
Common stock, no par value		2,149,465			2,151,323
Treasury stock		(3,811	)		(2,854	)
Total common stock		2,145,654			2,148,469
Retained earnings		1,381,547			1,444,208
Accumulated other comprehensive loss:
Pension and other postretirement benefits		(47,753	)		(47,547	)
Derivative instruments		(82,786	)		(99,151	)
Total accumulated other comprehensive loss		(130,539	)		(146,698	)
Total Pinnacle West shareholders’ equity		3,396,662			3,445,979
Noncontrolling real estate interests		28,501			47,389
Total equity		3,425,163			3,493,368
TOTAL LIABILITIES AND EQUITY	$	11,831,223		$	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)

	Nine Months Ended
	September 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	83,545		$	280,975
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		332,532			317,366
Deferred fuel and purchased power		(46,743	)		(104,774	)
Deferred fuel and purchased power amortization		115,214			157,999
Allowance for equity funds used during construction		(11,919	)		(16,211	)
Real estate impairment charge		260,450			—
Deferred income taxes		154,517			228,567
Change in mark-to-market valuations		(5,970	)		1,411
Changes in current assets and liabilities:
Customer and other receivables		(79,297	)		(40,195	)
Accrued utility revenues		(56,420	)		(50,843	)
Materials, supplies and fossil fuel		(16,781	)		(13,527	)
Other current assets		26,308			25,906
Accounts payable		(35,923	)		(10,571	)
Accrued taxes and income tax receivable-net		(120,878	)		22,136
Other current liabilities		25,808			44,153
Expenditures for real estate investments		(2,410	)		(17,397	)
Gains and other changes in real estate assets		(10,527	)		34,875
Change in unrecognized tax benefits		92,720			(107,069	)
Change in other regulatory liabilities		92,598			(4,397	)
Change in other long-term assets		(47,925	)		30,662
Change in other long-term liabilities		12,071			4,875
Net cash flow provided by operating activities		760,970			783,941
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(558,495	)		(707,685	)
Contributions in aid of construction		17,393			40,950
Capitalized interest		(8,568	)		(14,593	)
Proceeds from nuclear decommissioning trust sales		370,399			255,706
Investment in nuclear decommissioning trust		(386,743	)		(271,263	)
Proceeds from sale of commercial real estate investments		30,847			94,171
Other		(1,404	)		5,628
Net cash flow used for investing activities		(536,571	)		(597,086	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		867,582			88,550
Repayment and reacquisition of long-term debt		(414,474	)		(179,796	)
Short-term borrowings and payments — net		(528,217	)		100,886
Dividends paid on common stock		(153,740	)		(158,477	)
Common stock equity issuance		2,623			8,165
Other		(2,594	)		2,024
Net cash flow used for financing activities		(228,820	)		(138,648	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(4,421	)		48,207
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		105,245			56,321
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	100,824		$	104,528
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	(34,700	)	$	202
Interest, net of amounts capitalized	$	153,725		$	136,996

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, APS Energy Services Company, Inc. (“APSES”), El Dorado Investment Company (“El Dorado”) and Pinnacle West Marketing & Trading Co., LLC. By the end of 2008, substantially all of Pinnacle West Marketing & Trading Co., LLC’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 accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In preparing the accompanying unaudited condensed consolidated financial statements, we have evaluated subsequent events that have occurred after September 30, 2009 through the date the financial statements were issued on October 29, 2009.

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 financial 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 and Condensed Consolidated Balance Sheets in accordance with accounting requirements for reporting discontinued operations (see Note 17), and amended accounting guidance on reporting noncontrolling interests in consolidated financial statements (see Note 19). We have also presented certain line items in more detail in the Condensed Consolidated Balance Sheets than was presented at December 31, 2008. The prior year amounts were reclassified to conform to the current year presentation. Customer advances for construction, coal mine reclamation and unrecognized tax benefits are presented as separate line items instead of the previously reported single line item of other deferred credits.

Certain line items are presented in more detail on the Condensed Consolidated Statement of Cash Flows than was presented in the prior year. Other line items are more condensed than the previous presentation. The prior year amounts were reclassified to conform to the current year presentation. Customer and other receivables and accrued utility revenues are presented as separate line items instead of the previously reported single line item of customer and other receivables. Accrued taxes and income tax receivable-net and other current liabilities are presented as separate line items instead of the previously reported single line item of other current liabilities. Change in other regulatory liabilities is reported separately from change in other long-term liabilities. The change in collateral and margin account — assets and the change in other long-term assets are presented as a single line item of changes in other long-term assets. These reclassifications had no impact on total net cash flow provided by operating activities.

8

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3. Quarterly Fluctuations

Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate activities, such as the real estate impairment charges recorded in 2009 (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 September 30, 2009 (dollars in millions):

	Consolidated
Year	Pinnacle West		APS
2009	$	11	$	—
2010		285		197
2011		618		428
2012		446		446
2013		34		32
Thereafter		2,282		2,282
Total	$	3,676	$	3,385

Credit Facilities and Debt Issuances

The credit and liquidity markets experienced significant stress beginning the third quarter of 2008. Since the fourth quarter of 2008, Pinnacle West and APS have not accessed the commercial paper market due to negative market conditions. They have both been able to access existing credit facilities, ensuring adequate liquidity.

Pinnacle West

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 September 30, 2009, the parent company had outstanding $138 million of borrowings under its revolving credit facility and no letters of credit.

APS

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 or to be used for bank borrowings, including issuances of letters of credit up to $583 million. At September 30, 2009, APS had no borrowings and no letters of credit under its revolving lines of credit.

9

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2009, APS’ common equity ratio, as defined, was 51%. Its total common equity was approximately $3.5 billion, and total capitalization was approximately $6.9 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.7 billion, assuming APS’ total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

SunCor

SunCor’s principal loan facility (the “SunCor Secured Revolver”) matures in January 2010 and requires SunCor to reduce its outstanding borrowings by specified amounts over the term of the facility. As of September 30, 2009, approximately $72 million of borrowings were outstanding under the SunCor Secured Revolver and approximately $49 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 repayment of the SunCor Secured Revolver and SunCor’s other outstanding debt. The impairment charges discussed in Note 21 resulted in violations of certain covenants contained in the SunCor Secured Revolver and SunCor’s other credit facilities. The lenders have taken no enforcement action related to the covenant defaults, and SunCor is current on all of its debt payment obligations under the SunCor Secured Revolver and its other credit facilities. SunCor remains in discussions with its lenders to modify or replace the SunCor Secured Revolver to resolve the covenant defaults and extend the principal repayment provisions and the January 2010 maturity date. If SunCor is unable to obtain additional extensions, modifications, waivers or similar relief from its lenders, or is unable to comply with the provisions of any new or modified agreements, SunCor could be required to 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. While there can be no assurances as to the ultimate outcome of this matter, Pinnacle West does not believe that SunCor’s inability to obtain waivers or similar relief from SunCor’s lenders would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

As of September 30, 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.

10

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pollution Control Bonds

During 2009, APS refinanced approximately $343 million of its $566 million variable rate pollution control bonds. As a result of these refinancings, which are described in the following table, APS no longer has any outstanding debt securities in auction rate mode. Each series of bonds, described below, is payable solely from revenues obtained from APS pursuant to a loan agreement between APS and the respective pollution control corporation. We will be required to purchase the bonds at the applicable interest reset dates and have the opportunity to remarket the bonds at that time. These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets.

	Navajo County, AZ	Coconino County, AZ	Maricopa County, AZ
	Pollution Control	Pollution Control	Pollution Control
Issuer	Corporation (1)	Corporation (2)	Corporation (3)
Issuance Date	May 28, 2009	May 28, 2009	June 26, 2009
Due Date	June 1, 2034	June 1, 2034	May 1, 2029
Bond series details (series, fixed interest rate, amount, reset date)	Series A — 5.00% $38 million June 1, 2012	Series A — 5.50% $13 million June 1, 2014	Series A — 6.00% $36 million May 1, 2014
	Series B — 5.50% $32 million June 1, 2014		Series B — 5.50% $32 million May 1, 2012
	Series C — 5.50% $32 million June 1, 2014		Series C — 5.75% $32 million May 1, 2013
	Series D — 5.75% $32 million June 1, 2016		Series D — 6.00% $32 million May 1, 2014
	Series E — 5.75%, $32 million June 1, 2016		Series E — 6.00% $32 million May 1, 2014
Total	$166 million	$13 million	$164 million

(1)	Issued to redeem all of approximately $166 million of the Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds 2004 Series A-E, due 2034.
(2)	Issued to redeem all of approximately $13 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds 2004 Series A, due 2034.
(3)	Issued to redeem all of approximately $164 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds 2005 Series A-E, due 2029.

On September 11, 2008, APS purchased all of the approximately $27 million of the Coconino County, Arizona Pollution Control Corporation (“Coconino”) Pollution Control Revenue Bonds, Series 1996A and Series 1999 due December 2031 and April 2034 and held them as treasury bonds. On September 22, 2009, Coconino issued approximately $27 million of Coconino Pollution Control Revenue Refunding Bonds, 2009 Series B due April 2038 to redeem the existing bonds. APS used the funds received from the issuance to repay certain existing indebtedness under a revolving line of credit drawn upon by APS to fund its purchase of the 1996A and 1999 Series Bonds in 2008. The 2009 Series B Bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Coconino. According to the indenture of the bonds, the interest rate of the 2009 Series B Bonds could be reset daily, weekly, monthly, or at other time intervals. The initial rate period selected for the 2009 Series B Bonds is a daily rate period. At September 30, 2009, the daily interest rate was 0.35%. The daily rates are variable rates set by a remarketing agent. Concurrently with the issuance of the 2009 Series B Bonds, the Company entered into a two year letter of credit and reimbursement agreement to provide credit support for the 2009 Series B Bonds.

11

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 power supply adjustor (“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.

Proposed Settlement Agreement and Related Hearing — APS and other parties to the rate case began settlement discussions on January 30, 2009. On June 12, 2009, they entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have agreed to settle the rate case and which requires ACC approval. The ACC conducted an evidentiary hearing on the matter which concluded September 18, 2009 and the parties filed reply briefs in mid-October. Following the Administrative Law Judge’s (“ALJ”) issuance of a recommended order, the ACC will hold an open meeting, which is currently scheduled for December 7-11, in order to reach a final decision on this matter. These dates are subject to change by the ACC. If the Settlement Agreement is approved by the ACC, APS expects that its provisions, including the new rates, would become effective on or about January 1, 2010. At this time, APS cannot predict whether the ACC will approve the Settlement Agreement or, if approved, what conditions or changes to the agreement the ACC may require.

The Settlement Agreement includes a net retail rate increase of $207.5 million, which represents a base rate increase of $344.7 million less the reclassification of $137.2 million of fuel and purchased power revenues from the existing PSA to base rates.

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

12

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Other key provisions of the Settlement Agreement include the following:

• A non-fuel base rate increase in annual pretax revenues of $196.3 million, which would 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 that would not otherwise have been recoverable under the PSA;

• A Base Fuel Rate (the portion of APS’ retail base rates attributable to fuel and purchased power costs) of $0.0376 per kilowatt-hour (“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 from January 1, 2010 through year end 2012 (or until new rates are established in APS’ next general rate case, if that is before the end of 2012), resulting in present estimates of increased revenues of $23 million, $25 million and $49 million, respectively;

• An authorized return on common equity of 11.0%;

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

• A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (an increase of $10 million above the $20 million required reductions for 2009 ordered by the ACC in its interim rate decision in this matter);

• Equity infusions into APS of at least $700 million during the period beginning June 1, 2009 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, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.

Energy Efficiency, Demand-Side Management and Renewable Energy Programs

In 2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (the “RES”). Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include an RES surcharge on customer bills to recover the approved amounts for use on renewable energy projects. On July 1, 2009, APS filed its annual RES implementation plan with the ACC, which covers the 2010-2014 timeframe and requests approval for RES funding of $85.5 million for 2010. We filed a revised RES implementation plan on October 16, 2009, increasing our total requested RES funding to $86.7 million for 2010. We expect to receive a determination from the ACC on this matter by the end of 2009.

13

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan in compliance with certain provisions of the Settlement Agreement. APS is requesting approval by the ACC of programs and program elements for which APS has estimated a budget in the amount of $49.9 million for 2010. The Plan is also contingent upon ACC approval of the Settlement Agreement. In order to recover these estimated amounts for use on certain demand-side management programs, a surcharge would be added to customer bills similar to that described above under the RES. The surcharge will offset energy efficiency expenses and allow for the recovery of any earned incentives. We expect to receive a determination from the ACC on this matter simultaneously with its decision on the Settlement Agreement.

PSA Balance

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for the nine-month period ended September 30, 2009 and 2008 (dollars in millions):

	Nine Months Ended
	September 30,
	2009			2008
Beginning balance	$	8		$	111
Deferred fuel and purchased power costs-current period		47			103
Interest on deferred fuel and purchased power		—			2
Amounts recovered through revenues		(115	)		(158	)
Ending balance	$	(60	)	$	58

The PSA is the 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. 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 or decreased more than $0.004 per kWh in a year without permission of the ACC. The $60 million regulatory liability at September 30, 2009 reflects lower average prices and the seasonal nature of fuel and purchased power costs. We expect to have overcollected fuel cost deferrals during the 2009 PSA Year that will be refunded through the historical component of the PSA rate for the PSA Year beginning February 1, 2010. If the proposed Settlement Agreement is approved, APS anticipates this reset would occur January 1, 2010.

Formula Transmission Tariff

In July 2008, the United States Federal Energy Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect the costs that APS incurs in providing transmission services. 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 customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with, and obtain approval from, the ACC under the transmission cost adjustor (“TCA”) mechanism, by which changes in Retail Transmission Charges can be reflected in APS’ retail rates.

14

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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 Settlement Agreement, APS would be authorized and obligated to obtain equity infusions of up to $700 million during the period beginning June 1, 2009 through December 31, 2014, and such authorization would replace the $400 million authorization described in this paragraph.

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.

15

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Pension Benefits												Other Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2009			2008			2009			2008			2009			2008			2009			2008
Service cost — benefits earned during the period	$	13		$	13		$	40		$	39		$	4		$	4		$	14		$	13
Interest cost on benefit obligation		29			27			88			83			10			8			29			28
Expected return on plan assets		(29	)		(30	)		(87	)		(89	)		(9	)		(10	)		(26	)		(32	)
Amortization of:
Transition obligation		—			—			—			—			1			1			2			2
Prior service cost		1			1			2			2			—			—			—			—
Net actuarial loss		4			3			11			8			3			1			8			2
Net periodic benefit cost	$	18		$	14		$	54		$	43		$	9		$	4		$	27		$	13
Portion of cost charged to expense	$	9		$	6		$	26		$	19		$	4		$	2		$	13		$	6
APS’ share of cost charged to expense	$	8		$	6		$	25		$	18		$	4		$	2		$	12		$	5

Contributions

In the first quarter of 2009, United States Internal Revenue Service (“IRS”) regulations were modified to allow alternative measurement dates to determine the interest rate used to value the year-end 2008 pension liability for funding purposes. As a result of this change, we estimate our 2009 minimum pension contribution to be zero. 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 97% of the qualified defined benefit and account balance pension plan and other postretirement benefit 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 electric service to retail and wholesale customers supplied under traditional cost-based rate regulation (“Native Load”)) 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.

16

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Financial data for the three and nine months ended September 30, 2009 and 2008 and at September 30, 2009 and December 31, 2008 is provided as follows (dollars in millions):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Operating revenues:
Regulated electricity segment	$	1,084		$	1,040		$	2,499		$	2,493
Real estate segment		48			16			80			62
All other (a)		11			14			30			84
Total	$	1,143		$	1,070		$	2,609		$	2,639
Net income (loss) attributable to common shareholders:
Regulated electricity segment	$	200		$	158		$	257		$	273
Real estate segment		(12	)		(6	)		(153	)		8
All other (a)		(1	)		—			(6	)		—
Total	$	187		$	152		$	98		$	281

	As of		As of
	September 30, 2009		December 31, 2008
Assets:
Regulated electricity segment	$	11,509	$	10,951
Real estate segment		189		523
All other (a)		133		146
Total	$	11,831	$	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

Pinnacle West expects to recognize approximately $117 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 $97 million of these benefits were recorded in the nine months ended September 30, 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.

The $168 million income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated cash refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009 and the expected tax benefits related to the SunCor strategic asset sales that closed in 2009.

As of September 30, 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.

For the nine months ended September 30, 2009, unrecognized tax benefits increased $94 million as a result of tax positions taken in prior periods.

17

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. Variable-Interest Entities

In 1986, APS entered into agreements with three separate variable-interest entity (“VIE”) lessors in order to sell and lease back interests in Palo Verde Nuclear Generating Station (“Palo Verde”) Unit 2. The leases are accounted for as operating leases. 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 United States Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to 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 September 30, 2009, APS would have been required to assume approximately $167 million of debt and pay the equity participants approximately $161 million. See Note 15 for a discussion of letters of credit that support certain lessors in the Palo Verde sale leaseback transactions.

SunCor is the primary beneficiary of certain land development arrangements and, accordingly, consolidates the 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 September 30, 2009 and December 31, 2008.

In addition, see Note 19 for a discussion of the pending adoption of amended accounting guidance relating to VIEs.

10. Derivative and Energy Trading Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. Derivative instruments that are designated as cash flow hedges are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We may also invest in derivative instruments for trading purposes; however, for the nine months ended September 30, 2009, there was no material trading activity.

Our derivative instruments are accounted for at fair value; see Note 20 for a discussion of fair value measurements. On January 1, 2009, we adopted amended accounting guidance that required enhanced disclosures about derivative instruments and hedging activities. The adoption of this guidance did not have a material impact on our financial statements.

18

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Derivative instruments for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales scope exception and are accounted for under the accrual method of accounting. Due to the scope exception, these derivative instruments are excluded from our derivative instrument discussion and disclosures below.

We enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, some of these instruments may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Economic hedges not designated as accounting hedges are recorded at fair value on our balance sheet with changes in fair value recognized in the statement of income as incurred. These instruments are included in the “non-designated hedges” discussion and disclosure below.

Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value between the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of accumulated other comprehensive income (“AOCI”) and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As of September 30, 2009, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

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

For its regulated operations, APS defers for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate. Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of September 30, 2009, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power	13,113,421 megawatt hours
Gas	174,919,500 MMBTU (a)

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

19

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Derivative Instruments in Designated Accounting Hedging Relationships

The following table provides information about gains and losses from derivative instruments in designated accounting hedging relationships and their impact on our Condensed Consolidated Statements of Income during the three and nine months ended September 30, 2009 (dollars in thousands):

	Financial Statement	Three Months Ended			Nine Months Ended
Commodity Contracts	Location	September 30, 2009			September 30, 2009
Amount of Gain (Loss) Recognized in AOCI on Derivative Instruments (Effective Portion)	Accumulated other comprehensive loss-derivative instruments	$	4,959		$	(128,035	)
Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)	Regulated electricity segment fuel and purchased power		(81,660	)		(154,990	)
Amount of Loss Recognized in Income from Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)	Regulated electricity segment fuel and purchased power		(9,085	)		(12,993	)

(a) During the nine months ended September 30, 2009 we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.

During the next twelve months, we estimate that a net loss of $76 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, certain of these amounts will be recorded as either a regulatory asset or liability and have no effect on earnings.

20

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Derivative Instruments Not Designated as Accounting Hedges

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments and their impact on our Condensed Consolidated Statements of Income during the three and nine months ended September 30, 2009 (dollars in thousands):

		Three Months Ended		Nine Months Ended
Commodity Contracts	Financial Statement Location	September 30, 2009		September 30, 2009
Amount of Gain Recognized in Income from Derivative Instruments	Regulated electricity segment revenue	$	126	$	464
Amount of Gain (Loss) Recognized in Income from Derivative Instruments	Regulated electricity segment fuel and purchased power expense		23,463		(18,259	)
Total		$	23,589	$	(17,795	)

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 September 30, 2009 (dollars in thousands):

				Investments						Deferred Credits			Total Assets
Commodity Contracts	Current Assets			and Other Assets			Current Liabilities			and Other			(Liabilities)
Derivatives designated as accounting hedging instruments:
Assets	$	373		$	—		$	8,849		$	1,138		$	10,360
Liabilities		(3,783	)		(573	)		(76,925	)		(64,460	)		(145,741	)
Total hedging instruments		(3,410	)		(573	)		(68,076	)		(63,322	)		(135,381	)
Derivatives not designated as accounting hedging instruments:
Assets		26,983			22,892			40,806			39,617			130,298
Liabilities		(3,525	)		(152	)		(111,265	)		(70,362	)		(185,304	)
Total non-hedging instruments		23,458			22,740			(70,459	)		(30,745	)		(55,006	)
Total derivatives		20,048			22,167			(138,535	)		(94,067	)		(190,387	)
Margin account		8,798			—			23,466			547			32,811
Collateral provided to counterparties		3,587			—			64,901			47,022			115,510
Collateral provided from counterparties		—			—			(750	)		—			(750	)
Prepaid option premiums		(213	)		—			(58	)		—			(271	)
Balance Sheet Total	$	32,220		$	22,167		$	(50,976	)	$	(46,498	)	$	(43,087	)

21

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Derivative instrument 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.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which our exposure represents approximately 41% of Pinnacle West’s $54 million of risk management and trading assets as of September 30, 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’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on September 30, 2009 was $290 million for which we had posted collateral of $116 million in the normal course of business.

For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt were to fall below investment grade (below BBB- for Standard & Poor’s Ratings Services (“S&P”) or Fitch, Inc. (“Fitch”) or Baa3 for Moody’s Investors Services, Inc. (“Moody’s”)), which would be a violation of the credit rating provisions. If the investment grade contingent features underlying these agreements had been triggered on September 30, 2009, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $80 million of collateral to our counterparties; this amount includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the above footnote. We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features which could also require us to post additional collateral of approximately $200 million if our debt were to fall below investment grade.

22

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

11. Changes in Equity

The following tables show Pinnacle West’s changes in common stock equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2009 and 2008 (dollars in thousands):

	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
	Common			Noncontrolling						Common			Noncontrolling
	Shareholders			Interests			Total			Shareholders			Interests			Total
Beginning balance, June 30	$	3,206,805		$	29,168		$	3,235,973		$	3,747,813		$	53,865		$	3,801,678
Net income (loss)		186,652			(582	)		186,070			151,586			—			151,586
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		4,959			—			4,959			(348,207	)		—			(348,207	)
Net reclassification of realized (gains) losses to income (b)		81,660			—			81,660			(43,718	)		—			(43,718	)
Reclassification of pension and other postretirement benefits to income		1,240			—			1,240			1,175			—			1,175
Income tax (expense) benefit related to items of other comprehensive income		(34,495	)		—			(34,495	)		153,043			—			153,043
Total other comprehensive income (loss)		53,364			—			53,364			(237,707	)		—			(237,707	)
Total comprehensive income (loss)		240,016			(582	)		239,434			(86,121	)		—			(86,121	)
Issuance of capital stock		2,756			—			2,756			2,603			—			2,603
Purchase of treasury stock, net of reissuances		589			—			589			545			—			545
Other (primarily stock compensation)		(372	)		(85	)		(457	)		1,030			(186	)		844
Common stock dividends		(53,132	)		—			(53,132	)		(52,885	)		—			(52,885	)
Net capital activities by noncontrolling interests		—			—			—			—			(8,006	)		(8,006	)
Ending balance, September 30	$	3,396,662		$	28,501		$	3,425,163		$	3,612,985		$	45,673		$	3,658,658

23

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 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)		98,489			(14,944	)		83,545			280,975			—			280,975
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		(128,035	)		—			(128,035	)		12,584			—			12,584
Net reclassification of realized (gains) losses to income (b)		154,990			—			154,990			(82,488	)		—			(82,488	)
Reclassification of pension and other postretirement benefits to income		3,745			—			3,745			3,522			—			3,522
Net unrealized losses related to pension and other postretirement benefits		(4,204	)		—			(4,204	)		(10,595	)		—			(10,595	)
Income tax (expense) benefit related to items of other comprehensive income		(10,337	)		—			(10,337	)		30,218			—			30,218
Total other comprehensive income (loss)		16,159			—			16,159			(46,759	)		—			(46,759	)
Total comprehensive income (loss)		114,648			(14,944	)		99,704			234,216			—			234,216
Issuance of capital stock		8,102			—			8,102			8,165			—			8,165
Purchase of treasury stock, net of reissuances		(957	)		—			(957	)		(800	)		—			(800	)
Other (primarily stock compensation)		(11,899	)		(255	)		(12,154	)		(1,730	)		(890	)		(2,620	)
Common stock dividends		(159,211	)		—			(159,211	)		(158,477	)		—			(158,477	)
Net capital activities by noncontrolling interests		—			(3,689	)		(3,689	)		—			(8,006	)		(8,006	)
Ending balance, September 30	$	3,396,662		$	28,501		$	3,425,163		$	3,612,985		$	45,673		$	3,658,658

(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.

24

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the United States Department of Energy (“DOE”), and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE 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, and closing arguments were heard in late May. The court has not indicated when it will reach its decision in the matter.

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 September 30, 2009, APS had a regulatory liability of $31 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Purchased Power and Fuel Commitments

APS is party to various purchased power and fuel contracts that include required purchase provisions. APS estimates the contract requirements to be approximately $529 million in 2009; $409 million in 2010; $337 million in 2011; $351 million in 2012; $435 million in 2013; and $6.8 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. These amounts have increased since the 2008 Form 10-K; however, these amounts are less than those reported in the Pinnacle West/APS Quarterly Report on Form 10-Q for the period ended June 30, 2009 (“Second Quarter Form 10-Q”) due to the termination by Starwood Solar I, LLC of our contingent renewable purchased power agreement with them for a 290 MW solar project.

Renewable Energy Credits

APS has entered into contracts to purchase renewable energy credits to comply with the Renewable Energy Standard. APS estimates the contract requirements to be approximately $7 million in 2010; $11 million in 2011; $11 million in 2012; $11 million in 2013; and $126 million thereafter. These amounts have increased since the 2008 Form 10-K.

25

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

Superfund

The Comprehensive Environmental Response, Compensation and Liability Act (“Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties (“PRP”) under Superfund. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, the United States Environmental Protection Agency (“EPA”) advised APS that the EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with the EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $1.2 million, which is reserved as a liability on our financial statements. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time we cannot accurately estimate our total expenditures.

26

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Landlord Bankruptcy

On April 16, 2009, the landlord for our corporate headquarters building announced that it is seeking relief under Chapter 11 of the United States Bankruptcy Code. We currently have several assets on our books related to our landlord, the most significant of which is an asset related to rent payments for the building of approximately $65 million. This amount will continue to increase to approximately $94 million as a result of the lease terms until 2015 when this amount will begin to decrease over the remaining life of the lease. We are monitoring this matter and, while there can be no assurances as to the ultimate outcome of the matter due to the complexity of the bankruptcy proceedings, we currently do not expect that it will have a material adverse effect on our financial position, results of operations, or cash flows.

Litigation

We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including environmental matters related to the Clean Air Act, as amended (“Clean Air Act”), Navajo Nation issues and EPA and Arizona Department of Environmental Quality (“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.

13. Nuclear Insurance

The Palo Verde participants are insured against public liability for a nuclear incident up to $12.5 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, Palo Verde maintains the maximum available nuclear liability insurance in the amount of $300 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $19 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $52 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

27

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. Other Income and Other Expense

The following table provides detail of other income and other expense for the three and nine months ended September 30, 2009 and 2008 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Other income:
Interest income	$	556		$	1,082		$	1,214		$	6,559
Investment gains – net		3,696			—			120			—
SunCor other income (a)		89			222			321			1,786
Miscellaneous		147			482			2,797			1,144
Total other income	$	4,488		$	1,786		$	4,452		$	9,489
Other expense:
Non-operating costs	$	(1,643	)	$	(2,211	)	$	(6,498	)	$	(8,554	)
Investment losses – net		—			(4,683	)		—			(12,883	)
Miscellaneous		(291	)		(208	)		(2,389	)		(616	)
Total other expense	$	(1,934	)	$	(7,102	)	$	(8,887	)	$	(22,053	)

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

15. Guarantees

We have issued parental guarantees and 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, which primarily relate 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 September 30, 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 September 30, 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		19		1
Total	$	15			$	37

28

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS has entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2009, approximately $227 million of letters of credit were outstanding to support existing pollution control bonds of approximately $224 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $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.

29

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

16. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2009			2008		2009			2008
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	1.86		$	1.50	$	1.06		$	2.57
Income (loss) from discontinued operations		(0.02	)		—		(0.09	)		0.22
Earnings per share – basic	$	1.84		$	1.50	$	0.97		$	2.79
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	1.85		$	1.50	$	1.06		$	2.56
Income (loss) from discontinued operations		(0.01	)		—		(0.09	)		0.22
Earnings per share – diluted	$	1.84		$	1.50	$	0.97		$	2.78

Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding – diluted by approximately 162,000 shares and 268,000 shares for the three months ended September 30, 2009 and 2008, respectively, and by approximately 77,000 shares and 269,000 shares for the nine months ended September 30, 2009 and 2008, respectively.

Options to purchase 561,157 shares of common stock for the three-month period and 595,335 shares for the nine-month period ended September 30, 2009 were outstanding but were excluded from the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase 679,000 shares of common stock for the three-month period and 600,778 shares for the nine-month period ended September 30, 2008 were outstanding but were excluded from the computation of diluted earnings per share because the options’ exercise prices were higher than the average market price of the common shares.

17. Discontinued Operations

SunCor (real estate segment) – In 2008 and 2009, 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. Prior year income statement amounts related to these properties were reclassified from operations to discontinued operations. Our September 30, 2009 Condensed Consolidated Balance Sheet includes $6 million of assets held for sale. These assets were classified as real estate investments 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.

30

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2009 and 2008 (dollars in millions):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Revenue:
SunCor	$	1		$	4		$	5		$	42
APSES		—			7			—			63
Total revenue	$	1		$	11		$	5		$	105
Income (loss) before taxes:
SunCor	$	(2	)	$	2		$	(14	)	$	40
APSES		—			(2	)		—			(3	)
Total income before taxes	$	(2	)	$	—		$	(14	)	$	37
Income (loss) after taxes:
SunCor	$	(1	)	$	1		$	(8	)	$	25
APSES		—			(1	)		—			(2	)
Total income after taxes (a)	$	(1	)	$	—		$	(8	)	$	23

(a) Includes a tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of $1 million for the three months ended September 30, 2009, and $6 million for the nine months ended September 30, 2009.

18. Nuclear Decommissioning Trust

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income securities and domestic equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have recorded the offsetting amount of gains or losses on investment securities in other regulatory liabilities or assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at September 30, 2009 and December 31, 2008 (dollars in millions):

			Total		Total
			Unrealized		Unrealized
	Fair Value		Gains		Losses
September 30, 2009
Equity securities	$	152	$	31	$	(9	)
Fixed income securities		246		14		—
Net payables (a)		2		—		—
Total	$	400	$	45	$	(9	)

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

31

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

			Total		Total
			Unrealized		Unrealized
	Fair Value		Gains		Losses
December 31, 2008
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						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Realized gains	$	3		$	—		$	8		$	2
Realized losses		(1	)		(2	)		(6	)		(4	)
Proceeds from the sale of securities (a)		126			67			370			256

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2009 is as follows (dollars in millions):

	Fair Value
Less than one year	$	14
1 year – 5 years		69
5 years – 10 years		61
Greater than 10 years		102
Total	$	246

See Note 20 for a discussion of fair value measurements.

19. New Accounting Standards

See Note 20 for a discussion of fair value measurements and disclosures, 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 the amended guidance on disclosures about derivative instruments and hedging activities. We adopted this amended disclosure guidance on January 1, 2009.

32

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We adopted amended guidance on reporting noncontrolling interests in consolidated financial statements 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 Condensed Consolidated Balance Sheets. Prior year’s net income attributable to noncontrolling interests was not material to our Condensed Consolidated Statements of Income and was not reclassified. The adoption of this guidance modified our financial statement presentation, but did not have an impact on our financial statement results.

On January 1, 2009, we adopted accounting guidance on determining whether instruments granted in share-based payment transactions are participating securities. This guidance 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. Our awards do not have nonforfeitable rights to dividends or dividend equivalents and, therefore, the adoption of this guidance did not have any impact on our financial statements.

On April 1, 2009, we adopted new accounting provisions on topics described below. The adoption of these new accounting provisions did not have a material impact on our financial statements. See Note 20 for a discussion of fair value measurements.

• 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.

• The recognition and presentation of other-than-temporary impairments.

• Interim disclosures about fair value of financial instruments.

In May 2009, the Financial Accounting Standards Board (“FASB”) issued guidance which established general standards of accounting for and disclosure of subsequent events. Subsequent events are events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this guidance during the second quarter of 2009. The adoption of this guidance did not have a material impact on our financial statements.

In June 2009, the FASB issued the FASB accounting standards codification and the hierarchy of generally accepted accounting principles. This guidance establishes the FASB Accounting Standards Codification as the source of authoritative accounting principles recognized by the FASB to be applied by entities in the preparation of financial statements in conformity with GAAP. We adopted this guidance during the third quarter of 2009. The adoption of this provision modifies how we reference and research accounting guidance, but did not have a material impact on our financial statements.

In December 2008, the FASB issued guidance on employers’ disclosures about postretirement benefit plan assets. This guidance requires enhanced employers’ 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 the adoption of this guidance will have a material impact on our financial statements.

33

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In June 2009, the FASB issued amended guidance on the consolidation of variable interest entities. This amended guidance is intended to improve financial reporting and provide more relevant and reliable information by enterprises involved with variable interest entities. This guidance is effective for us on January 1, 2010. We are currently evaluating this new guidance and the impact it may have on our financial statements.

The FASB recently issued amended guidance relating to fair value measurements, as described below. We will adopt these new accounting provisions during the fourth quarter of 2009. We do not expect the adoption of these provisions to have a material impact on our financial statements.

• Measuring fair value of liabilities, which provides additional guidance on how fair value measurements of liabilities should be determined.

• Measuring fair value of certain alternative investments. This guidance provides clarification on the measurement and disclosure of investments in entities that calculate net asset value.

20. Fair Value Measurements

We disclose the fair value of certain assets and liabilities according to a fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

Level 1 – Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes our derivative instruments that are exchange-traded such as futures, cash equivalents invested in exchange-traded money market funds, and nuclear decommissioning trust investments in Treasury securities.

Level 2 – Quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable. Derivative instruments in this category include nonexchange-traded contracts such as forwards, options, and swaps. This category also includes our nuclear decommissioning trust assets in bonds and commingled equity funds. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market transactions, or we can determine that the inputs the broker used to arrive at the quoted price are observable. Quarterly and calendar year quotes from independent brokers are converted into monthly prices using historical relationships.

Level 3 – Model-derived valuations with unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where models are required due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.

34

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We maximize the use of observable inputs and minimize the use of unobservable inputs. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.

For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.

The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

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.

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 nuclear decommissioning trust invests in fixed income securities directly and equity securities indirectly through commingled funds. The commingled equity funds are valued based on the fund’s net asset value (“NAV”) and are classified within Level 2. Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. The trust fund investments have been established to satisfy APS’ nuclear decommissioning obligations (see Note 18).

35

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The trust fund investments have been established to satisfy APS’ nuclear decommissioning obligations (see Note 18).

The following table presents the fair value at September 30, 2009 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices			Significant
	in Active			Other			Significant
	Markets for			Observable			Unobservable			Counterparty			Balance at
	Identical Assets			Inputs			Inputs			Netting & Other			September 30,
	(Level 1)			(Level 2)			(Level 3)			(a)			2009
Assets
Cash equivalents	$	49		$	—		$	—		$	—		$	49
Risk management and trading activities		7			95			38			(86	)		54
Nuclear decommissioning trust:
US Treasury debt securities		63			—			—			—			63
Commingled equity funds		—			152			—			—			152
Corporate debt securities		—			53			—			—			53
Mortgage-backed securities		—			48			—			—			48
Municipality debt securities		—			45			—			—			45
Other		—			37			—			2			39
Total	$	119		$	430		$	38		$	(84	)	$	503
Liabilities
Risk management and trading activities	$	(31	)	$	(248	)	$	(51	)	$	233		$	(97	)

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

36

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 (dollars in millions):

	Quoted Prices			Significant
	in Active			Other			Significant
	Markets for			Observable			Unobservable			Counterparty			Balance at
	Identical Assets			Inputs			Inputs			Netting & Other			December 31,
	(Level 1)			(Level 2)			(Level 3)			(a)			2008
Assets
Cash equivalents	$	75		$	—		$	—		$	—		$	75
Risk management and trading activities		31			76			51			(92	)		66
Nuclear decommissioning trust:
US Treasury debt securities		33			—			—			—			33
Commingled equity funds		—			113			—			—			113
Corporate debt securities		—			33			—			—			33
Mortgage-backed securities		—			73			—			—			73
Municipality debt securities		—			67			—			—			67
Other		—			22			—			2			24
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.

37

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and nine months ended September 30, 2009 and 2008 (dollars in millions):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Net derivative balance at beginning of period	$	(16	)	$	7		$	(7	)	$	8
Total net gains (losses) realized/unrealized:
Included in earnings (a)		1			31			3			12
Included in OCI		(2	)		(11	)		(3	)		2
Deferred as a regulatory asset or liability		6			(37	)		12			(42	)
Purchases, issuances, and settlements		(4	)		—			(1	)		—
Level 3 transfers (b)		2			(10	)		(17	)		—
Net derivative balance at end of period	$	(13	)	$	(20	)	$	(13	)	$	(20	)
Net unrealized losses included in earnings related to instruments still held at end of period	$	1		$	23		$	3		$	41

(a)	Earnings are recorded in regulated electricity segment revenue or regulated electricity segment fuel and purchased power.
(b)	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.

The following table represents the carrying amount and estimated fair value of our debt which is not carried at fair value on the balance sheet. The carrying value of our cash, net accounts receivable, accounts payable and short-term borrowings approximate fair value. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. Our debt fair value estimates are based on quoted market prices of the same or similar issues (dollars in millions):

	As of				As of
	September 30, 2009				December 31, 2008
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Pinnacle West	$	175	$	178	$	175	$	169
APS		3,378		3,498		2,851		2,466
SunCor		116		116		183		183
Total	$	3,669	$	3,792	$	3,209	$	2,818

38

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We adopted guidance on fair value measurements and disclosures, for our nonfinancial assets and liabilities on January 1, 2009, and it did not have a material impact on our financial statements. We apply nonrecurring fair value measurements to certain real estate assets. These adjustments to fair value are the result of write-downs of individual assets due to impairment. Certain of our real estate assets have been impaired due to the distressed real estate market. We determine fair value for our real estate assets primarily based on the future cash flows that we estimate will be generated by each asset discounted for market risk. These fair value determinations require significant judgment regarding key assumptions. Due to these unobservable inputs, the valuation of real estate assets are considered Level 3 measurements.

As of September 30, 2009, the fair value of our impaired real estate assets that are measured at fair value on a nonrecurring basis was $85 million, all of which was valued using significant unobservable inputs (Level 3). Total impairment charges included in net income for the quarter ended September 30, 2009 were approximately $38 million and $260 million for the nine months ended September 30, 2009 (including net loss attributable to noncontrolling interests of $14 million before income taxes). See Note 21 for additional information.

21. Real Estate Impairment Charge

During the first quarter of 2009, SunCor undertook and completed a review of its assets and strategies within its various markets as a result of the then current and anticipated continuing distressed conditions in real estate and credit markets. Based on the results of the review, on March 27, 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce SunCor’s outstanding debt. This resulted in a pretax impairment charge of approximately $202 million, or $123 million after income taxes, in the first quarter of 2009. During the second and third quarters of 2009, SunCor reassessed market conditions and recorded additional pretax impairment charges of approximately $6 million and $38 million, or $4 million and $23 million after income taxes, respectively. Of the total $246 million impairment charge for the nine months ended September 30, 2009, approximately $13 million related to assets held for sale and approximately $233 million related to held and used assets. We believe that most of the assets to be sold do not meet the held for sale and discontinued operations criteria as of September 30, 2009 because of the uncertainties related to the current market conditions and obtaining necessary approvals. The detail of the impairment charge is as follows (dollars in millions):

	Three Months Ended		Nine Months Ended
	September 30, 2009		September 30, 2009
Homebuilding and master-planned communities	$	10	$	151
Land parcels and commercial assets		26		78
Golf courses		1		18
Subtotal		37		247
Discontinued operations		1		13
Less non-controlling interests		—		(14	)
Total	$	38	$	246

39

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We estimate the fair value of our real estate assets primarily based on either the future cash flows that we estimate will be generated by each asset discounted at a rate we believe market participants would use, on independent appraisals, or other market information. Our impairment assessments and fair value determinations require significant judgment regarding key assumptions such as future sales prices, future construction and land development costs, future sales timing, and discount rates. The assumptions are specific to each project and may vary among projects. The weighted average discount rates we used to estimate fair values at September 30, 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.

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

40

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

	Three Months Ended
	September 30,
	2009			2008
ELECTRIC OPERATING REVENUES	$	1,083,825		$	1,042,084
OPERATING EXPENSES
Fuel and purchased power		381,543			421,632
Operations and maintenance		203,446			206,526
Depreciation and amortization		101,027			96,769
Income taxes		118,923			86,484
Other taxes		33,782			28,018
Total		838,721			839,429
OPERATING INCOME		245,104			202,655
OTHER INCOME (DEDUCTIONS)
Income taxes		1,070			1,909
Allowance for equity funds used during construction		2,197			4,673
Other income (Note S-2)		3,530			1,462
Other expense (Note S-2)		(2,790	)		(9,458	)
Total		4,007			(1,414	)
INTEREST DEDUCTIONS
Interest on long-term debt		51,216			40,841
Interest on short-term borrowings		1,058			2,563
Debt discount, premium and expense		1,115			1,162
Allowance for borrowed funds used during construction		(1,343	)		(3,079	)
Total		52,046			41,487
NET INCOME	$	197,065		$	159,754

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

41

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

	Nine Months Ended
	September 30,
	2009			2008
ELECTRIC OPERATING REVENUES	$	2,499,072		$	2,498,743
OPERATING EXPENSES
Fuel and purchased power		920,630			1,022,762
Operations and maintenance		625,674			582,480
Depreciation and amortization		298,036			286,615
Income taxes		158,041			113,194
Other taxes		100,077			93,549
Total		2,102,458			2,098,600
OPERATING INCOME		396,614			400,143
OTHER INCOME (DEDUCTIONS)
Income taxes		3,684			4,863
Allowance for equity funds used during construction		11,919			16,211
Other income (Note S-2)		7,580			4,560
Other expense (Note S-2)		(10,798	)		(21,546	)
Total		12,385			4,088
INTEREST DEDUCTIONS
Interest on long-term debt		148,267			123,733
Interest on short-term borrowings		5,326			8,931
Debt discount, premium and expense		3,560			3,482
Allowance for borrowed funds used during construction		(8,284	)		(10,687	)
Total		148,869			125,459
NET INCOME	$	260,130		$	278,772

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

42

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

	September 30,			December 31,
	2009			2008
ASSETS
UTILITY PLANT
Electric plant in service and held for future use	$	12,569,397		$	12,198,010
Less accumulated depreciation and amortization		4,283,668			4,129,958
Net		8,285,729			8,068,052
Construction work in progress		536,119			571,977
Intangible assets, net of accumulated amortization		154,243			131,243
Nuclear fuel, net of accumulated amortization		126,767			89,323
Total utility plant		9,102,858			8,860,595
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 18)		399,808			343,052
Assets from management and trading activities (Note 10)		22,167			33,675
Other assets		65,576			60,604
Total investments and other assets		487,551			437,331
CURRENT ASSETS
Cash and cash equivalents		86,338			71,544
Customer and other receivables		366,241			262,177
Accrued utility revenues		156,509			100,089
Allowance for doubtful accounts		(3,758	)		(3,155	)
Materials and supplies (at average cost)		180,144			173,252
Fossil fuel (at average cost)		39,641			29,752
Income tax receivable		84,766			—
Assets from risk management and trading activities (Note 10)		32,220			32,181
Deferred income taxes		58,873			79,694
Other current assets		18,770			19,866
Total current assets		1,019,744			765,400
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		—			7,984
Other regulatory assets		726,883			787,506
Unamortized debt issue costs		20,300			22,026
Other		85,399			82,735
Total deferred debits		832,582			900,251
TOTAL ASSETS	$	11,442,735		$	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.

43

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

	September 30,			December 31,
	2009			2008
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital		2,126,863			2,117,789
Retained earnings		1,301,531			1,168,901
Accumulated other comprehensive loss (Note S-1):
Pension and other postretirement benefits		(27,433	)		(26,960	)
Derivative instruments		(82,445	)		(98,742	)
Common stock equity		3,496,678			3,339,150
Long-term debt less current maturities (Note 4)		3,327,025			2,850,242
Total capitalization		6,823,703			6,189,392
CURRENT LIABILITIES
Short-term borrowings		—			521,684
Current maturities of long-term debt (Note 4)		50,541			874
Accounts payable		184,036			233,529
Accrued taxes (Note 8)		153,905			219,129
Accrued interest		48,820			39,860
Customer deposits		73,171			77,452
Liabilities from risk management and trading activities (Note 10)		50,976			69,585
Other current liabilities		117,256			105,655
Total current liabilities		678,705			1,267,768
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,638,537			1,401,412
Regulatory liabilities		668,567			587,586
Deferred fuel and purchased power regulatory liability (Note 5)		60,488			—
Liability for asset retirements		289,921			275,970
Liabilities for pension and other postretirement benefits (Note 6)		684,661			635,327
Customer advances		131,512			132,023
Liabilities from risk management and trading activities (Note 10)		46,498			126,532
Coal mine reclamation		91,847			91,201
Unrecognized tax benefits		161,987			67,846
Other		166,309			188,520
Total deferred credits and other		3,940,327			3,506,417
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	11,442,735		$	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.

44

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

	Nine Months Ended
	September 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	260,130		$	278,772
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		328,313			312,022
Deferred fuel and purchased power		(46,743	)		(104,774	)
Deferred fuel and purchased power amortization		115,214			157,999
Allowance for equity funds used during construction		(11,919	)		(16,211	)
Deferred income taxes		252,282			220,180
Change in mark-to-market valuations		(5,970	)		190
Changes in current assets and liabilities:
Customer and other receivables		(92,535	)		(59,607	)
Accrued utility revenues		(56,420	)		(50,843	)
Materials, supplies and fossil fuel		(16,781	)		(13,527	)
Other current assets		(2,473	)		2,774
Accounts payable		(28,018	)		40,339
Accrued taxes and income tax receivable — net		(149,990	)		7,268
Other current liabilities		16,279			58,887
Change in regulatory liabilities		92,598			(4,397	)
Change in unrecognized tax benefits		92,973			(104,523	)
Change in other long-term assets		(53,530	)		41,379
Change in other long-term liabilities		10,053			16,365
Net cash flow provided by operating activities		703,463			782,293
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(551,042	)		(681,775	)
Contributions in aid of construction		17,393			40,950
Allowance for borrowed funds used during construction		(8,284	)		(10,687	)
Proceeds from nuclear decommissioning trust sales		370,399			255,706
Investment in nuclear decommissioning trust		(386,743	)		(271,263	)
Other		(1,404	)		4,267
Net cash flow used for investing activities		(559,681	)		(662,802	)
CASH FLOWS FROM FINANCING ACTIVITIES
Equity infusion		—			7,601
Issuance of long-term debt		863,903			—
Repayment and reacquisition of long-term debt		(343,707	)		(27,485	)
Short-term borrowings and payments-net		(521,684	)		51,580
Dividends paid on common stock		(127,500	)		(127,500	)
Net cash flow used for financing activities		(128,988	)		(95,804	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		14,794			23,687
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		71,544			52,151
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	86,338		$	75,838
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of refunds	$	13,555		$	25,710
Interest, net of amounts capitalized	$	136,349		$	119,302

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

45

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

46

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS

S-1. Comprehensive Income

Components of APS’ comprehensive income for the three and nine months ended September 30, 2009 and 2008 are as follows (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Net income	$	197,065		$	159,754		$	260,130		$	278,772
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		4,959			(334,384	)		(128,035	)		6,984
Net reclassification of realized (gains) losses to income (b)		81,660			(39,115	)		154,990			(62,444	)
Net unrealized losses related to pension benefits		—			—			(3,774	)		(10,279	)
Reclassification of pension and other postretirement benefits to income		999			1,000			2,991			3,001
Income tax benefit (expense) related to items of other comprehensive income		(34,644	)		146,616			(10,348	)		24,694
Total other comprehensive income (loss)		52,974			(225,883	)		15,824			(38,044	)
Comprehensive income (loss)	$	250,039		$	(66,129	)	$	275,954		$	240,728

(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.

47

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS

S-2. Other Income and Other Expense

The following table provides detail of APS’ other income and other expense for the three and nine months ended September 30, 2009 and 2008 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Other income:
Interest income	$	63		$	739		$	402		$	3,064
Investment gains — net		3,320			—			5,189			—
Miscellaneous		147			723			1,989			1,496
Total other income	$	3,530		$	1,462		$	7,580		$	4,560
Other expense:
Non-operating costs (a)	$	(1,714	)	$	(2,779	)	$	(6,225	)	$	(8,966	)
Asset dispositions		(182	)		(2,168	)		(540	)		(2,999	)
Investment losses — net		—			(3,066	)		—			(5,929	)
Miscellaneous		(894	)		(1,445	)		(4,033	)		(3,652	)
Total other expense	$	(2,790	)	$	(9,458	)	$	(10,798	)	$	(21,546	)

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

48

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. For purposes of this report, a “Note” refers to a Note to Pinnacle West’s Condensed Consolidated Financial Statements in Item 1 of this report.

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for most of our revenues and earnings, and is expected to continue to do so.

Customer growth in APS’ service territory for the nine-month period ended September 30, 2009 was 0.7% compared with the prior year period. For the three years 2006 through 2008, APS’ customer growth averaged 3% a year. 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. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for the nine-month period ended September 30, 2009 declined 2.1% compared to the same period in the prior year, reflecting the poor economic conditions in 2009 and the effects of our energy efficiency programs. For the three years 2006 through 2008, APS’ actual retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, grew at an average annual rate of 2.9%. We currently estimate that total retail electricity sales in kilowatt-hours will remain flat on average per year during 2009 through 2011, including the effects of APS’ energy efficiency programs but excluding the effects of weather variations.

Despite the recent volatility and disruption of the credit markets, as discussed in detail under “Pinnacle West Consolidated — Liquidity and Capital Resources” below, 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 needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. During the third quarter, the ACC conducted an evidentiary hearing in our pending retail rate case, which was originally filed during 2008 to help defray rising infrastructure costs and allow for new conservation rates, among other things. The hearing involved testimony related to a proposed settlement agreement between APS and other parties to the rate case. The parties are awaiting a recommended order from the ALJ, after which the ACC will hold an open meeting in order to reach a final decision on this matter. If the Settlement Agreement is approved by the ACC in its current form, APS expects that its provisions, including the new rates, would become effective on or about January 1, 2010. 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 detailed discussion of the Settlement Agreement, a related evidentiary hearing, and the anticipated timing of a final ACC decision in this matter.

49

During the first quarter of 2009, SunCor undertook and completed a review of its assets and strategies within its various markets as a result of the then current and anticipated continuing distressed conditions in real estate and credit markets. Based on the results of the review, on March 27, 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce SunCor’s outstanding debt. This resulted in a pretax impairment charge of approximately $202 million, or $123 million after income taxes, in the first quarter of 2009. During the second and third quarters of 2009, SunCor reassessed market conditions and recorded additional pretax impairment charges of approximately $6 million and $38 million, or $4 million and $23 million after income taxes, respectively. Of the total $246 million impairment charge for the nine months ended September 30, 2009, approximately $13 million related to assets held for sale and approximately $233 million related to held and used assets. We believe that most of the assets to be sold do not meet the held for sale and discontinued operations criteria as of September 30, 2009 because of the uncertainties related to the current market conditions and obtaining necessary approvals. See “Liquidity and Capital Resources — Other Subsidiaries — SunCor” below for a discussion of SunCor’s outstanding debt and related matters.

Our other first tier subsidiaries, El Dorado and APSES, are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.

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

RESULTS OF OPERATIONS

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

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

Operating Results — Three-month period ended September 30, 2009 compared with three-month period ended September 30, 2008

Our consolidated net income attributable to common shareholders for the three months ended September 30, 2009 was $187 million, compared with net income of $152 million for the comparable prior-year period. The increase in net income was primarily due to improved results from the Company’s regulated electricity segment relating to increased mark-to-market valuations of fuel and purchased power contracts and increased revenues due to the interim rate increase effective January 1, 2009. These positive factors were partially offset by higher interest charges, net of capitalized financing costs.

50

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

							Increase
							(Decrease)
							in Net Income
	Three Months Ended						Attributable
	September 30,						to Common
	2009			2008			Shareholders
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	702		$	620		$	82
Operations and maintenance		(205	)		(209	)		4
Depreciation and amortization		(101	)		(97	)		(4	)
Taxes other than income taxes		(34	)		(28	)		(6	)
Other income (expenses), net		2			(6	)		8
Interest charges, net of capitalized financing costs		(53	)		(41	)		(12	)
Income taxes		(111	)		(81	)		(30	)
Regulated electricity segment net income		200			158			42
Real Estate Segment:
Other real estate activities		18			(11	)		29
Real estate impairment charges		(37	)		—			(37	)
Income taxes		7			5			2
Real estate segment net loss		(12	)		(6	)		(6	)
All other (a)		(1	)		—			(1	)
Net Income Attributable to Common Shareholders	$	187		$	152		$	35

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

Regulated electricity segment

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

51

Operating revenues less fuel and purchased power expenses

Regulated electricity segment operating revenues less fuel and purchased power expenses were $82 million higher for the three months ended September 30, 2009 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Purchased
	Operating			power and fuel
	revenues			expenses			Net change
	(dollars in millions)
Increased mark-to-market valuations of fuel and purchased power contracts related to favorable changes in market prices, net of related PSA deferrals	$			$	(37	)	$	37
Interim retail rate increases effective January 1, 2009		21						21
Higher renewable energy and demand-side management surcharges (substantially offset in operations and maintenance expense)		17						17
Effects of hotter weather on retail sales		12			4			8
Transmission rate increases		7						7
Lower retail sales primarily due to lower usage per customer, including the effects of the energy efficiency programs, but excluding the effects of weather		(11	)		(4	)		(7	)
Higher retail revenues related to recovery of PSA deferrals, offset by amortization of the same amount recorded as fuel and purchased power expense (see Note 5)		5			5			—
Miscellaneous items, net		(8	)		(7	)		(1	)
Total	$	43		$	(39	)	$	82

Operations and maintenance Operations and maintenance expenses decreased $4 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of:

• A decrease of $21 million associated with cost saving measures and other factors, including the absence of employee severance costs in 2009; and

• An increase of $17 million related to renewable energy and demand-side management programs, which are offset in operating revenues.

Depreciation and amortization Depreciation and amortization expenses increased $4 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.

Taxes other than income taxes Taxes other than income taxes increased $6 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of higher property tax assessments as a result of increased utility plant in service described above.

52

Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $12 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of higher debt balances, partially offset by the effects of lower interest rates (see discussion related to APS’ debt issuances in “Pinnacle West Consolidated — Liquidity and Capital Resources” below). Interest charges, net of capitalized financing costs are comprised of the line items interest expense, capitalized interest and allowance for equity funds used during construction from the Condensed Consolidated Statements of Income.

Other income (expenses), net Other income (expenses), net improved $8 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of improved investment gains (losses). Other income (expenses), net is comprised of the line items other income and other expense from the Condensed Consolidated Statements of Income.

Income taxes Income taxes were $30 million higher for the three months ended September 30, 2009 compared with the prior-year period primarily because of higher pretax income.

Real estate segment

During the first quarter of 2009, we decided to restructure SunCor through the sale of the substantial majority of its assets. The real estate segment net income attributable to common shareholders was $6 million lower for the three months ended September 30, 2009 compared with the prior-year period primarily because of:

• Real estate impairment charges of $37 million recorded in the 2009 period (see Note 21 for details of the impairment charge), without comparable charges in the prior-year period;

• A $29 million increase in other real estate activities primarily due to increased parcel sales in the 2009 period; and

• A $2 million decrease in income taxes related to lower pretax income.

Operating Results — Nine-month period ended September 30, 2009 compared with nine-month period ended September 30, 2008

Our consolidated net income attributable to common shareholders for the nine months ended September 30, 2009 was $98 million, compared with net income of $281 million for the comparable prior-year period. The decrease in net income was primarily due to 2009 real estate impairment charges recorded by SunCor, the Company’s real estate subsidiary.

In addition, regulated electricity segment net income decreased approximately $16 million from the prior-year period primarily due to lower retail sales resulting from lower usage per customer; higher interest charges, net of capitalized financing costs; higher depreciation and amortization expenses; and the absence of income tax benefits related to prior years recorded in 2008. These negative factors were partially offset by increased revenues due to the interim rate increase effective January 1, 2009 and transmission rate increases.

53

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

							Increase
							(Decrease)
							in Net Income
	Nine Months Ended						Attributable
	September 30,						to Common
	2009			2008			Shareholders
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	1,578		$	1,476		$	102
Operations and maintenance		(633	)		(589	)		(44	)
Depreciation and amortization		(298	)		(287	)		(11	)
Taxes other than income taxes		(101	)		(94	)		(7	)
Other income (expenses), net		1			(12	)		13
Interest charges, net of capitalized financing costs		(147	)		(121	)		(26	)
Income taxes		(143	)		(100	)		(43	)
Regulated electricity segment net income		257			273			(16	)
Real Estate Segment:
Real estate impairment charges		(247	)		—			(247	)
Other real estate operations		(6	)		(28	)		22
Income taxes		93			11			82
Income (loss) from discontinued operations		(8	)		25			(33	)
Noncontrolling interests		15			—			15
Real estate segment net income (loss)		(153	)		8			(161	)
All Other (a)		(6	)		—			(6	)
Net Income Attributable to Common Shareholders	$	98		$	281		$	(183	)

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

Regulated electricity segment

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

54

Operating revenues less fuel and purchased power expenses

Regulated electricity segment operating revenues less fuel and purchased power expenses were $102 million higher for the nine months ended September 30, 2009 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Purchased
	Operating			power and fuel
	revenues			expenses			Net change
	(dollars in millions)
Interim retail rate increases effective January 1, 2009	$	50		$			$	50
Higher renewable energy and demand-side management surcharges (substantially offset in operations and maintenance expense)		49						49
Transmission rate increases		16						16
Increased mark-to-market valuations of fuel and purchased power contracts related to favorable changes in market prices, net of related PSA deferrals					(9	)		9
Effects of weather on retail sales, primarily due to hotter weather in the third quarter of 2009		9			2			7
Lower retail sales primarily due to lower usage per customer, including the effects of the Company’s energy efficiency programs, but excluding the effects of weather		(41	)		(18	)		(23	)
Higher fuel and purchased power costs including the effects of lower off-system sales, net of related PSA deferrals		(26	)		(21	)		(5	)
Lower retail revenues related to recovery of PSA deferrals, offset by lower amortization of the same amount recorded as fuel and purchased power expense (see Note 5)		(43	)		(43	)		—
Miscellaneous items, net		(8	)		(7	)		(1	)
Total	$	6		$	(96	)	$	102

Operations and maintenance Operations and maintenance expenses increased $44 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of:

• An increase of $48 million related to renewable energy and demand-side management programs, which are offset in operating revenues;

• An increase of $14 million in generation costs, including more planned maintenance, partially offset by lower costs at Palo Verde due to cost efficiency measures; and

• A decrease of $18 million associated with cost saving measures and other factors, including the absence of employee severance costs in 2009.

55

Depreciation and amortization Depreciation and amortization expenses increased $11 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.

Taxes other than income taxes Taxes other than income taxes increased $7 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of higher property tax assessments as a result of increased utility plant in service described above.

Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $26 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of higher debt balances, partially offset by the effects of lower interest rates (see discussion related to APS’ debt issuances in “Pinnacle West Consolidated — Liquidity and Capital Resources” below). Interest charges, net of capitalized financing costs are comprised of the line items interest expense, capitalized interest and allowance for equity funds used during construction from the Condensed Consolidated Statements of Income.

Other income (expenses), net Other income (expenses), net improved $13 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of improved investment gains (losses). Other income (expenses), net is comprised of the line items other income and other expense from the Condensed Consolidated Statements of Income.

Income taxes Income taxes were $43 million higher for the nine months ended September 30, 2009 compared with the prior-year period primarily because of $30 million of income tax benefits related to prior years recorded in 2008 and higher pretax income.

Real estate segment

During the first quarter of 2009, we decided to restructure SunCor through the sale of the substantial majority of its assets. The real estate segment net loss attributable to common shareholders was $161 million higher for the nine months ended September 30, 2009 compared with the prior-year period primarily because of:

• Real estate impairment charges of $247 million recorded in the 2009 period (see Note 21 for details of the impairment charge), without comparable charges in the prior-year period;

• An increase of $22 million from other real estate operations primarily due to increased parcel sales in the 2009 period;

• A decrease of $33 million in income from discontinued operations related to gains on certain real estate commercial property sales in 2008 and real estate impairment charges in 2009 (see Note 21);

• An increase of $15 million related to noncontrolling interests’ portion of real estate impairment charges and other results (see Note 21); and

• An increase in income tax benefits of $82 million primarily because of higher net loss.

56

All other

All other earnings were $6 million lower for the nine months ended September 30, 2009 compared to the prior-year period primarily 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 nine months ended September 30, 2009 and 2008 (dollars in millions):

	Nine Months Ended
	September 30,
	2009			2008
Net cash flow provided by operating activities	$	761		$	784
Net cash flow used for investing activities		(537	)		(597	)
Net cash flow used for financing activities		(229	)		(139	)

The decrease of approximately $23 million in net cash provided by operating activities is primarily due to changes in working capital, including a 2009 income tax refund (see Note 8).

The decrease of approximately $60 million in net cash used for investing activities is primarily due to lower levels of capital expenditures net of contributions (see table and discussion below), partially offset by lower real estate sales primarily due to a commercial property sale in 2008.

The increase of approximately $90 million in net cash used for financing activities is primarily due to repayments of short-term borrowings and SunCor’s repayment of long-term debt, partially offset by APS’ issuance of $500 million of unsecured senior notes (see Note 4).

CAPITAL EXPENDITURES
(dollars in millions)

	Nine Months Ended				Estimated for the Year Ended
	September 30,				December 31,
	2008		2009		2009		2010		2011
APS
Distribution	$	258	$	172	$	276	$	289	$	381
Generation (a)		244		182		288		274		319
Transmission		109		159		275		99		185
Other (b)		22		30		44		37		50
Subtotal		633		543		883		699		935
Other		43		8		12		8		8
Total	$	676	$	551	$	895	$	707	$	943

(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.

57

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 “Environmental Matters — EPA Environmental Regulation — Regional Haze Rules” in Part II, Item 5 below and “Environmental Matters — EPA Environmental Regulation — Mercury” in Part II, Item 5 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009.)

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 October 21, 2009, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on December 1, 2009, to shareholders of record on November 2, 2009.

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 September 30, 2009, APS’ common equity ratio, as defined, was 51%. Its total common equity was approximately $3.5 billion, and total capitalization was approximately $6.9 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.7 billion, assuming APS’ total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

The credit and liquidity markets experienced significant stress beginning the third quarter of 2008. Since the fourth quarter of 2008, Pinnacle West and APS have not accessed the commercial paper market due to negative market conditions. They have both been able to access existing credit facilities, ensuring adequate liquidity.

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 September 30, 2009, the parent company had outstanding $138 million of borrowings under its revolving credit facility and no letters of credit.

58

Pinnacle West expects to recognize approximately $117 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 $97 million of these benefits were recorded in the nine months ended September 30, 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.

The $168 million income tax receivable on the Condensed Consolidated Balance Sheets represents the anticipated cash refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009 and the expected tax benefits related to the SunCor strategic asset sales that closed in 2009.

Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity, real estate and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We contributed $35 million to our pension plan in 2008. In the first quarter of 2009, IRS regulations were modified to allow alternative measurement dates to determine the interest rate used to value the year-end 2008 pension liability for funding purposes. As a result of this change, we estimate our 2009 minimum pension contribution to be zero. We currently estimate that our pension contributions could average around $150 million for several years, assuming the discount rate remains at approximately current levels. 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 97% 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. 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.

59

During 2009, APS refinanced approximately $343 million of its $566 million variable rate pollution control bonds. As a result of these refinancings, the terms of which are described in detail in Note 4, APS no longer has any outstanding debt securities in auction rate mode.

On September 11, 2008, APS purchased all of the approximately $27 million of the Coconino Pollution Control Revenue Bonds, Series 1996A and Series 1999 due December 2031 and April 2034 and held them as treasury bonds. On September 22, 2009, Coconino issued approximately $27 million of Coconino Pollution Control Revenue Refunding Bonds, 2009 Series B due April 2038 to redeem the existing bonds. APS used the funds received from the issuance to repay certain existing indebtedness under a revolving line of credit drawn upon by APS to fund its purchase of the 1996A and 1999 Series Bonds in 2008. The 2009 Series B Bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Coconino. According to the indenture of the bonds, the interest rate of the 2009 Series B Bonds could be reset daily, weekly, monthly, or at other time intervals. The initial rate period selected for the 2009 Series B Bonds is a daily rate period. At September 30, 2009, the daily interest rate was 0.35%. The daily rates are variable rates set by a remarketing agent. Concurrently with the issuance of the 2009 Series B Bonds, the Company entered into a two year letter of credit and reimbursement agreement to provide credit support for the 2009 Series B Bonds.

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 or to be used for bank borrowings, including issuances of letters of credit up to $583 million. At September 30, 2009, APS had no borrowings and no letters of credit under its revolving lines of credit.

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 through December 31, 2014.

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

Other Subsidiaries

SunCor — The SunCor Secured Revolver matures in January 2010 and requires SunCor to reduce its outstanding borrowings by specified amounts over the term of the facility. As of September 30, 2009, approximately $72 million of borrowings were outstanding under the SunCor Secured Revolver and approximately $49 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 repayment of the SunCor Secured Revolver and SunCor’s other outstanding debt. The impairment charges discussed in Note 21 resulted in violations of certain covenants contained in the SunCor Secured Revolver and SunCor’s other credit facilities. The lenders have taken no enforcement action related to the covenant defaults, and SunCor is current on all of its debt payment obligations under the SunCor Secured Revolver and its other credit facilities. SunCor remains in discussions with its lenders to modify or replace the SunCor Secured Revolver to resolve the covenant defaults and extend the principal repayment provisions and the January 2010 maturity date. If SunCor is unable to obtain additional extensions, modifications, waivers or similar relief from its lenders, or is unable to comply with the provisions of any new or modified agreements, SunCor could be required to 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. While there can be no assurances as to the ultimate outcome of this matter, Pinnacle West does not believe that SunCor’s inability to obtain waivers or similar relief from SunCor’s lenders would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

60

As of September 30, 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.

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, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At September 30, 2009, the ratio was approximately 52% for Pinnacle West and 48% for APS. The provisions regarding interest coverage require minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.6 times under APS’ bank financing agreements as of September 30, 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.

61

Credit Ratings

The ratings of securities of Pinnacle West and APS as of October 28, 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 cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient liquidity to cover a downward revision to our credit ratings.

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

(a) Pinnacle West has a shelf registration under United States Securities and Exchange Commission (“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. 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 September 30, 2009, APS would have been required to assume approximately $167 million of debt and pay the equity participants approximately $161 million. See Note 15 for a discussion of letters of credit that support certain lessors in the Palo Verde sale leaseback transactions.

62

SunCor is the primary beneficiary of certain land development arrangements and, accordingly, consolidates the 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 September 30, 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, which primarily relate 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 September 30, 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. 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.

Contractual Obligations

Our future contractual obligations, including contingent obligations, related to purchased power and fuel contracts and renewable energy credits have increased from approximately $7.9 billion at December 31, 2008 to $9.0 billion at September 30, 2009 as follows (dollars in billions):

2009		2010-2011		2012-2013		Thereafter		Total
$	0.5	$	0.8	$	0.8	$	6.9	$	9.0

These amounts have increased since the 2008 Form 10-K primarily due to gas transportation contracts and renewable energy credits associated with the Renewable Energy Standard; however, these amounts are less than those reported in the Second Quarter Form 10-Q due to the termination by Starwood Solar I, LLC of our contingent renewable purchased power agreement with them for a 290 MW solar project.

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

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.

63

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.

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 pre-tax changes in mark-to-market value of our derivative positions for the nine months ended September 30, 2009 and 2008 (dollars in millions):

	Nine Months Ended
	September 30,
	2009			2008
Total derivatives at beginning of period	$	(282	)	$	40
Recognized in earnings:
Change in mark-to-market gains (losses) for future period deliveries		(3	)		5
Mark-to-market (gains) losses realized including ineffectiveness during the period		9			(7	)
Decrease (increase) in regulatory asset		59			(53	)
Recognized in AOCI:
Change in mark-to-market gains (losses) for future period deliveries (a)		(128	)		13
Mark-to-market (gains) losses realized during the period		155			(83	)
Change in valuation techniques		—			—
Total derivatives at end of period	$	(190	)	$	(85	)

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

64

The table below shows the net fair value of maturities of our derivative contracts (dollars in millions) at September 30, 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.

																Years			Total
Source of Fair Value	2009			2010			2011			2012			2013			thereafter			Fair Value
Level 1 – Quoted prices in active markets	$	(13	)	$	(11	)	$	—		$	—		$	—		$	—		$	(24	)
Level 2 – Significant other observable inputs		(38	)		(66	)		(45	)		(4	)		—			—			(153	)
Level 3 – Significant unobservable inputs		1			(3	)		1			2			(2	)		(12	)		(13	)
Total by maturity	$	(50	)	$	(80	)	$	(44	)	$	(2	)	$	(2	)	$	(12	)	$	(190	)

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 September 30, 2009 and December 31, 2008 (dollars in millions):

	September 30, 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	$	1	$	(1	)	$	2	$	(2	)
Natural gas		2		(2	)		3		(3	)
Regulatory asset (liability) or AOCI (a)
Electricity		21		(21	)		20		(20	)
Natural gas		59		(59	)		64		(64	)
Total	$	83	$	(83	)	$	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.

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.

65

OTHER ACCOUNTING MATTERS

See Note 20 for a discussion of fair value measurements and disclosures, 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 the amended guidance on disclosures about derivative instruments and hedging activities. We adopted this amended disclosure guidance on January 1, 2009.

We adopted amended guidance on reporting noncontrolling interests in consolidated financial statements 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 Condensed Consolidated Balance Sheets. Prior year’s net income attributable to noncontrolling interests was not material to our Condensed Consolidated Statements of Income and was not reclassified. The adoption of this guidance modified our financial statement presentation, but did not have an impact on our financial statement results.

On January 1, 2009, we adopted accounting guidance on determining whether instruments granted in share-based payment transactions are participating securities. This guidance 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. Our awards do not have nonforfeitable rights to dividends or dividend equivalents and, therefore, the adoption of this guidance did not have any impact on our financial statements.

On April 1, 2009, we adopted new accounting provisions on topics described below. The adoption of these new accounting provisions did not have a material impact on our financial statements. See Note 20 for a discussion of fair value measurements.

• 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.

• The recognition and presentation of other-than-temporary impairments.

• Interim disclosures about fair value of financial instruments.

In May 2009, the FASB issued guidance which established general standards of accounting for and disclosure of subsequent events. Subsequent events are events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this guidance during the second quarter of 2009. The adoption of this guidance did not have a material impact on our financial statements.

66

In June 2009, the FASB issued the FASB accounting standards codification and the hierarchy of generally accepted accounting principles. This guidance establishes the FASB Accounting Standards Codification as the source of authoritative accounting principles recognized by the FASB to be applied by entities in the preparation of financial statements in conformity with GAAP. We adopted this guidance during the third quarter of 2009. The adoption of this provision modifies how we reference and research accounting guidance, but did not have a material impact on our financial statements.

In December 2008, the FASB issued guidance on employers’ disclosures about postretirement benefit plan assets. This guidance requires enhanced employers’ 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 the adoption of this guidance will have a material impact on our financial statements.

In June 2009, the FASB issued amended guidance on the consolidation of variable interest entities. This amended guidance is intended to improve financial reporting and provide more relevant and reliable information by enterprises involved with variable interest entities. This guidance is effective for us on January 1, 2010. We are currently evaluating this new guidance and the impact it may have on our financial statements.

The FASB recently issued amended guidance relating to fair value measurements, as described below. We will adopt these new accounting provisions during the fourth quarter of 2009. We do not expect the adoption of these provisions to have a material impact on our financial statements.

• Measuring fair value of liabilities, which provides additional guidance on how fair value measurements of liabilities should be determined.

• Measuring fair value of certain alternative investments. This guidance provides clarification on the measurement and disclosure of investments in entities that calculate net asset value.

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 are sales of electricity from generation owned or contracted by APS that are over and above the amount required to serve APS’ retail customers and traditional wholesale contracts. 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 needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. See Note 5 for details regarding our pending retail rate case, including the ACC’s approval of an interim base rate surcharge pending the outcome of the case and a detailed discussion of the Settlement Agreement, a related evidentiary hearing, and the anticipated timing of a final ACC decision in this matter.

67

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, including the treatment of uncollected or overcollected PSA deferrals and related annual PSA adjustments.

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 nine-month period ended September 30, 2009 was 0.7% compared with the prior year period. For the three years 2006 through 2008, APS’ customer growth averaged 3% a year. 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. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for the nine-month period ended September 30, 2009 declined 2.1% compared to the same period in the prior year, reflecting the poor economic conditions in 2009 and the effects of our energy efficiency programs. For the three years 2006 through 2008, APS’ actual retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, grew at an average annual rate of 2.9%. We currently estimate that total retail electricity sales in kilowatt-hours will remain flat on average per year during 2009 through 2011, including the effects of APS’ energy efficiency programs but excluding the effects of weather variations.

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.

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, renewable energy and demand side management related expenses (which are offset by the same amount of regulated electricity segment operating revenues) and other factors. In early 2009, APS identified certain operations and maintenance expense reductions for 2009 and has committed to additional reductions in the rate case Settlement Agreement. See “Energy Efficiency, Demand-Side Management and Renewable Energy Programs” and “2008 General Retail Rate Case — Proposed Settlement Agreement and Related Hearing” in Note 5.

68

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. We have also applied to the NRC for renewed operating licenses for Palo Verde Unit 1, Unit 2 and Unit 3. See “Business of Arizona Public Service Company — Nuclear Generating Facility — Regulatory” in the 2008 Form 10-K. If the NRC grants the extension and the ACC approves the adjustment of depreciation rates to reflect the extension, we estimate that our annual pretax depreciation expense will decrease by approximately $34 million at the later of the license extension date or January 1, 2012.

Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 7.8% 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 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 and Environmental Matters Recent concern over climate change and other emission-related issues could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades. 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” and “Environmental Matters” in Part II, Item 5 for more information regarding environmental and climate change developments.

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. Currently, there are two matters pending with the ACC that involve a business model where customers pay solar vendors for the installation and operation of solar facilities based on the amount of energy produced. The ACC must make a determination whether these entities would be considered “public service corporations” under the Arizona Constitution, causing them to be regulated by the ACC. Use of such products by customers within our territory would result in some level of competition; however, at this time we do not feel this would materially impact our financial results. We cannot predict when, and the extent to which, additional electric service providers will enter or 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. SunCor’s net loss attributable to common shareholders for the nine months ended September 30, 2009 was approximately $253 million, which included a pre-tax impairment charge of approximately $246 million. See Note 21 for further discussion of impairment charges in 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.

69

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” at the front of this document 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.

ARIZONA PUBLIC SERVICE COMPANY — RESULTS OF OPERATIONS

Operating Results — Three-month period ended September 30, 2009 compared with three-month period ended September 30, 2008

APS’ net income for the three months ended September 30, 2009 was $197 million, compared with net income of $160 million for the comparable prior-year period. The increase in net income was primarily due to increased mark-to-market valuations of fuel and purchased power contracts and increased revenues due to the interim rate increase effective January 1, 2009. These positive factors were partially offset by higher interest charges, net of capitalized financing costs.

The following table presents net income compared with the prior-year period:

	Three Months Ended						Increase
	September 30,						(Decrease)
	2009			2008			in Net Income
	(dollars in millions)
Operating revenues less fuel and purchased power expenses	$	702		$	620		$	82
Operations and maintenance		(203	)		(206	)		3
Depreciation and amortization		(101	)		(97	)		(4	)
Taxes other than income taxes		(34	)		(28	)		(6	)
Other income (expenses), net		1			(7	)		8
Interest charges, net of capitalized financing costs		(50	)		(37	)		(13	)
Income taxes		(118	)		(85	)		(33	)
Net income	$	197		$	160		$	37

70

Operating revenues less fuel and purchased power expenses

Electric operating revenues less fuel and purchased power costs were $82 million higher for the three months ended September 30, 2009 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Purchased
	Operating			power and fuel
	revenues			expenses			Net change
	(dollars in millions)
Increased mark-to-market valuations of fuel and purchased power contracts related to favorable changes in market prices, net of related PSA deferrals	$			$	(37	)	$	37
Interim retail rate increases due to the interim rate increase effective January 1, 2009		21						21
Higher renewable energy and demand-side management surcharges (substantially offset in operations and maintenance expense)		17						17
Effects of hotter weather on retail sales		12			4			8
Transmission rate increases		7						7
Lower retail sales primarily due to lower usage per customer, including the effects of the Company’s energy efficiency programs, but excluding the effects of weather		(11	)		(4	)		(7	)
Higher retail revenues related to recovery of PSA deferrals, offset by amortization of the same amount recorded as fuel and purchased power expense (see Note 5)		5			5			—
Miscellaneous items, net		(8	)		(7	)		(1	)
Total	$	43		$	(39	)	$	82

Operations and maintenance Operations and maintenance expenses decreased $3 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of:

• A decrease of $20 million associated with cost saving measures and other factors, including the absence of employee severance costs in 2009; and

• An increase of $17 million in expenses related to renewable energy and demand-side management programs related expenses, which expenses are offset in operating revenues.

Depreciation and amortization Depreciation and amortization expenses increased $4 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.

Taxes other than income taxes Taxes other than income taxes increased $6 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of higher property tax assessments as a result of increased utility plant in service described above.

71

Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $13 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of higher debt balances, partially offset by the effects of lower interest rates (see discussion related to APS’ debt issuances in “Pinnacle West Consolidated — Liquidity and Capital Resources” above). Interest charges, net of capitalized financing costs are comprised of the total interest deductions and allowance for equity funds used during construction from the APS’ Condensed Statements of Income.

Other income (expenses), net Other income (expense), net improved $8 million for the three months ended September 30, 2009 compared with the prior-year period primarily because of improved investment gains (losses). Other income (expenses), net is comprised of the line items other income and other expense from the APS’ Condensed Statements of Income.

Income taxes Income taxes were $33 million higher for the three months ended September 30, 2009 compared with the prior-year period primarily because of higher pretax income.

Operating Results — Nine-month period ended September 30, 2009 compared with nine-month period ended September 30, 2008

APS’ net income for the nine months ended September 30, 2009 was $260 million, compared with net income of $279 million for the comparable prior-year period. The decrease in net income was primarily due to lower retail sales due to lower usage per customer; higher interest charges, net of capitalized financing costs; higher depreciation and amortization expenses; and the absence of income tax benefits related to prior years recorded in 2008. These negative factors were partially offset by increased revenues due to the interim rate increase effective January 1, 2009 and transmission rate increases.

The following table presents net income compared with the prior-year period:

	Nine Months Ended						Increase
	September 30,						(Decrease)
	2009			2008			in Net Income
	(dollars in millions)
Operating revenues less fuel and purchased power expenses	$	1,578		$	1,476		$	102
Operations and maintenance		(626	)		(583	)		(43	)
Depreciation and amortization		(298	)		(287	)		(11	)
Taxes other than income taxes		(100	)		(94	)		(6	)
Other income (expenses), net		(3	)		(16	)		13
Interest charges, net of capitalized financing costs		(137	)		(109	)		(28	)
Income taxes		(154	)		(108	)		(46	)
Net income	$	260		$	279		$	(19	)

72

Operating revenues less fuel and purchased power expenses

Electric operating revenues less fuel and purchased power costs were $102 million higher for the nine months ended September 30, 2009 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Purchased
	Operating			power and fuel
	revenues			expenses			Net change
	(dollars in millions)
Interim retail rate increases effective January 1, 2009	$	50		$			$	50
Higher renewable energy and demand-side management surcharges(substantially offset in operations and maintenance expense)		49						49
Transmission rate increases		16						16
Improved mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals					(9	)		9
Effects of weather on retail sales, primarily due to hotter weather in the third quarter of 2009		9			2			7
Lower retail sales primarily due to lower usage per customer, including the effects of the Company’s energy efficiency programs, but excluding the effects of weather		(41	)		(18	)		(23	)
Higher fuel and purchase power costs including the effects of power off-system sales, net of related PSA deferrals		(26	)		(21	)		(5	)
Lower retail revenues related to recovery of PSA deferrals, offset by amortization of the same amount recorded as fuel and purchased power expense (see Note 5)		(43	)		(43	)		—
Miscellaneous items, net		(8	)		(7	)		(1	)
Total	$	6		$	(96	)	$	102

Operations and maintenance Operations and maintenance expenses increased $43 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of:

• An increase of $48 million in expenses related to renewable energy and demand-side management programs related expenses, which expenses are offset in operating revenues;

• An increase of $14 million in generation costs, including more planned maintenance partially offset by lower costs at Palo Verde due to cost efficiency measures; and

• A decrease of $19 million associated with cost saving measures and other factors, including the absence of employee severance costs in 2009.

73

Depreciation and amortization Depreciation and amortization expenses increased $11 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.

Taxes other than income taxes Taxes other than income taxes increased $6 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of higher property tax assessments as a result of increased utility plant in service described above.

Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $28 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of higher debt balances, partially offset by the effects of lower interest rates (see discussion related to APS’ debt issuances in “Pinnacle West Consolidated - Liquidity and Capital Resources” above). Interest charges, net of capitalized financing costs are comprised of the total interest deductions and allowance for equity funds used during construction from the APS’ Condensed Statements of Income.

Other income (expenses), net Other income (expense), net improved $13 million for the nine months ended September 30, 2009 compared with the prior-year period primarily because of improved investment gains (losses). Other income (expenses), net is comprised of the line items other income and other expense from the APS’ Condensed Statements of Income.

Income taxes Income taxes were $46 million higher for the nine months ended September 30, 2009 compared with the prior-year period primarily because of higher net income and $29 million of income tax benefits related to prior years recorded in 2008.

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 nine months ended September 30, 2009 and 2008 (dollars in millions):

	Nine Months Ended
	September 30,
	2009			2008
Net cash flow provided by operating activities	$	703		$	782
Net cash flow used for investing activities		(560	)		(663	)
Net cash flow used for financing activities		(129	)		(96	)

The decrease of approximately $79 million in net cash provided by operating activities is primarily due to changes in working capital.

The decrease of approximately $103 million in net cash used for investing activities is primarily due to lower levels of capital expenditures net of contributions.

74

The increase of approximately $33 million in net cash used for financing activities is primarily due to repayments of short-term borrowings partially offset by APS’ issuance of $500 million of unsecured senior notes (see Note 4).

Contractual Obligations

APS’ future contractual obligations, including contingent obligations, related to purchased power and fuel contracts and renewable energy credits have increased from approximately $7.9 billion at December 31, 2008 to $9.0 billion at September 30, 2009 as follows (dollars in billions):

2009		2010-2011		2012-2013		Thereafter		Total
$	0.5	$	0.8	$	0.8	$	6.9	$	9.0

These amounts have increased since the 2008 Form 10-K primarily due to gas transportation contracts and renewable energy credits associated with the Renewable Energy Standard; however, these amounts are less than those reported in the Second Quarter Form 10-Q due to the termination by Starwood Solar I, LLC of our contingent renewable purchased power agreement with them for a 290 MW solar project.

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

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.

75

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of September 30, 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 September 30, 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 September 30, 2009 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

76

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 5. OTHER INFORMATION

Construction and Financing Programs

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

Regulatory Matters

See Note 5 for a discussion of regulatory developments.

77

Environmental Matters

Superfund

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

EPA Environmental Regulation

Regional Haze Rules EPA Region 9 previously requested that APS, as the operating agent for the Four Corners Power Plant (“Four Corners”), and Salt River Project Agricultural Improvement and Power District (“SRP”), as the operating agent for the Navajo Generating Station (“Navajo”), perform a “best available retrofit technology” (BART) analysis for each of Four Corners and Navajo, respectively. 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 — Regional Haze Rules” in Part II, Item 5 of our Second Quarter Form 10-Q for additional background on the BART analyses and the underlying process. APS and SRP each submitted an analysis to the EPA concluding that certain combustion control equipment constitutes BART for these plants. Based on the analyses and comments received through EPA’s rulemaking process, the EPA will determine what it believes constitutes BART for each plant.

The EPA recently issued an Advanced Notice of Proposed Rulemaking (“ANPR”) seeking public comments on its BART determination. The public comment period expired on October 28, 2009. We expect that the EPA will issue a proposed determination in early 2010. Once the EPA issues its proposed determination, it will provide a second comment period prior to issuing its final determination. The participant owners of Four Corners and Navajo will have five years after the EPA issues its final determination to achieve compliance with their respective BART requirements.

APS’ recommended plan for Four Corners includes the installation of combustion control equipment with an estimated cost to APS, based on preliminary engineering estimates and APS’ Four Corners ownership interest, of approximately $50 million. If the EPA determines that post-combustion controls are required, APS’ total costs could be up to approximately $422 million for Four Corners. SRP’s recommended plan for Navajo includes the installation of combustion control equipment with an estimated cost to APS of approximately $6 million based on APS’ Navajo ownership interest. If the EPA determines that post-combustion controls are required, APS’ total costs could be up to approximately $93 million for Navajo. APS’ obligation to comply with the EPA’s final BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of the Navajo and Four Corners plants due to the significant costs involved.

In order to coordinate with each plant’s other scheduled activities, the plants are currently implementing portions of their recommended plans described above on a voluntary basis. APS’ share of the costs related to the implementation of these portions of the recommended plans are included in our 2009, 2010 and 2011 environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Expenditures” in Item 2).

78

Four Corners Federal Implementation Plan (“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 intervened in their action. In our lawsuit, we challenged 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. While 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, we filed a petition for rehearing on May 29, 2009 related to the stack opacity limit finding because we do not believe that the EPA properly established the limit in question. The court denied our petition on July 24, 2009, and we do not intend to appeal the matter further.

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, on June 26, 2009, the House of Representatives approved the American Clean Energy and Security Act of 2009, H.R. 2454. In addition to establishing clean energy programs, H.R. 2454 would establish a greenhouse gas emission cap-and-trade system applicable to about 85% of all emission sources in the nation. This legislation has moved to the Senate for its consideration. The economic and operational impact of this or any similar 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 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 was made in the context of regulating CO₂ emissions from new motor vehicles, the EPA’s endangerment determination may impact other Clean Air Act programs as well. On September 30, 2009, the EPA announced a proposed rule under the Clean Air Act requiring certain new and modified stationary sources, including power plants, to use the best available control technology to minimize greenhouse gas emissions. At the present time we cannot predict when the EPA will issue its final endangerment finding, whether the proposed stationary source rule will be adopted in its current or a revised form, what other rules or regulations may ultimately result from the EPA’s finding, and what impact the proposed rule and potential other rules or regulations will have on our operations.

In anticipation of potential future regulation of greenhouse gases under the Clean Air Act as described above, on September 22, 2009, the EPA issued a mandatory greenhouse gas reporting rule. The rule applies to direct greenhouse gas emissions from facilities such as our power plants. We expect that our incremental costs to comply with this rule will be immaterial since we already routinely report CO₂ emissions from our plants.

79

Other Developments. On September 21, 2009, the U.S. Court of Appeals for the 2^nd Circuit reversed a lower court decision and ruled that eight states and the City of New York could bring a common law nuisance lawsuit against coal-burning utilities allegedly contributing to global warming. This case raises political and legal considerations, including whether the courts can or should be making climate change policy decisions. We are not a party to this lawsuit, but will monitor these developments and their potential industry impacts.

Economic Stimulus Projects

Through the American Recovery and Reinvestment Act of 2009 (“ARRA”), the Federal government is making a number of programs available for utilities to develop renewable resources, improve reliability and create jobs from the availability of economic stimulus funding. Certain programs are also available through the State of Arizona. On September 11, 2009, the DOE announced an ARRA commitment to fund the majority of a carbon dioxide emission reduction research and development project in the amount of $70.5 million, which will be located at our Cholla power plant. The funding amount is contingent upon meeting certain project milestones, including DOE-established budget parameters, over the next four years.

APS has submitted applications for various other projects, including those related to advanced metering infrastructure and smart grid projects, a photovoltaic generation study, and solar hot water heater and other energy-related community projects. We are currently unable to predict if these applications will result in the award of any funds, or when any such award may be granted, and we continue to evaluate additional opportunities for funding under the ARRA programs.

80

Item 6. EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of James R. Hatfield, Senior Vice President, Treasurer 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, Treasurer 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

81

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

			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

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.

82

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: October 29, 2009	By:	/s/ James R. Hatfield
		James R. Hatfield
		Sr. Vice President, Treasurer and Chief Financial Officer
		(Principal Financial Officer and Officer Duly Authorized to sign this Report)
	ARIZONA PUBLIC SERVICE COMPANY
	(Registrant)
Dated: October 29, 2009	By:	/s/ James R. Hatfield
		James R. Hatfield
		Sr. Vice President, Treasurer and Chief Financial Officer
		(Principal Financial Officer and Officer Duly Authorized to sign this Report)

83

EXHIBIT INDEX

Exhibit No.	Registrant(s)	Description
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
31.1	Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of James R. Hatfield, Senior Vice President, Treasurer 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, Treasurer 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

84