Arizona Public Service 10-Q 2010 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(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, 2010

OR

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

For the transition period from                    to                    

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

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PINNACLE WEST CAPITAL CORPORATION	Yesþ	Noo
ARIZONA PUBLIC SERVICE COMPANY	Yesþ	Noo

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	Yesþ	Noo
ARIZONA PUBLIC SERVICE COMPANY	Yeso	Noo

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 filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filero	Accelerated filero	Non-accelerated filerþ	Smaller reporting companyo

Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act Rule 12b-2).

PINNACLE WEST CAPITAL CORPORATION	Yeso	Noþ
ARIZONA PUBLIC SERVICE COMPANY	Yeso	Noþ

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 ofOctober 25, 2010: 108,711,779
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of October 25, 2010: 71,264,947

Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) ofForm 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

TABLE OF CONTENTS

	Page
Forward-Looking Statements		2
Part I		3
Item 1. Financial Statements		3
Pinnacle West Capital Corporation		3
Arizona Public Service Company		44
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		53
Item 3. Quantitative and Qualitative Disclosures About Market Risk		80
Item 4. Controls and Procedures		80
Part II		81
Item 1. Legal Proceedings		81
Item 1A. Risk Factors		81
Item 5. Other Information		81
Item 6. Exhibits		83
Signatures		86
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
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

This combined Form 10-Q is separately provided by Pinnacle West Capital Corporation (“Pinnacle West”) and Arizona Public Service Company (“APS”). Any use of the words “Company,” “we,” and “our” refer to Pinnacle West. Each registrant is providing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is providing any information that does not relate to such registrant, and therefore makes no representation as to any such information. The information required with respect to each company is set forth within the applicable items. Item 1 of this report includes Condensed Consolidated Financial Statements of Pinnacle West and Condensed Consolidated Financial Statements of APS. Item 1 also includes Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS, and Supplemental Notes, which only relate to APS’ Condensed Consolidated Financial Statements. Item 2 of this report is divided into two sections — Pinnacle West Consolidated and APS. The Pinnacle West Consolidated section describes Pinnacle West and its subsidiaries on a consolidated basis, including discussions of Pinnacle West’s regulated utility and non-utility operations.

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2009 (“2009 Form 10-K”) and in Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations herein, these factors include, but are not limited to:

• regulatory and judicial decisions, developments and proceedings;

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

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

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

• power plant performance and outages;

• volatile fuel and purchased power costs;

• fuel and water supply availability;

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

• our ability to meet renewable energy requirements and recover related costs, including returns on debt and equity capital;

• 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;

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

• potential shortfalls in insurance coverage;

• new accounting requirements or new interpretations of existing requirements;

• generation, transmission and distribution facility and system conditions and operating costs;

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

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

• technological developments affecting the electric industry; and

• economic and other conditions affecting SunCor Development Company’s (“SunCor”) ability to dispose of its remaining assets and satisfy its debt obligations.

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

2

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

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

	Three Months Ended
	September 30,
	2010			2009
OPERATING REVENUES
Regulated electricity segment	$	1,116,211		$	1,083,750
Other revenues		22,874			5,286
Total		1,139,085			1,089,036
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		353,904			381,543
Operations and maintenance		221,469			198,030
Depreciation and amortization		104,194			103,008
Taxes other than income taxes		37,528			34,015
Other expenses		18,365			5,033
Total		735,460			721,629
OPERATING INCOME		403,625			367,407
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		5,524			2,197
Other income (Note 11)		4,348			4,386
Other expense (Note 11)		(3,855	)		(1,934	)
Total		6,017			4,649
INTEREST EXPENSE
Interest charges		60,491			60,299
Allowance for borrowed funds used during construction		(6,163	)		(1,349	)
Total		54,328			58,950
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		355,314			313,106
INCOME TAXES		123,486			109,778
INCOME FROM CONTINUING OPERATIONS		231,828			203,328
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $4,721 and $(7,567) (Note 14)		7,211			(12,305	)
NET INCOME		239,039			191,023
Less: Net income attributable to noncontrolling interests (Notes 7 and 16)		5,119			4,371
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	233,920		$	186,652
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		108,632			101,223
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		109,094			101,385
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	2.09		$	1.96
Net income attributable to common shareholders — basic		2.15			1.84
Income from continuing operations attributable to common shareholders — diluted		2.08			1.96
Net income attributable to common shareholders — diluted		2.14			1.84
DIVIDENDS DECLARED PER SHARE	$	—		$	0.525
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	226,700		$	198,375
Discontinued operations, net of tax		7,220			(11,723	)
Net income attributable to common shareholders	$	233,920		$	186,652

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,
	2010			2009
OPERATING REVENUES
Regulated electricity segment	$	2,527,052		$	2,498,838
Other revenues		52,982			16,164
Total		2,580,034			2,515,002
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		821,244			920,630
Operations and maintenance		644,415			610,401
Depreciation and amortization		307,864			304,066
Taxes other than income taxes		100,936			100,788
Other expenses		41,009			15,862
Total		1,915,468			1,951,747
OPERATING INCOME		664,566			563,255
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		16,417			11,919
Other income (Note 11)		3,828			4,102
Other expense (Note 11)		(8,650	)		(8,887	)
Total		11,595			7,134
INTEREST EXPENSE
Interest charges		181,937			177,447
Allowance for borrowed funds used during construction		(12,314	)		(8,318	)
Total		169,623			169,129
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		506,538			401,260
INCOME TAXES		168,143			137,594
INCOME FROM CONTINUING OPERATIONS		338,395			263,666
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $12,611 and $(97,662) (Note 14)		19,313			(165,867	)
NET INCOME		357,708			97,799
Less: Net income (loss) attributable to noncontrolling interests (Notes 7 and 16)		15,005			(690	)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	342,703		$	98,489
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		105,846			101,107
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		106,318			101,184
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations attributable to common shareholders — basic	$	3.06		$	2.47
Net income attributable to common shareholders — basic		3.24			0.97
Income from continuing operations attributable to common shareholders — diluted		3.04			2.46
Net income attributable to common shareholders — diluted		3.22			0.97
DIVIDENDS DECLARED PER SHARE	$	1.575		$	1.575
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Income from continuing operations, net of tax	$	323,361		$	249,412
Discontinued operations, net of tax		19,342			(150,923	)
Net income attributable to common shareholders	$	342,703		$	98,489

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,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	195,915		$	145,378
Customer and other receivables		387,435			301,915
Accrued unbilled revenues		180,006			110,971
Allowance for doubtful accounts		(7,901	)		(6,153	)
Materials and supplies (at average cost)		174,428			176,020
Fossil fuel (at average cost)		21,826			39,245
Deferred income taxes		134,012			53,990
Income tax receivable (Note 6)		22,840			26,005
Assets from risk management activities (Note 8)		68,476			50,619
Assets held for sale (Notes 14 and 16)		22,312			—
Other current assets		43,983			30,747
Total current assets		1,243,332			928,737
INVESTMENTS AND OTHER ASSETS
Real estate investments — net (Note 16)		—			119,989
Assets from risk management activities (Note 8)		54,968			28,855
Nuclear decommissioning trust (Note 15)		453,963			414,576
Other assets		112,797			110,091
Total investments and other assets		621,728			673,511
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		12,987,278			12,848,138
Accumulated depreciation and amortization		(4,459,579	)		(4,340,645	)
Net		8,527,699			8,507,493
Construction work in progress		555,137			467,700
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)		140,145			146,722
Intangible assets, net of accumulated amortization		178,666			164,380
Nuclear fuel, net of accumulated amortization		124,101			118,243
Total property, plant and equipment		9,525,748			9,404,538
DEFERRED DEBITS
Regulatory assets		879,056			813,161
Income tax receivable (Note 6)		65,103			65,103
Other		100,520			101,274
Total deferred debits		1,044,679			979,538
TOTAL ASSETS	$	12,435,487		$	11,986,324

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,
	2010				2009
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	253,565			$	240,637
Accrued taxes		157,697				104,011
Accrued interest		52,384				54,596
Short-term borrowings		—		��		153,715
Current maturities of long-term debt (Note 2)		238,513				303,476
Customer deposits		68,254				71,026
Liabilities from risk management activities (Note 8)		55,847				55,908
Other current liabilities		141,547				125,574
Total current liabilities		967,807				1,108,943
LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities (Note 2)		3,349,927				3,370,524
Palo Verde sale leaseback lessor notes (Notes 2 and 7)		113,379				126,000
Total long-term debt less current maturities		3,463,306				3,496,524
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,868,860				1,496,095
Deferred fuel and purchased power regulatory liability (Note 3)		41,385				87,291
Other regulatory liabilities		685,908				679,072
Liability for asset retirements		323,134				301,783
Liabilities for pension and other postretirement benefits (Note 4)		737,644				811,338
Liabilities from risk management activities (Note 8)		80,656				62,443
Customer advances		127,449				136,595
Coal mine reclamation		117,029				92,060
Unrecognized tax benefits (Note 6)		66,837				142,099
Other		127,243				144,077
Total deferred credits and other		4,176,145				3,952,853
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 9)
Common stock, no par value		2,418,660				2,153,295
Treasury stock		(2,157	)			(3,812	)
Total common stock		2,416,503				2,149,483
Retained earnings		1,473,683				1,298,213
Accumulated other comprehensive loss:
Pension and other postretirement benefits		(52,626	)			(50,892	)
Derivative instruments		(120,634	)			(80,695	)
Total accumulated other comprehensive loss		(173,260	)			(131,587	)
Total shareholders’ equity		3,716,926				3,316,109
Noncontrolling interests (Note 7)		111,303				111,895
Total equity		3,828,229				3,428,004
TOTAL LIABILITIES AND EQUITY	$	12,435,487			$	11,986,324

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,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	357,708		$	97,799
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of district cooling business		(41,973	)		—
Depreciation and amortization including nuclear fuel		350,762			338,311
Deferred fuel and purchased power		50,020			(46,743	)
Deferred fuel and purchased power amortization		(95,926	)		115,214
Allowance for equity funds used during construction		(16,417	)		(11,919	)
Real estate impairment charges		16,731			260,450
Gain on real estate debt restructuring		(14,403	)		—
Deferred income taxes		281,486			154,517
Change in mark-to-market valuations		3,716			(5,970	)
Changes in current assets and liabilities:
Customer and other receivables		(103,973	)		(79,297	)
Accrued unbilled revenues		(69,035	)		(56,420	)
Materials, supplies and fossil fuel		19,011			(16,781	)
Other current assets		(13,236	)		26,308
Accounts payable		36,687			(35,923	)
Accrued taxes and income tax receivable-net		56,851			(120,878	)
Other current liabilities		10,989			8,789
Expenditures for real estate investments		(514	)		(2,410	)
Gains and other changes in real estate assets		1,811			(10,527	)
Change in margin and collateral accounts — assets		(4,336	)		1,652
Change in margin and collateral accounts — liabilities		(143,725	)		3,564
Change in unrecognized tax benefits		(72,649	)		92,720
Change in other regulatory liabilities		40,121			92,598
Change in other long-term assets		(51,659	)		(49,577	)
Change in other long-term liabilities		(28,547	)		15,491
Net cash flow provided by operating activities		569,500			770,968
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(552,707	)		(558,495	)
Contributions in aid of construction		25,258			17,393
Allowance for borrowed funds used during construction		(12,553	)		(8,568	)
Proceeds from sale of district cooling business		100,300			—
Proceeds from nuclear decommissioning trust sales		424,255			370,399
Investment in nuclear decommissioning trust		(442,567	)		(386,743	)
Proceeds from sale of commercial real estate investments		71,174			30,847
Other		9,621			(1,404	)
Net cash flow used for investing activities		(377,219	)		(536,571	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		—			867,582
Repayment of long-term debt		(84,529	)		(421,079	)
Short-term borrowings and payments — net		(153,715	)		(528,217	)
Dividends paid on common stock		(161,722	)		(153,740	)
Common stock equity issuance		255,156			2,623
Noncontrolling interests		(3,286	)		(3,393	)
Other		6,352			(2,594	)
Net cash flow used for financing activities		(141,744	)		(238,818	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		50,537			(4,421	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		145,378			105,245
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	195,915		$	100,824
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	(22,165	)	$	(34,700	)
Interest, net of amounts capitalized	$	167,576		$	163,438

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”), and El Dorado Investment Company (“El Dorado”). Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde sale leaseback variable interest entities (“VIEs”) (see Note 7 for further discussion). Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

In preparing the condensed consolidated financial statements, we have evaluated the events that have occurred after December 31, 2009 through the date the financial statements were issued. Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. The December 31, 2009 condensed consolidated balance sheet data was derived from audited financial statements, but does not include disclosures required by GAAP for audited annual statements. This quarterly report should be reviewed in conjunction with the audited financial statements included in the 2009 Form 10-K. These condensed consolidated financial statements and notes have been prepared consistently with the 2009 Form 10-K with the exception of certain line items that are presented in more detail on the Condensed Consolidated Statements of Cash Flows than were presented in the prior year. The prior year amounts were reclassified to conform to the current year presentation. Change in margin and collateral accounts — assets is presented as a separate line item instead of as a single line item of change in other long-term assets as previously reported. Change in margin and collateral accounts — liabilities is presented as a separate line item instead of as a single line item of change in other long-term liabilities as previously reported. There has also been a reclassification of certain prior-year amounts on our Condensed Consolidated Statements of Income, Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows in accordance with accounting requirements for reporting discontinued operations (see Note 14) and amended accounting guidance on consolidation of VIEs (see Note 7). The following tables show the impacts of the reclassifications to prior year (previously reported) amounts (dollars in thousands):

8

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

										Amount
										reported after
				Reclassifications						adoption of
				as a result of the						amended VIE
				adoption of						accounting
	As			new VIE			Reclassifications			guidance and
Statement of Income for the	previously			accounting			for discontinued			discontinued
Three Months Ended September 30, 2009	reported			guidance			operations			operations
Operating Revenues
Real estate segment	$	47,602		$	—		$	(47,602	)	$	—
Other revenues		10,853			—			(5,567	)		5,286
Operating Expenses
Real estate segment operations		25,074			—			(25,074	)		—
Real estate impairment charge		37,051			—			(37,051	)		—
Operations and maintenance		208,769			(9,916	)		(823	)		198,030
Depreciation and amortization		102,246			1,927			(1,165	)		103,008
Taxes other than income taxes		34,111			—			(96	)		34,015
Other expenses		8,014			—			(2,981	)		5,033
Other
Other income		4,650			—			(264	)		4,386
Interest Expense
Interest charges		60,161			3,036			(2,898	)		60,299
Allowance for borrowed funds used during construction		(1,423	)		—			74			(1,349	)
Income Taxes		103,507			—			6,271			109,778
Income From Continuing Operations		188,065			4,953			10,310			203,328
Loss From Discontinued Operations		(1,995	)		—			(10,310	)		(12,305	)
Net Income		186,070			4,953			—			191,023
Net Income (Loss) Attributable To Noncontrolling Interests		(582	)		4,953			—			4,371
Statement of Income for the Nine Months Ended September 30, 2009
Operating Revenues
Real estate segment	$	75,122		$	—		$	(75,122	)	$	—
Other revenues		30,084			—			(13,920	)		16,164
Operating Expenses
Real estate segment operations		71,413			—			(71,413	)		—
Real estate impairment charge		241,469			—			(241,469	)		—
Operations and maintenance		642,545			(29,745	)		(2,399	)		610,401
Depreciation and amortization		302,166			5,778			(3,878	)		304,066
Taxes other than income taxes		101,126			—			(338	)		100,788
Other expenses		22,214			—			(6,352	)		15,862
Other
Other income		4,820			—			(718	)		4,102
Interest Expense
Interest charges		174,720			9,713			(6,986	)		177,447
Allowance for borrowed funds used during construction		(8,568	)		—			250			(8,318	)
Income Taxes		48,082			—			89,512			137,594
Income From Continuing Operations		96,099			14,254			153,313			263,666
Loss From Discontinued Operations		(12,554	)		—			(153,313	)		(165,867	)
Net Income		83,545			14,254			—			97,799
Net Loss Attributable To Noncontrolling Interests		(14,944	)		14,254			—			(690	)

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

			Reclassifications as a			Amounts reported
			result of the adoption of			after adoption of
	As previously		the new VIE accounting			amended VIE
Balance Sheets — December 31, 2009	reported		guidance			accounting guidance
Property, Plant and Equipment — Palo Verde sale leaseback, net of accumulated depreciation	$	—	$	146,722		$	146,722
Deferred Debits — Regulatory assets		781,714		31,447			813,161
Current Liabilities — Current maturities of long-term debt		277,693		25,783			303,476
Long-Term Debt Less Current Maturities — Palo Verde sale leaseback lessor notes		—		126,000			126,000
Deferred Credits and Other — Other		200,015		(55,938	)		144,077
Equity — Noncontrolling Interests		29,571		82,324			111,895

							Amounts reported
				Reclassifications as a			after adoption of
				result of the adoption of			amended VIE
				the new VIE accounting			accounting guidance
				guidance and to conform			and to conform to
Statement of Cash Flows for the	As previously			to current year			current year
Nine Months Ended September 30, 2009	reported			presentation			presentation
Cash Flows from Operating Activities
Net income	$	83,545		$	14,254		$	97,799
Depreciation and amortization including nuclear fuel		332,532			5,779			338,311
Other current liabilities		25,808			(17,019	)		8,789
Change in margin and collateral accounts-assets		—			1,652			1,652
Change in margin and collateral accounts-liabilities		—			3,564			3,564
Other long-term assets		(47,925	)		(1,652	)		(49,577	)
Other long-term liabilities		12,071			3,420			15,491
Cash Flows from Financing Activities
Repayment and acquisition of long-term debt		(414,474	)		(6,605	)		(421,079	)
Noncontrolling interests		—			(3,393	)		(3,393	)
Supplemental Disclosure of Cash Flow Information
Cash paid for Interest, Net of Amounts Capitalized		153,725			9,713			163,438

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2. Long-term Debt and Liquidity Matters

The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements as of September 30, 2010 (dollars in millions):

	Consolidated		Consolidated
Year	Pinnacle West		APS
2010	$	23	$	17
2011		632		457
2012		478		478
2013		140		140
2014		503		503
Thereafter		1,932		1,932
Total	$	3,708	$	3,527

Credit Facilities, Debt and Equity Issuances

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

Pinnacle West

On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. The new facility matures in February 2013. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Pinnacle West will use the facility for general corporate purposes, commercial paper support and for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. As a result of the downsized credit facility, the Company also reduced the size of its commercial paper program to $200 million from $250 million.

At September 30, 2010, the $200 million credit facility was available to support the issuance of up to $200 million in commercial paper or for bank borrowings, including issuances of letters of credit up to $100 million. At September 30, 2010, Pinnacle West had no outstanding borrowings under this credit facility, no commercial paper borrowings and no outstanding letters of credit.

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

In June 2010, Pinnacle West received approximately $100 million related to the sale of APSES’ district cooling business. The net proceeds were used to repay short-term indebtedness.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS

On February 12, 2010, APS refinanced its $377 million credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. The new credit facility terminates in February 2013. APS has the option to increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility for general corporate purposes, commercial paper support and for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.

At September 30, 2010, APS had two credit facilities totaling $989 million, including the $500 million credit facility described above and a $489 million facility that terminates in September 2011. These facilities are available either to support the issuance of up to $250 million in commercial paper or for bank borrowings, including issuances of letters of credit up to $739 million. At September 30, 2010, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. A $20 million letter of credit was issued under APS’ $489 million credit facility in the second quarter of 2010.

On July 13, 2010, APS changed the interest rate mode for the approximately $33 million of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Navajo Project) 1994 Series A, due 2029. The rate period for the bonds changed from a daily rate mode, supported by a letter of credit, to a three-year term rate mode that will bear interest at a rate of 3.625% per annum for three years. The letter of credit was terminated in connection with this change, and there is no bank or other third-party credit support for the bonds in the term rate mode.

On August 10, 2010, APS changed the letter of credit supporting the approximately $17 million of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Project) Series 1998, due 2033. The bonds were in a daily rate mode supported by a letter of credit and remain in a daily rate mode, supported by a new three-year letter of credit expiring in August 2013.

On October 12, 2010, APS changed the interest rate mode for the approximately $147 million of City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project) 1994 Series A and 1994 Series B, due 2024 and City of Farmington, New Mexico Pollution Control Revenue Bonds (Arizona Public Service Company Four Corners Project) 1994 Series C, due 2024. The rate period for the 1994 Series A bonds and the 1994 Series B bonds changed from a daily rate mode, supported by letters of credit, to a term rate mode to maturity with an optional redemption after year ten that will bear interest at a rate of 4.70% per annum until maturity in 2024 unless the optional redemption is exercised by APS. The rate period for the 1994 Series C bonds changed from a daily rate mode, supported by a letter of credit, to a three-year term rate mode that will bear interest at a rate of 2.875% per annum until October 2013. The letters of credit supporting each of these three series of bonds were terminated in connection with these changes, and there is no bank or other third-party credit support for any of these bonds.

On January 1, 2010, due to the adoption of amended accounting guidance relating to VIEs, APS began consolidating the Palo Verde Lessor Trusts (see Note 7) and, as a result of consolidation of these VIEs, APS has reported the Lessor Trusts’ long-term debt on its Condensed Consolidated Balance Sheets. Interest rates on these debt instruments are 8% and are fixed for the remaining life of the debt. As of September 30, 2010, approximately $30 million was classified as current maturities of long-term debt and $113 million was classified as long-term debt relating to these VIEs. These debt instruments mature on December 30, 2015 and have sinking fund features that are serviced by the lease payments. See Note 7 for additional discussion of the VIEs.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SunCor

In July 2010, SunCor sold land parcels, commercial assets and a master planned home-building community for approximately $70 million, which approximated the carrying value of these assets, resulting in a net gain of zero. In connection with this sale, SunCor negotiated a restructuring of certain of its credit facilities, including its principal loan facility. The debt restructuring resulted in an after-tax gain of approximately $9 million, which was recognized in the third quarter of 2010.

At September 30, 2010, SunCor had approximately $22 million of assets on its balance sheet classified as assets held for sale. These assets consisted of $18 million of consolidated VIEs (see Note 7), master planned home-building communities and golf courses. Because it is expected that SunCor will dispose of these assets within the next 12 months, they are classified as assets held for sale on the balance sheet.

At September 30, 2010, SunCor had $6 million in debt outstanding, a portion of which is in default. 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 repay remaining debt outstanding would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

As of September 30, 2010, SunCor could not transfer any cash dividends to Pinnacle West. This restriction does not affect Pinnacle West’s ability to meet its ongoing capital requirements.

Debt Provisions

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At September 30, 2010, APS’ common equity ratio, as defined, was 53%. Its total shareholder equity was approximately $3.8 billion, and total capitalization was approximately $7.2 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’ total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

3. Regulatory Matters

2008 General Retail Rate Case Impacts

On December 30, 2009, the ACC issued an order approving a settlement agreement (“Settlement Agreement”) entered into by APS and twenty-one other parties to its general retail rate case, which was originally filed in March 2008. The Settlement Agreement contains on-going requirements, commitments and authorizations, including the following:

• Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’ next general rate case, if that is before the end of 2012), which resulted in projected estimates of increased revenues of $23 million, $25 million and $49 million, respectively (as of September 30, 2010, estimates for the 2010 year are expected to be $17 — $21 million);

• An authorized return on common equity of 11%;

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

• A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

• Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010 (see Note 2)); and

• Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.

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

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

Renewable Energy Standard.In 2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (“RES”). Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge on customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for the upcoming year’s RES funding amount.

During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval. The plan provided for the acquisition of renewable generation in compliance with requirements through 2014, and requested RES funding of $86.7 million for 2010, which was later approved by the ACC. APS also sought various other determinations in its plan, including approval of the AZ Sun Program and the Community Power Project in Flagstaff, Arizona described below.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On March 3, 2010, the ACC approved the AZ Sun Program, which contemplates the addition of 100 megawatts (“MW”) of APS-owned solar resources through 2014. Through this program, APS plans to invest up to $500 million in solar photovoltaic projects across Arizona, which APS will acquire through competitive procurement processes. The costs associated with the first 50 MW under this program will be recovered initially through the RES until such time as the costs are recovered in base rates. The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’ next retail rate case. As of September 30, 2010, APS had signed two contracts to develop 33 MW of photovoltaic power for approximately $150 million under the AZ Sun Program.

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

On July 1, 2010, APS filed its annual RES implementation plan, covering the 2011-2015 timeframe and requesting 2011 RES funding of $96.4 million. The 2011 Plan addressed enhancements to the residential distributed energy incentive program based on high customer participation and additional programs offered in response to ACC workshops on “feed in tariffs,” which provide opportunities for streamlined development of certain renewable projects. On October 13, 2010, APS filed an adjusted RES implementation plan to reflect the following items, among others: 1) increased clarity relating to customer project in-service dates and related budget revisions; 2) AZ Sun Program updates; and 3) addition of 10 MW of biomass capacity. In addition, APS lowered its 2011 RES funding request to $92.5 million primarily as a result of an improved understanding of the timing of incentives payable for commercial projects. APS expects the ACC to vote on the 2011 Plan in the fourth quarter of 2010.

Demand-Side Management Adjustor Charge (“DSMAC”).The Settlement Agreement requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan, requesting approval by the ACC of programs and program elements for which APS had estimated a budget in the amount of $49.9 million for 2010. APS received ACC approval of all of its proposed programs and implemented the new DSMAC on March 1, 2010. A surcharge was added to customer bills in order to recover these estimated amounts for use on certain demand-side management programs. The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.

The ACC approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the Settlement Agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery is to be spread over a three-year period.

On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the Settlement Agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79.2 million. If this plan is approved by the ACC as proposed, and when added to the amortization of 2009 costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $74.8 million over a twelve month period beginning March 1, 2011. These amounts do not include $1.3 million for an electric vehicle charging station program submitted to the ACC for approval on September 30, 2010.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PSA Mechanism and Balance.The power supply adjustor (“PSA”) provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs from the “Base Fuel Rate,” which is currently $0.0376 per kilowatt-hour (“kWh”). The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for the nine-month periods ended September 30, 2010 and 2009 (dollars in millions):

	Nine Months Ended
	September 30,
	2010			2009
Beginning balance	$	(87	)	$	8
Deferred fuel and purchased power costs-current period		(50	)		47
Amounts refunded (recovered)		96			(115	)
Ending balance	$	(41	)	$	(60	)

The PSA rate for the current PSA year is ($0.0045) per kWh. Since the 2010 PSA adjustment was a reduction of the PSA rate, the ACC accelerated the 2010 adjustment from the standard PSA year start date of February 1^st to January 1^st to coincide with the increase in retail rates resulting from the ACC’s decision in the general retail rate case, causing a minimal net impact on residential bills. This accelerated 2010 adjustment will remain in effect until February 1, 2011. The regulatory liability at September 30, 2010 reflects lower average prices and the seasonal nature of fuel and purchased power costs. Any uncollected (overcollected) deferrals during the 2010 PSA year will be included in the historical component of the PSA rate for the PSA year beginning February 1, 2011.

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

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

The formula rate is updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Effective June 1, 2010, APS’ annual wholesale transmission rates for all users of its transmission system were reduced by approximately $12 million in accordance with the FERC-approved formula as a result of lower costs reflected in the formula. Approximately $10 million of this revenue reduction relates to transmission services used for APS’ retail customers. On May 20, 2010, APS filed with the ACC an application for the related reduction of its TCA rate. The ACC approved the TCA reduction on July 27, 2010.

Decoupling. On October 18, 2010, the Chairman of the ACC issued a draft decoupling policy statement. Decoupling refers to a ratemaking design which reduces or removes the linkage between sales and utility revenues and/or profits, reducing utility disincentives to the adoption of programs that benefit customers by saving energy. Mechanically, decoupling compares actual versus authorized revenues or revenue per customer over a period and either credits or collects any differences from customers in a subsequent period. The draft policy is supportive of decoupling using a revenue-per-customer methodology, which is the mechanism APS and a number of other parties support because it recognizes increased costs associated with additional customers. The draft policy would allow a utility to file a decoupling plan in its next general rate case. Subsequent steps by the ACC prior to approving any policy statement will likely depend on the nature and extent of the comments received from various stakeholders.

4. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.

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

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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						Nine Months						Three Months						Nine Months
	Ended						Ended						Ended						Ended
	September 30,						September 30,						September 30,						September 30,
	2010			2009			2010			2009			2010			2009			2010			2009
Service cost — benefits earned during the period	$	14		$	13		$	42		$	40		$	4		$	4		$	14		$	14
Interest cost on benefit obligation		31			29			92			88			11			10			32			29
Expected return on plan assets		(31	)		(29	)		(93	)		(87	)		(9	)		(9	)		(29	)		(26	)
Amortization of:
Transition obligation		—			—			—			—			—			1			—			2
Prior service cost		—			1			1			2			—			—			—			—
Net actuarial loss		5			4			15			11			2			3			7			8
Net periodic benefit cost	$	19		$	18		$	57		$	54		$	8		$	9		$	24		$	27
Portion of cost charged to expense	$	10		$	9		$	29		$	26		$	4		$	4		$	12		$	13
APS’ share of cost charged to expense	$	9		$	8		$	28		$	25		$	4		$	4		$	12		$	12

Contributions

The required minimum contribution to our pension plan is zero in 2010. During the first quarter of 2010, we made a voluntary contribution of $100 million to our pension plan. The contribution to our other postretirement benefit plans in 2010 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 98% of both plans.

5. Business Segments

Pinnacle West’s two reportable business segments are:

• our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and related activities and includes electricity generation, transmission and distribution; and

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

In July 2010, SunCor sold land parcels, commercial assets and a master planned home-building community. It is expected that SunCor will dispose of its remaining assets within the next 12 months. As a result, they are classified as assets held for sale on the balance sheet at September 30, 2010 and all of SunCor’s operations are reflected in discontinued operations. While segment reporting is not required for discontinued operations, Pinnacle West continues to provide the information below, due to the significant impacts of real estate impairments in 2009. See Note 14 — Discontinued Operations.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Financial data for the three and nine months ended September 30, 2010 and 2009 and at September 30, 2010 and December 31, 2009 is provided as follows (dollars in millions):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010			2009
Operating revenues:
Regulated electricity segment	$	1,116	$	1,084		$	2,527		$	2,499
All other (a)		23		5			53			16
Total	$	1,139	$	1,089		$	2,580		$	2,515
Net income (loss) attributable to common shareholders:
Regulated electricity segment	$	225	$	200		$	320		$	257
Real estate segment		8		(12	)		(6	)		(153	)
All other (a)		1		(1	)		29			(6	)
Total	$	234	$	187		$	343		$	98

	As of		As of
	September 30, 2010		December 31, 2009
Assets:
Regulated electricity segment	$	12,324	$	11,691
Real estate segment		41		161
All other (a)		70		134
Total	$	12,435	$	11,986

(a) Includes activities related to APSES and El Dorado. None of the activities of either of these companies constitutes a reportable segment. All other also includes the sale of APSES’ district cooling business, which resulted in an after-tax gain of $25 million for the nine months ended September 30, 2010. See Note 14 — Discontinued Operations.

6. Income Taxes

Pinnacle West expects to receive approximately $132 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 16), which will not be fully realized until all of the asset sales are completed. Approximately $7 million of these benefits were recorded in the nine months ended September 30, 2010 as reductions to income tax expense related to the current impairment charges. The additional $125 million of tax benefits were recorded as reductions to income tax expense related to SunCor impairment charges recorded on or before December 31, 2009.

The $88 million income tax receivables on the Condensed Consolidated Balance Sheets represent the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009 and the current year tax benefits related to the SunCor strategic asset sales that closed in 2010.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

As of September 30, 2010, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 1999.

7. Variable Interest Entities

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

APS VIEs

In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Nuclear Generating Station (“Palo Verde”) Unit 2 and related common facilities. The VIE lessor trusts are single-asset leasing entities. APS will pay approximately $49 million per year for the years 2010 to 2015 related to these leases. The leases do not contain fixed price purchase options or residual value guarantees. However, the lease agreements include fixed rate renewal periods which may have a significant impact on the VIEs’ economic performance. We have concluded that these fixed rate renewal periods may give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. In addition to the fixed rate renewal periods, our primary beneficiary analysis also considered that APS is the operating agent for Palo Verde, is obligated to decommission the leased assets and has fair value purchase options.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Consolidation of these VIEs eliminates the lease accounting we previously reported and results in changes in our consolidated assets, debt, equity, and net income. Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. The creditors of the VIEs have no recourse to the assets of APS or Pinnacle West. As a result of consolidation we have eliminated rent expense, and have recognized depreciation and interest expense, resulting in an increase in net income for the three and nine months ended September 30, 2010 of $5 million and of $15 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.

Our Condensed Consolidated Balance Sheets at September 30, 2010 include the following amounts relating to the VIEs (in millions):

	September 30,
	2010
Property plant and equipment, net of accumulated depreciation	$	140
Long-term debt including current maturities		143
Equity- Noncontrolling interests		94

For regulatory ratemaking purposes the leases continue to be treated as operating leases, and as a result we have recorded a regulatory asset of $32 million as of September 30, 2010.

APS is exposed to losses relating to these lessor trust VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of September 30, 2010, APS would have been required to pay the noncontrolling equity participants approximately $152 million and assume $143 million of debt. Since APS now consolidates the VIEs, the debt APS would be required to assume is already reflected in our Condensed Consolidated Balance Sheets.

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

SunCor VIEs

SunCor is the primary beneficiary of certain land development trust arrangements and, accordingly, consolidates these VIEs. We have determined that SunCor is the primary beneficiary of these VIEs because SunCor controls the activities related to the development of the land held in the trusts. Our adoption of amended VIE accounting guidance has not changed our accounting treatment of the SunCor VIEs. Our Condensed Consolidated Balance Sheets reflect $18 million of assets and $18 million of noncontrolling equity interests relating to these arrangements at September 30, 2010. Our Condensed Consolidated Balance Sheets reflect $29 million of assets and $29 million of noncontrolling equity interests related to these arrangements at December 31, 2009. The assets relating to these VIEs consist strictly of land, all of which is restricted and may only be used for payment to the noncontrolling interests. We have not provided, and are not required to provide, financing or other financial support to these entities.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. Derivative and Energy Trading Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. Derivative instruments that are designated as cash flow hedges are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

Our derivative instruments are accounted for at fair value and are presented on the Condensed Consolidated Balance Sheets as “Assets/Liabilities from Risk Management Activities” (see Note 15 for a discussion of fair value measurements). Derivative instruments for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales scope exception and are accounted for under the accrual method of accounting. Due to the scope exception, these derivative instruments are excluded from our derivative instrument discussion and disclosures below.

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

Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value between the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of accumulated other comprehensive income (“AOCI”) and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As of September 30, 2010, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For its regulated operations, APS defers for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the portion of APS’ retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”), which is currently $0.0376 per kWh (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of September 30, 2010, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):

Commodity	Quantity
Power		14,149,591	megawatt hours
Gas		149,026,687	MMBTU (a)

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

Derivative Instruments in Designated Accounting Hedging Relationships

The following table provides information about gains and losses from derivative instruments in designated accounting hedging relationships and their impact on our Condensed Consolidated Statements of Income during the three and nine months ended September 30, 2010 and 2009 (dollars in thousands):

		Three Months Ended						Nine Months Ended
	Financial Statement	September 30,						September 30,
Commodity Contracts	Location	2010			2009			2010			2009
Amount of Gain (Loss) Recognized in AOCI on Derivative Instruments (Effective Portion)	Accumulated other comprehensive loss-derivative instruments	$	(67,856	)	$	4,959		$	(168,110	)	$	(128,035	)
Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)	Regulated electricity segment fuel and purchased power		(59,801	)		(81,660	)		(102,130	)		(154,990	)
Amount of Gain (Loss) Recognized in Income from Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)	Regulated electricity segment fuel and purchased power		(68	)		(9,085	)		1,364			(12,993	)

(a) During the three and nine months ended September 30, 2010 and 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 $119 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions. Approximately 90% of the amounts related to derivatives subject to the PSA will be recorded as either a regulatory asset or liability and have no effect on earnings.

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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, 2010 and 2009 (dollars in thousands):

		Three Months Ended					Nine Months Ended
	Financial Statement	September 30,					September 30,
Commodity Contracts	Location	2010			2009		2010			2009
Amount of Net Gain Recognized in Income from Derivative Instruments	Regulated electricity segment revenue	$	1,721		$	126	$	2,316		$	464
Amount of Net Gain (Loss) Recognized in Income from Derivative Instruments	Regulated electricity segment fuel and purchased power expense		(41,044	)		23,463		(105,272	)		(18,259	)
Total		$	(39,323	)	$	23,589	$	(102,956	)	$	(17,795	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. These amounts are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of September 30, 2010 (dollars in thousands):

				Investments			Current			Deferred Credits			Total Assets
Commodity Contracts	Current Assets			and Other Assets			Liabilities			and Other			(Liabilities)
Derivatives designated as accounting hedging instruments:
Assets	$	2		$	—		$	—		$	—		$	2
Liabilities		(1,311	)		(2,159	)		(123,351	)		(86,043	)		(212,864	)
Total hedging instruments		(1,309	)		(2,159	)		(123,351	)		(86,043	)		(212,862	)
Derivatives not designated as accounting hedging instruments:
Assets		40,078			57,154			45,700			30,659			173,591
Liabilities		(1,257	)		(27	)		(124,165	)		(126,066	)		(251,515	)
Total non-hedging instruments		38,821			57,127			(78,465	)		(95,407	)		(77,924	)
Total derivatives		37,512			54,968			(201,816	)		(181,450	)		(290,786	)
Margin account		23,822			—			2,068			—			25,890
Collateral provided to counterparties		12,701			—			145,230			100,794			258,725
Collateral provided from counterparties		(6,750	)		—			(1,250	)		—			(8,000	)
Prepaid option premiums and other		1,191			—			(79	)		—			1,112
Balance Sheet Total	$	68,476		$	54,968		$	(55,847	)	$	(80,656	)	$	(13,059	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information about the fair value of our derivative instruments, margin account and cash collateral reported on a gross basis at December 31, 2009 (dollars in thousands):

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

Credit Risk and Credit-Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 51% of Pinnacle West’s $123 million of risk management assets as of September 30, 2010. This exposure relates to long-term traditional wholesale contracts with counterparties that have very high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on September 30, 2010 was $430 million, for which we had posted collateral of $247 million in the normal course of business.

For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s Ratings Services (“Standard & Poor’s”) or Fitch, Inc. (“Fitch”) or Baa3 for Moody’s Investors Service, Inc. (“Moody’s”)), which would be a violation of the credit rating provisions. If the investment grade contingent features underlying these agreements had been fully triggered on September 30, 2010, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $111 million of collateral to our counterparties; this amount includes those contracts that 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 require us to post additional collateral of approximately $204 million if our debt credit ratings were to fall below investment grade.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. Changes in Equity

The following tables show Pinnacle West’s changes in shareholders’ equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2010 and 2009 (dollars in thousands):

	Three Months Ended September 30, 2010									Three Months Ended September 30, 2009
	Common			Noncontrolling						Common			Noncontrolling
	Shareholders			Interests			Total			Shareholders			Interests			Total
Beginning balance, July 1	$	3,479,548		$	113,455		$	3,593,003		$	3,206,805		$	112,677		$	3,319,482
Net income		233,920			5,119			239,039			186,652			4,371			191,023
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		(67,856	)		—			(67,856	)		4,959			—			4,959
Net reclassification of realized losses to income (b)		59,801			—			59,801			81,660			—			81,660
Reclassification of pension and other postretirement benefits to income		1,314			—			1,314			1,240			—			1,240
Net income tax benefit (expense) related to items of other comprehensive income (loss)		2,660			—			2,660			(34,495	)		—			(34,495	)
Total other comprehensive income (loss)		(4,081	)		—			(4,081	)		53,364			—			53,364
Total comprehensive income		229,839			5,119			234,958			240,016			4,371			244,387
Issuance of capital stock		2,506			—			2,506			2,756			—			2,756
Purchase of treasury stock, net of reissuances		577			—			577			589			—			589
Other (primarily stock compensation)		4,456			—			4,456			(372	)		—			(372	)
Dividends on common stock		—			—			—			(53,132	)		—			(53,132	)
Net capital activities by noncontrolling interests		—			(7,271	)		(7,271	)		—			(93	)		(93	)
Ending balance, September 30	$	3,716,926		$	111,303		$	3,828,229		$	3,396,662		$	116,955		$	3,513,617

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2009
	Common			Noncontrolling						Common			Noncontrolling
	Shareholders			Interests			Total			Shareholders			Interests			Total
Beginning balance, January 1	$	3,316,109		$	111,895		$	3,428,004		$	3,445,979		$	124,990		$	3,570,969
Net income (loss)		342,703			15,005			357,708			98,489			(690	)		97,799
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)		(168,110	)		—			(168,110	)		(128,035	)		—			(128,035	)
Net reclassification of realized losses to income (b)		102,130			—			102,130			154,990			—			154,990
Reclassification of pension and other postretirement benefits to income		4,069			—			4,069			3,745			—			3,745
Net unrealized losses related to pension and other postretirement benefits		(6,933	)		—			(6,933	)		(4,204	)		—			(4,204	)
Net income tax benefit (expense) related to items of other comprehensive income (loss)		27,171			—			27,171			(10,337	)		—			(10,337	)
Total other comprehensive income (loss)		(41,673	)		—			(41,673	)		16,159			—			16,159
Total comprehensive income (loss)		301,030			15,005			316,035			114,648			(690	)		113,958
Issuance of capital stock		260,665			—			260,665			8,102			—			8,102
Purchase of treasury stock, net of reissuances		1,655			—			1,655			(957	)		—			(957	)
Other (primarily stock compensation)		4,598			—			4,598			(11,899	)		—			(11,899	)
Dividends on common stock		(167,131	)		—			(167,131	)		(159,211	)		—			(159,211	)
Net capital activities by noncontrolling interests		—			(15,597	)		(15,597	)		—			(7,345	)		(7,345	)
Ending balance, September 30	$	3,716,926		$	111,303		$	3,828,229		$	3,396,662		$	116,955		$	3,513,617

(a)	These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.
(b)	These amounts primarily include the reclassification of unrealized gains and losses to realized gains and losses for contracted commodities delivered during the period.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

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

Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS pursued a damages claim for costs incurred through December 2006 in a trial that began on January 28, 2009. On June 18, 2010, the court awarded APS and the other Palo Verde owners approximately $30 million. APS received its share of this amount in October 2010, which is approximately $9 million.

APS currently estimates it will incur $132 million (in 2010 dollars) over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At September 30, 2010, APS had a regulatory liability of $46 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to purchase obligations and various fuel and purchased power contracts with terms expiring between 2010 and 2042 that include required purchase provisions. APS estimates the contract requirements to be approximately $727 million in 2010; $527 million in 2011; $435 million in 2012; $515 million in 2013; $550 million in 2014; and $7.6 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. These amounts have increased since the 2009 Form 10-K primarily due to increased commitments for fuel and purchased power and contracts associated with meeting our renewable energy requirements.

Coal Mine Reclamation Obligations

APS is obligated to reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation recorded on the Condensed Consolidated Balance Sheets was estimated to be $117 million at September 30, 2010 and $92 million at December 31, 2009.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FERC Market Issues

APS reached a settlement on previously disputed matters resulting from its involvement in the California energy market during specified time frames in the early 2000s. The settlement 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 APS’ financial position, results of operations or cash flows.

On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

Superfund

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

Landlord Bankruptcy

On April 16, 2009, the landlord for our corporate headquarters building announced that it is seeking relief under Chapter 11 of the United States Bankruptcy Code. At September 30, 2010, we have several assets on our books related to our landlord, the most significant of which is an asset related to levelized rent payments for the building of approximately $70 million which is included in other deferred debits on the Condensed Consolidated Balance Sheets. This amount will continue to increase to approximately $93 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Nuclear Insurance

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

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $16 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $44 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

32

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

11. Other Income and Other Expense

The following table provides detail of other income and other expense for the three and nine months ended September 30, 2010 and 2009 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Other income:
Interest income	$	943		$	543		$	2,597		$	1,185
Investment gains — net		3,390			3,696			1,051			120
Miscellaneous		15			147			180			2,797
Total other income	$	4,348		$	4,386		$	3,828		$	4,102
Other expense:
Non-operating costs	$	(2,894	)	$	(1,643	)	$	(5,917	)	$	(6,498	)
Miscellaneous		(961	)		(291	)		(2,733	)		(2,389	)
Total other expense	$	(3,855	)	$	(1,934	)	$	(8,650	)	$	(8,887	)

12. Guarantees

We have issued parental guarantees and obtained surety bonds on behalf of our subsidiaries including credit support instruments enabling APSES to offer energy-related products and surety bonds at APS, principally related to self-insured workers’ compensation. Non-performance or non-payment under the underlying contract by our subsidiaries would result in a payment liability on our part 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 and surety bonds on behalf of our subsidiaries. At September 30, 2010, we had no outstanding claims for payment under any of these guarantees. Our guarantees and surety bonds have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees or surety bonds from our subsidiaries. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at September 30, 2010 are as follows (dollars in millions):

	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
APSES	$	5		1	$	42		1
APS		3		1		9		1
Total	$	8			$	51

APS has entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2010, approximately $194 million of letters of credit were outstanding to support existing pollution control bonds of approximately $190 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations. In connection with the change of interest rate modes and termination of corresponding letters of credit for certain pollution control bonds described in Note 2, the letters of credit outstanding have decreased since September 30, 2010. Currently, there are approximately $44 million of letters of credit outstanding to support existing pollution control bonds of approximately $44 million. These letters of credit expire in 2011 and 2013. APS has also entered into approximately $61 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 7 for further details on the Palo Verde sale leaseback transactions). These letters of credit were amended and extended in April 2010, and will expire in 2013.

33

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

13. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010		2009
Basic earnings per share:
Income from continuing operations attributable to common shareholders	$	2.09	$	1.96		$	3.06	$	2.47
Income (loss) from discontinued operations		0.06		(0.12	)		0.18		(1.50	)
Earnings per share — basic	$	2.15	$	1.84		$	3.24	$	0.97
Diluted earnings per share:
Income from continuing operations attributable to common shareholders	$	2.08	$	1.96		$	3.04	$	2.46
Income (loss) from discontinued operations		0.06		(0.12	)		0.18		(1.49	)
Earnings per share — diluted	$	2.14	$	1.84		$	3.22	$	0.97

Dilutive stock options and performance shares (which are contingently issuable) increased average diluted common shares outstanding by approximately 462,000 shares and 162,000 shares for the three months ended September 30, 2010 and 2009, respectively, and by approximately 472,000 and 77,000 shares for the nine months ended September 30, 2010 and 2009, respectively.

Options to purchase 175,333 shares of common stock for the three-month period ended September 30, 2010, and 561,157 shares for the three-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 322,333 shares and 595,335 shares of common stock for the nine-month periods ended September 30, 2010 and September 30, 2009, respectively, 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.

34

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. Discontinued Operations

SunCor(real estate segment)—In July 2010, SunCor sold land parcels, commercial assets and a master planned home-building community for approximately $70 million, which approximated the carrying value of these assets, resulting in a net gain of zero. At September 30, 2010, SunCor had approximately $22 million of assets on its balance sheet classified as assets held for sale. These assets consist of $18 million of consolidated VIEs (see Note 7), master planned home-building communities and golf courses. Because it is expected that SunCor will dispose of these assets within the next 12 months, they are classified as assets held for sale on the balance sheet. As a result, for the three and nine months ended September 30, 2010, all of SunCor’s operations are reflected in discontinued operations. Prior comparative period income statement amounts related to these properties were reclassified from continuing operations to discontinued operations. In addition, see Note 16 — Real Estate Impairment Charge.

APSES(other)—On June 22, 2010, our subsidiary, APSES, sold its district cooling business consisting of operations in downtown Phoenix, Tucson, and on certain Arizona State University campuses. As a result of the sale, we recorded an after-tax gain from discontinued operations of approximately $25 million in June 2010. Prior period income statement amounts related to this sale and the associated revenues and costs are reflected in discontinued operations in 2010 and 2009.

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, 2010 and 2009 (dollars in millions):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenue:
SunCor	$	4		$	49		$	25		$	85
APSES		—			5			7			14
Total revenue	$	4		$	54		$	32		$	99
Income (loss) before taxes:
SunCor	$	14		$	(20	)	$	(10	)	$	(252	)
APSES		(2	)		1			42			3
Total income (loss) before taxes	$	12		$	(19	)		32		$	(249	)
Income (loss) after taxes:
SunCor (a)	$	8		$	(12	)	$	(6	)	$	(153	)
APSES		(1	)		1			26			2
Total income (loss) after taxes	$	7		$	(11	)	$	20		$	(151	)

(a) Includes a tax (expense) benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of ($6) million and $8 million for the three months ended September 30, 2010, and 2009, respectively; and $4 million and $99 million for the nine months ended September 30, 2010 and 2009, respectively.

35

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

15. Fair Value Measurements

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

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

Level 2 — Quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable. This category includes nonexchange-traded derivative instruments such as forwards, options, and swaps. This category also includes investments in common and commingled funds that are redeemable and valued based on the funds’ net asset values.

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

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We maximize the use of observable inputs and minimize the use of unobservable inputs. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market transactions, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Recurring Fair Value Measurements

We apply recurring fair value measurements to derivative instruments, nuclear decommissioning trusts, certain cash equivalents and plan assets held in our retirement and other benefit plans.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cash Equivalents

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

Risk Management Activities

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

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

Some of our derivative instrument transactions are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable inputs 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.

Nuclear Decommissioning Trust

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 and are classified within Level 2. We may transact in the fund on a semi-monthly basis. Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. The trust fund investments have been established to satisfy APS’ nuclear decommissioning obligations.

37

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables

The following table presents the fair value at September 30, 2010 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):

	Quoted Prices			Significant
	in Active			Other			Significant
	Markets for			Observable			Unobservable			Counterparty			Balance at
	Identical Assets			Inputs			Inputs (a)			Netting &			September 30,
	(Level 1)			(Level 2)			(Level 3)			Other (b)			2010
Assets
Cash equivalents	$	122		$	—		$	—		$	—		$	122
Risk management activities:
Commodity contracts		—			98			76			(51	)		123
Nuclear decommissioning trust:
Equity securities:
U.S. commingled funds		—			151			—			—			151
Fixed income securities:
U.S. Treasury		67			—			—			—			67
Corporate		—			63			—			—			63
Mortgage-backed		—			61			—			—			61
Municipality		—			71			—			—			71
Other		—			54			—			(13	)		41
Total	$	189		$	498		$	76		$	(64	)	$	699
Liabilities
Risk management activities:
Commodity contracts	$	(2	)	$	(338	)	$	(125	)	$	328		$	(137	)

(a)	Primarily consists of long-dated electricity contracts.
(b)	Primarily represents netting under master netting arrangements, including margin and collateral. See Note 8.

38

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

(a)	Primarily consists of long-dated electricity contracts.
(b)	Primarily represents netting under master netting arrangements, including margin and collateral. See Note 8.

39

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, 2010 and 2009 (dollars in millions):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Commodity Contracts	2010			2009			2010			2009
Net derivative balance at beginning of period	$	(42	)	$	(16	)	$	(10	)	$	(7	)
Total net gains (losses) realized/unrealized:
Included in earnings		1			1			(1	)		3
Included in OCI		(11	)		(2	)		(20	)		(3	)
Deferred as a regulatory asset or liability		(15	)		6			(39	)		12
Settlements		12			(4	)		15			(1	)
Transfers into Level 3 from Level 2		(2	)		(2	)		6			(23	)
Transfers from Level 3 into Level 2		8			4			—			6
Net derivative balance at end of period	$	(49	)	$	(13	)	$	(49	)	$	(13	)
Net unrealized gains (losses) included in earnings related to instruments still held at end of period	$	1		$	1		$	—		$	3

Amounts included in earnings are recorded in either regulated electricity segment revenue or regulated electricity segment fuel and purchased power depending on the nature of the underlying contract.

Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.

Nonrecurring Fair Value Measurements

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

We apply nonrecurring fair value measurements to certain real estate assets. These adjustments to fair value are the result of write-downs of individual assets due to impairment. Our real estate assets have been impaired due to the distressed real estate market. The majority of our real estate assets reflect the expected sales price less cost to sell at September 30, 2010. Due to these unobservable inputs, the valuation of real estate assets are considered Level 3 measurements.

Financial Instruments Not Carried at Fair Value

The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our long-term debt fair value estimates are based on quoted market prices of the same or similar issues. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.

40

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	As of				As of
	September 30, 2010				December 31, 2009
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Pinnacle West	$	175	$	178	$	175	$	180
APS		3,521		3,919		3,530		3,667
SunCor (a)		6		6		95		95
Total	$	3,702	$	4,103	$	3,800	$	3,942

(a) See Note 2 for further discussion related to SunCor’s debt and liquidity matters.

Nuclear Decommissioning Trust

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust funds are invested in a tax efficient manner in fixed income securities and domestic equity securities. APS classifies investments in decommissioning trust funds as available for sale, and therefore, 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, 2010 and December 31, 2009 (dollars in millions):

				Total		Total
				Unrealized		Unrealized
	Fair Value			Gains		Losses
September 30, 2010
Equity securities	$	151		$	31	$	(4	)
Fixed income securities		316			20		—
Net payables (a)		(13	)		—		—
Total	$	454		$	51	$	(4	)

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

41

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate realized 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,
	2010		2009			2010			2009
Realized gains	$	1	$	3		$	15		$	8
Realized losses		—		(1	)		(3	)		(6	)
Proceeds from the sale of securities (a)		94		126			424			370

(a) Proceeds are reinvested in the trust.

The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2010 is as follows (dollars in millions):

	Fair Value
Less than one year	$	26
1 year - 5 years		74
5 years - 10 years		93
Greater than 10 years		123
Total	$	316

42

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

16. Real Estate Impairment Charge

In 2009, SunCor undertook and completed a review of its assets and strategies within its various markets as a result of the distressed conditions in real estate and credit markets. Based on the results of the review, on March 27, 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce SunCor’s outstanding debt. In July 2010, SunCor sold land parcels, commercial assets and a master planned home-building community for approximately $70 million, which approximated the carrying value of these assets, resulting in a net gain of zero. It is expected that SunCor will dispose of its other assets within the next 12 months. As a result, they are classified as assets held for sale on the balance sheet at September 30, 2010 and all of SunCor’s operations are reflected in discontinued operations. The detail of the impairment charges are as follows (dollars in millions, and before income taxes):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Discontinued Operations:
Homebuilding and master-planned communities	$	—	$	10	$	1	$	160
Land parcels and commercial assets		—		27		11		81
Golf courses		—		1		1		19
Other		—		—		4		—
Subtotal		—		38		17		260
Less noncontrolling interests		—		—		—		(14	)
Total	$	—	$	38	$	17	$	246

See Note 2 for a discussion of SunCor’s debt and liquidity matters.

43

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

(dollars in thousands)

	Three Months Ended
	September 30,
	2010			2009
ELECTRIC OPERATING REVENUES	$	1,116,220		$	1,083,825
OPERATING EXPENSES
Fuel and purchased power		353,904			381,543
Operations and maintenance		217,044			193,530
Depreciation and amortization		104,152			102,954
Income taxes		126,841			118,923
Taxes other than income taxes		37,270			33,782
Total		839,211			830,732
OPERATING INCOME		277,009			253,093
OTHER INCOME (DEDUCTIONS)
Income taxes		1,272			1,070
Allowance for equity funds used during construction		5,524			2,197
Other income (Note S-2)		2,962			3,530
Other expense (Note S-2)		(4,074	)		(2,790	)
Total		5,684			4,007
INTEREST EXPENSE
Interest on long-term debt		53,946			54,252
Interest on short-term borrowings		2,013			1,058
Debt discount, premium and expense		1,121			1,115
Allowance for borrowed funds used during construction		(6,163	)		(1,343	)
Total		50,917			55,082
NET INCOME		231,776			202,018
Less: Net income attributable to noncontrolling interests (Note 7)		5,128			4,953
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	226,648		$	197,065

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

44

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

	Nine Months Ended
	September 30,
	2010			2009
ELECTRIC OPERATING REVENUES	$	2,527,163			$	2,499,072
OPERATING EXPENSES
Fuel and purchased power		821,244				920,630
Operations and maintenance		632,235				595,929
Depreciation and amortization		307,731				303,814
Income taxes		177,089				158,041
Taxes other than income taxes		100,171				100,077
Total		2,038,470				2,078,491
OPERATING INCOME		488,693				420,581
OTHER INCOME (DEDUCTIONS)
Income taxes		3,769				3,684
Allowance for equity funds used during construction		16,417				11,919
Other income (Note S-2)		3,872				7,580
Other expense (Note S-2)		(11,091	)			(10,798	)
Total		12,967				12,385
INTEREST EXPENSE
Interest on long-term debt		161,918				157,980
Interest on short-term borrowings		5,734				5,326
Debt discount, premium and expense		3,376				3,560
Allowance for borrowed funds used during construction		(12,254	)			(8,284	)
Total		158,774				158,582
NET INCOME		342,886				274,384
Less: Net income attributable to noncontrolling interests (Note 7)		15,034				14,254
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	327,852			$	260,130

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

45

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

	September 30,			December 31,
	2010			2009
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use	$	12,982,572		$	12,781,256
Accumulated depreciation and amortization		(4,456,017	)		(4,326,908	)
Net		8,526,555			8,454,348
Construction work in progress		555,137			460,748
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)		140,145			146,722
Intangible assets, net of accumulated amortization		178,479			164,183
Nuclear fuel, net of accumulated amortization		124,101			118,243
Total property, plant and equipment		9,524,417			9,344,244
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)		453,963			414,576
Assets from risk management activities (Note 8)		54,968			28,855
Other assets		70,383			68,839
Total investments and other assets		579,314			512,270
CURRENT ASSETS
Cash and cash equivalents		162,272			120,798
Customer and other receivables		359,053			280,226
Accrued unbilled revenues		180,006			110,971
Allowance for doubtful accounts		(7,660	)		(6,063	)
Materials and supplies (at average cost)		174,428			176,020
Fossil fuel (at average cost)		21,826			39,245
Assets from risk management activities (Note 8)		68,476			50,619
Deferred income taxes		81,719			53,990
Other current assets		42,901			25,724
Total current assets		1,083,021			851,530
DEFERRED DEBITS
Regulatory assets		879,056			813,161
Income tax receivable (Note 6)		65,498			65,498
Unamortized debt issue costs		19,719			20,959
Other		77,448			73,909
Total deferred debits		1,041,721			973,527
TOTAL ASSETS	$	12,228,473		$	11,681,571

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

46

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

	September 30,			December 31,
	2010			2009
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital		2,379,696			2,126,863
Retained earnings		1,421,679			1,250,126
Accumulated other comprehensive loss:
Pension and other postretirement benefits		(31,149	)		(29,114	)
Derivative instruments		(120,614	)		(80,682	)
Total shareholder equity		3,827,774			3,445,355
Noncontrolling interests (Note 7)		94,073			82,324
Total equity		3,921,847			3,527,679
Long-term debt less current maturities (Note 2)		3,349,924			3,180,406
Palo Verde sale leaseback lessor notes (Notes 2 and 7)		113,379			126,000
Total capitalization		7,385,150			6,834,085
CURRENT LIABILITIES
Current maturities of long-term debt (Note 2)		57,275			222,959
Accounts payable		227,224			213,833
Accrued taxes		174,192			158,051
Accrued interest		52,112			54,099
Customer deposits		68,206			70,780
Liabilities from risk management activities (Note 8)		55,847			55,908
Other current liabilities		135,931			124,995
Total current liabilities		770,787			900,625
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,840,300			1,582,945
Deferred fuel and purchased power regulatory liability (Note 3)		41,385			87,291
Other regulatory liabilities		685,908			679,072
Liability for asset retirements		323,134			301,783
Liabilities for pension and other postretirement benefits (Note 4)		697,686			766,378
Liabilities from risk management activities (Note 8)		80,656			62,443
Customer advances		127,449			136,595
Coal mine reclamation		117,029			92,060
Unrecognized tax benefits (Note 6)		65,863			140,638
Other		93,126			97,656
Total deferred credits and other		4,072,536			3,946,861
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	12,228,473		$	11,681,571

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

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

	Nine Months Ended
	September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	342,886		$	274,384
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		349,267			334,092
Deferred fuel and purchased power		50,020			(46,743	)
Deferred fuel and purchased power amortization		(95,926	)		115,214
Allowance for equity funds used during construction		(16,417	)		(11,919	)
Deferred income taxes		218,575			252,282
Change in mark-to-market valuations		3,716			(5,970	)
Changes in current assets and liabilities:
Customer and other receivables		(93,394	)		(92,535	)
Accrued unbilled revenues		(69,035	)		(56,420	)
Materials, supplies and fossil fuel		19,011			(16,781	)
Other current assets		(17,177	)		(2,473	)
Accounts payable		37,150			(28,018	)
Accrued taxes		16,141			(149,990	)
Other current liabilities		6,375			(740	)
Change in margin and collateral accounts — assets		(4,336	)		1,251
Change in margin and collateral accounts — liabilities		(143,725	)		3,564
Change in regulatory liabilities		40,121			92,598
Change in unrecognized tax benefits		(72,217	)		92,973
Change in other long-term assets		(53,566	)		(54,781	)
Change in other long-term liabilities		(11,686	)		13,473
Net cash flow provided by operating activities		505,783			713,461
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(552,331	)		(551,042	)
Contributions in aid of construction		25,258			17,393
Allowance for borrowed funds used during construction		(12,254	)		(8,284	)
Proceeds from nuclear decommissioning trust sales		424,255			370,399
Investment in nuclear decommissioning trust		(442,567	)		(386,743	)
Other		9,621			(1,404	)
Net cash flow used for investing activities		(548,018	)		(559,681	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		—			863,903
Repayment of long-term debt		(9,538	)		(350,312	)
Short-term borrowings and payments-net		—			(521,684	)
Equity infusion		252,833			—
Dividends paid on common stock		(156,300	)		(127,500	)
Noncontrolling interests		(3,286	)		(3,393	)
Net cash flow provided by (used for) financing activities		83,709			(138,986	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		41,474			14,794
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		120,798			71,544
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	162,272		$	86,338
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)	$	76,364		$	13,555
Interest, net of amounts capitalized	$	157,385		$	146,062

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

48

Certain notes to APS’ Condensed Consolidated Financial Statements are combined with the Notes to Pinnacle West’s Condensed Consolidated Financial Statements. Listed below are the Condensed Consolidated Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS’ Condensed Consolidated Financial Statements. In addition, listed below are the Supplemental Notes that are required disclosures for APS and should be read in conjunction with Pinnacle West’s Condensed Consolidated Notes.

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

49

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-1. Changes in Equity

The following tables show APS’ changes in shareholder equity and changes in equity of noncontrolling interests for the three and nine months ended September 30, 2010 and 2009 (dollars in thousands):

	Three Months Ended September 30, 2010								Three Months Ended September 30, 2009
	Shareholder			Noncontrolling					Shareholder			Noncontrolling
	Equity			Interests		Total			Equity			Interests			Total
Beginning balance, July 1	$	3,605,292		$	88,944	$	3,694,236		$	3,284,568		$	83,509		$	3,368,077
Net income		226,648			5,128		231,776			197,065			4,953			202,018
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		(67,856	)		—		(67,856	)		4,959			—			4,959
Net reclassification of realized losses to income (b)		59,801			—		59,801			81,660			—			81,660
Reclassification of pension and other postretirement benefits to income		1,172			—		1,172			999			—			999
Net income tax benefit (expense) related to items of other comprehensive income (loss)		2,717			—		2,717			(34,644	)		—			(34,644	)
Total other comprehensive income (loss)		(4,166	)		—		(4,166	)		52,974			—			52,974
Total comprehensive income		222,482			5,128		227,610			250,039			4,953			254,992
Dividends on common stock		—			—		—			(42,500	)		—			(42,500	)
Equity infusion		—			—		—			4,571			—			4,571
Other		—			1		1			—			(8	)		(8	)
Ending balance, September 30	$	3,827,774		$	94,073	$	3,921,847		$	3,496,678		$	88,454		$	3,585,132

(a)	These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.
(b)	These amounts primarily include the reclassification of unrealized gains and losses to realized gains and losses for contracted commodities delivered during the period.

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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2009
	Shareholder			Noncontrolling						Shareholder			Noncontrolling
	Equity			Interests			Total			Equity			Interests			Total
Beginning balance, January 1	$	3,445,355		$	82,324		$	3,527,679		$	3,339,150		$	77,601		$	3,416,751
Net income		327,852			15,034			342,886			260,130			14,254			274,384
Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)		(168,110	)		—			(168,110	)		(128,035	)		—			(128,035	)
Net reclassification of realized losses to income (b)		102,130			—			102,130			154,990			—			154,990
Reclassification of pension and other postretirement benefits to income		3,499			—			3,499			2,991			—			2,991
Net unrealized losses related to pension benefits		(6,863	)		—			(6,863	)		(3,774	)		—			(3,774	)
Net income tax benefit (expense) related to items of other comprehensive income (loss)		27,377			—			27,377			(10,348	)		—			(10,348	)
Total other comprehensive income (loss)		(41,967	)		—			(41,967	)		15,824			—			15,824
Total comprehensive income		285,885			15,034			300,919			275,954			14,254			290,208
Dividends on common stock		(156,300	)		—			(156,300	)		(127,500	)		—			(127,500	)
Equity infusion		252,833			—			252,833			9,074			—			9,074
Other		1			(3,285	)		(3,284	)		—			(3,401	)		(3,401	)
Ending balance, September 30	$	3,827,774		$	94,073		$	3,921,847		$	3,496,678		$	88,454		$	3,585,132

(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.

51

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

S-2. Other Income and Other Expense

The following table provides detail of APS’ other income and other expense for the three and nine months ended September 30, 2010 and 2009 (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Other income:
Interest income	$	373		$	63		$	2,653		$	402
Investment gains — net		2,574			3,320			1,038			5,189
Miscellaneous		15			147			181			1,989
Total other income	$	2,962		$	3,530		$	3,872		$	7,580
Other expense:
Non-operating costs (a)	$	(2,969	)	$	(1,714	)	$	(6,453	)	$	(6,225	)
Asset dispositions		(186	)		(182	)		(395	)		(540	)
Miscellaneous		(919	)		(894	)		(4,243	)		(4,033	)
Total other expense	$	(4,074	)	$	(2,790	)	$	(11,091	)	$	(10,798	)

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

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

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and Arizona Public Service Company’s Condensed Consolidated Financial Statements and the related Notes that appear in Item 1 of this report. For purposes of this report, a “Note” refers to a Note to Pinnacle West’s Condensed Consolidated Financial Statements in Item 1 of this report. For information on the broad factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A of the 2009 Form 10-K.

OVERVIEW

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

Areas of Business Focus

Nuclear.APS operates and is a joint-owner of the Palo Verde Nuclear Generating Station. With a focus on safely and efficiently generating electricity for the long-term, APS applied for twenty-year renewals of its operating licenses for each of the three Palo Verde units, and is making preparations to secure necessary resources to operate the plant during this extended period of time.

Coal and Related Environmental Matters.APS is a joint-owner of three coal-fired power plants and acts as operating agent for two of the plants. APS is focused on the impacts on its coal fleet that may result from potential legislation and increased regulation concerning greenhouse gas emissions. Recent concern over climate change and other emission-related issues could have a significant impact on APS’ capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades for these plants. APS is closely monitoring its long range capital management plans, understanding that the resulting legislation and regulation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to fund any such equipment upgrades. In particular, on October 6, 2010, the EPA issued its proposed determination for “Best Available Retrofit Technology” (BART) requirements for the Four Corners Power Plant (“Four Corners”) that, as proposed, would require installation of additional pollution control equipment on all five of the plant’s units. APS estimates that its total costs for the proposed controls could be up to approximately $422 million for nitrogen oxide controls and about $220 million for particulate removal equipment. It is currently evaluating the impacts of the proposed determination and intends to submit comments during the EPA's comment period. (See "Environmental Matters – Regional Haze Rules" in Part II, Item 5.) In addition, Southern California Edison, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the plant.

Transmission and Delivery.APS’ 2010 transmission plan projects that it will invest approximately $520 million in new transmission over the next ten years, which includes 270 miles of new lines. APS is working closely with regulators to identify and plan for transmission needs resulting from the current focus on renewable energy. APS is also working to establish and expand smart grid technology throughout its service territory designed to provide a variety of benefits both to APS and its customers. This technology is designed to allow customers to better monitor their energy use and needs, minimize system outage durations and the number of customers that experience outages, and facilitate cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

53

Renewable Energy.APS is committed to increasing the amount of energy produced by renewable energy resources. The ACC approved the RES in 2006, recognizing the importance of renewable energy to our state. In the Settlement Agreement for the 2008 general retail rate case, APS agreed to exceed the RES standards, committing that approximately 10% of APS’ energy will come from renewable resources by the year 2015. A component of the original RES is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties). As of September 30, 2010, customers have installed 41 MW of distributed energy system through APS’ renewable incentive programs. A variety of other provisions in the Settlement Agreement reinforce APS’ dedication to renewable energy through initiatives such as building photovoltaic solar plants, seeking an Arizona wind generation project and installing solar rooftop panels on schools and government buildings.

To procure the additional renewable resources required under our Settlement Agreement, APS issued three requests for proposals (“RFPs”) for renewable resources in the first half of 2010. The first RFP was for wind projects between 15 and 100 MW to be located within Arizona. The second RFP was for utility-scale solar photovoltaic (“PV”) projects between 15 and 50 MW. The third RFP, the 2010 Small Generation RFP, serves as the first in a series of solicitations that will focus on a broad base of renewable technologies for projects between 2 and 15 MW. Resulting from these and prior solicitations, as of September 30, 2010, APS has entered into two long-term power purchase contracts, the first for a 15 MW solar PV project located in Bagdad, Arizona and the second for a 99 MW wind project located north of Williams, Arizona, known as Perrin Ranch Wind. Each of these agreements is subject to various conditions, including successful siting, permitting and interconnection of the project to the electric grid.

On March 3, 2010, the ACC approved the AZ Sun Program, under which APS plans to own 100 MW of solar PV power plants across Arizona by investing up to $500 million through 2014. See Note 3 for additional details of this program, including the related cost recovery. APS expects to acquire these resources through competitive procurement processes, with projects being placed into service in the 2011 to 2014 timeframe. The ultimate timing of these projects will depend on the outcome of current and future procurement processes. APS plans to invest approximately $150 million to develop the following two projects announced to date:

		Expected
		Commercial
AZ Sun Program Contracts:	Capacity	Operation Date	Type
Glendale, AZ	15 MW	Summer 2011	Solar PV
Gila Bend, AZ	18 MW	Late 2011	Solar PV
Amount Remaining Under AZ Sun Program	67 MW
TOTAL AZ Sun Program	100 MW

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Energy Efficiency.Arizona regulators are placing an increased focus on energy efficiency and demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. In December 2009, the ACC initiated Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. On July 27, 2010, the proposed Energy Efficiency Standard was approved by the ACC subject to review and approval by the Arizona Attorney General, which should be completed before the end of 2010. An ambitious standard, such as that approved by the ACC, will increase participation by APS customers in these conservation and energy efficiency programs, which in turn will impact Arizona’s future energy resource needs.

Rate Matters.APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. At the end of 2009, the ACC approved a settlement agreement entered into by APS and twenty-one of the twenty-three other parties to APS’ general retail rate case, with modifications that did not materially affect the overall economic terms of the agreement. The rate case settlement should strengthen APS’ financial condition by allowing for rate stability and a greater level of cost recovery and return on investment. It also authorizes and requires equity infusions into APS of at least $700 million prior to the end of 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010 (see Note 2)). The settlement demonstrates cooperation among APS, the ACC staff, the Residential Utility Consumer Office and other intervenors to the rate case, and sets forth a future rate case filing plan that allows APS the opportunity to help shape Arizona’s energy future outside of continual rate cases. See Note 3 for a discussion of the Settlement Agreement terms and information on APS’ FERC rates.

APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its energy efficiency, demand-side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 3.

On October 18, 2010, the Chairman of the ACC issued a draft decoupling policy statement. Decoupling refers to a ratemaking design which reduces or removes the linkage between sales and utility revenues and/or profits, reducing utility disincentives to the adoption of programs that benefit customers by saving energy. Mechanically, decoupling compares actual versus authorized revenues or revenue per customer over a period and either credits or collects any differences from customers in a subsequent period. The draft policy is supportive of decoupling using a revenue-per-customer methodology, which is the mechanism APS and a number of other parties support because it recognizes increased costs associated with additional customers. The draft policy would allow a utility to file a decoupling plan in its next general rate case. Subsequent steps by the ACC prior to approving any policy statement will likely depend on the nature and extent of the comments received from various stakeholders.

Financial Strength and Flexibility.Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities and have been able to access these facilities as well as the commercial paper market, ensuring adequate liquidity for each company. In early February 2010, APS entered into a $500 million revolving credit facility, replacing its $377 million facility that would have otherwise terminated in December 2010. At that same time, Pinnacle West entered into a $200 million revolving credit facility that replaced its $283 million facility that also would have otherwise terminated in December 2010. Since March 2010, Pinnacle West and APS have accessed the commercial paper markets, which neither company had utilized since the third quarter of 2008 due to negative market conditions.

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

55

Since the beginning of the third quarter, APS changed the interest rate modes on approximately $180 million of its pollution control bonds from daily rate modes to term rate modes. The letters of credit supporting each of these series of bonds were terminated in conjunction with the rate changes. See Note 2 for additional details of these changes.

SunCor Real Estate Operations.As a result of the distressed conditions in the real estate markets, during 2009 SunCor undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce its outstanding debt. In July 2010, SunCor sold land parcels, commercial assets and a master planned home-building community for approximately $70 million, which approximated the carrying value of these assets, resulting in a net gain of zero. In connection with this sale, SunCor negotiated a restructuring of certain of its credit facilities, including its principal loan facility. The debt restructuring resulted in an after-tax gain of approximately $9 million, which was recognized in the third quarter of 2010. At September 30, 2010, SunCor had approximately $22 million of assets on its balance sheet classified as assets held for sale. These assets consisted of $18 million of consolidated VIEs (see Note 7), master planned home-building communities and golf courses. Because it is expected that SunCor will dispose of these assets within the next 12 months, they are classified as assets held for sale on the balance sheet. See “Pinnacle West Consolidated — Liquidity and Capital Resources — Other Subsidiaries — SunCor” below for a discussion of SunCor’s outstanding debt and related matters and Note 16 for a discussion of related impairment charges.

Other Subsidiary Matters.The operations of APSES and our other first tier subsidiary, El Dorado, are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.

Key Financial Drivers

In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.

Regulated Electricity Segment Revenues.For the years 2007 through 2009, retail electric revenues comprised approximately 94% of our total electric operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. Off-system sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth.Customer growth in APS’ service territory for the nine-month period ended September 30, 2010 was 0.6% compared with the prior year period. For the three years 2007 through 2009, APS’ customer growth averaged 1.8% per year. We currently expect annual customer growth to average about 1% for 2010 through 2012 due to economic conditions both nationally and in Arizona. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for the nine-month period ended September 30, 2010 declined 1.0% compared to the same period in the prior year, reflecting the poor economic conditions and the effects of our energy efficiency programs. For the three years 2007 through 2009, APS’ actual retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, grew at an average annual rate of 0.2%. We currently estimate that total annual retail electricity sales in kilowatt-hours will remain flat on average during 2010 through 2012, including the effects of APS’ energy efficiency programs, but excluding the effects of weather variations. A continuation of the economic downturn, or the failure of the Arizona economy to rebound in the near future, could further impact these estimates. The customer and sales growth referred to in this paragraph apply to Native Load customers.

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Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth or decline, usage patterns, impacts of energy efficiency programs and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.

Weather.In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

Fuel and Purchased Power Costs.Fuel and purchased power costs included on our Condensed Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses.Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs, renewable energy and demand side management related expenses (which are offset by the same amount of regulated electricity segment operating revenues) and other factors. In its retail rate case settlement, APS committed to operational expense reductions from 2010 through 2014 and received approval to defer certain pension and other postretirement benefit cost increases to be incurred in 2011 and 2012.

Depreciation and Amortization Expenses.Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. The “Capital Expenditures” section below provides information regarding the planned additions to our facilities. We have also applied to the NRC for renewed operating licenses for each of the Palo Verde units. If the NRC grants the extension, we estimate that our annual pretax depreciation expense will decrease by approximately $34 million at the later of the license extension date or January 1, 2012.

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

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Income Taxes.Income taxes are affected by the amount of pre-tax book income, income tax rates, and certain non-taxable items, such as the allowance for equity funds used during construction. In addition, income taxes may also be affected by the settlement of issues with taxing authorities.

Interest Expense.Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 2). The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. An allowance for borrowed funds offsets a portion of interest expense while capital projects are under construction. We stop accruing the allowance for borrowed funds on a project when it is placed in commercial operation.

PINNACLE WEST CONSOLIDATED — RESULTS OF OPERATIONS

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

• our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to 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. All of SunCor’s operations are reflected in discontinued operations (see Notes 5 and 14). The real estate segment activities are presented separately in the period-over-period discussions that follow.

Operating Results — Three-month period ended September 30, 2010 compared with three-month period ended September 30, 2009

Our consolidated net income attributable to common shareholders for the three months ended September 30, 2010 was $234 million, compared with net income of $187 million for the comparable prior-year period. The $47 million variance consists of a $29 million increase in income from continuing operations and an $18 million increase from discontinued operations (primarily real estate segment). As discussed in greater detail below, the improved results reflect an increase of approximately $25 million in regulated electricity segment net income primarily due to increased revenues related to APS’ retail rate increases, partially offset by increased operations and maintenance expenses.

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

	Three Months Ended
	September 30,
	2010			2009			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	762		$	702		$	60
Operations and maintenance		(220	)		(195	)		(25	)
Depreciation and amortization		(104	)		(103	)		(1	)
Taxes other than income taxes		(38	)		(34	)		(4	)
Other income (expenses), net		—			2			(2	)
Interest charges, net of allowance for funds used during construction		(48	)		(56	)		8
Income taxes		(122	)		(111	)		(11	)
Noncontrolling interests (Note 7)		(5	)		(5	)		—
Regulated electricity segment net income		225			200			25
All other (a)		2			(2	)		4
Income from Continuing Operations Attributable to Common Shareholders		227			198			29
Real Estate Segment:
Real estate impairment charges (Note 16)		—			(38	)		38
Other real estate operations		13			18			(5	)
Income taxes		(5	)		8			(13	)
Real estate segment net income (loss)		8			(12	)		20
All other (a)		(1	)		1			(2	)
Income (Loss) from Discontinued Operations Attributable to Common Shareholders		7			(11	)		18
Net Income Attributable to Common Shareholders	$	234		$	187		$	47

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

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Regulated electricity segment

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

Operating revenues less fuel and purchased power expensesRegulated electricity segment operating revenues less fuel and purchased power expenses were $60 million higher for the three months ended September 30, 2010 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Fuel and
				purchased
	Operating			power
	revenues			expenses			Net change
	(dollars in millions)
Retail regulatory settlement effective January 1, 2010:
Retail base rate increases, net of deferrals	$	98		$	43		$	55
Line extension revenues (Note 3)		6						6
Transmission rate decreases		(1	)					(1	)
Higher demand-side management and renewable energy surcharges (substantially offset in operations and maintenance expense)		11						11
Effects of weather on retail sales		6			2			4
Lower retail revenues related to recovery of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense		(90	)		(92	)		2
Higher fuel and purchased power costs including the effects of higher off-system sales, net of related PSA deferrals		22			24			(2	)
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		(15	)		(5	)		(10	)
Miscellaneous items, net		(4	)		1			(5	)
Total	$	33		$	(27	)	$	60

Operations and maintenanceOperations and maintenance expenses increased $25 million for the three months ended September 30, 2010 compared with the prior-year period primarily because of:

• An increase of $8 million related to demand-side management and renewable energy programs, which are primarily offset in operating revenues;

• An increase of $6 million related to employee benefits costs; and

• An increase of $4 million in generation costs, including the acceleration of fossil-plant planned maintenance.

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Interest charges, net of allowance for funds used during constructionInterest charges, net of allowance for funds used during construction, decreased $8 million for the three months ended September 30, 2010 compared with the prior-year period primarily because of higher rates in the current year for the allowance for equity and borrowed funds used during construction.

Income taxesIncome taxes were $11 million higher for the three months ended September 30, 2010 compared with the prior-year period primarily because of higher pretax income in the current-year period.

Real estate segment

As of September 30, 2010, all of SunCor’s operations have been reclassified to discontinued operations. The real estate segment net income attributable to common shareholders was $20 million higher for the three months ended September 30, 2010 compared with the prior-year period primarily because of:

• A decrease in real estate impairment charges of $38 million;

• A decrease in income from other real estate operations of $5 million primarily due to a gain from debt restructuring of approximately $14 million recorded in the current-year period (see Note 2) compared with income from parcel sales in the prior-year period; and

• An increase in income taxes of $13 million primarily because of higher pretax income in the current-year period.

Operating Results — Nine-month period ended September 30, 2010 compared with nine-month period ended September 30, 2009

Our consolidated net income attributable to common shareholders for the nine months ended September 30, 2010 was $343 million, compared with $98 million for the comparable prior-year period. The improved results were primarily due to lower real estate impairment charges recorded in 2010 compared with the prior-year period by SunCor.

In addition, regulated electricity segment net income increased approximately $63 million from the prior-year period due to increased revenues related to APS’ retail rate increases and other factors, partially offset by milder weather in the second quarter of 2010. Our consolidated results for 2010 also include a gain of $25 million after income taxes related to the sale of APSES’ district cooling business.

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

	Nine Months Ended
	September 30,
	2010			2009			Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	1,706		$	1,578		$	128
Operations and maintenance		(639	)		(603	)		(36	)
Depreciation and amortization		(308	)		(304	)		(4	)
Taxes other than income taxes		(101	)		(101	)		—
Other income (expenses), net		(5	)		1			(6	)
Interest charges, net of allowance for funds used during construction		(152	)		(156	)		4
Income taxes		(166	)		(143	)		(23	)
Noncontrolling interests (Note 7)		(15	)		(15	)		—
Regulated electricity segment net income		320			257			63
All other (a)		3			(8	)		11
Income from Continuing Operations Attributable to Common Shareholders		323			249			74
Real Estate Segment:
Real estate impairment charges (Note 16)		(17	)		(246	)		229
Other real estate operations		7			(6	)		13
Income taxes		4			99			(95	)
Real estate segment net loss		(6	)		(153	)		147
All other (a)		26			2			24
Income (Loss) from Discontinued Operations Attributable to Common Shareholders		20			(151	)		171
Net Income Attributable to Common Shareholders	$	343		$	98		$	245

(a) Includes activities related to APSES and El Dorado. None of the activities of either of these companies constitutes a reportable segment. Income from discontinued operations for the period ended September 30, 2010 includes a gain of $25 million after income taxes related to the sale of APSES’ district cooling business.

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Regulated electricity segment

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

Operating revenues less fuel and purchased power expensesRegulated electricity segment operating revenues less fuel and purchased power expenses were $128 million higher for the nine months ended September 30, 2010 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
					Fuel and
					purchased
	Operating				power
	revenues			��	expenses			Net change
	(dollars in millions)
Retail regulatory settlement effective January 1, 2010:
Retail base rate increases, net of deferrals	$	217			$	100		$	117
Line extension revenues (Note 3)		14							14
Transmission rate increases		8							8
Higher demand-side management and renewable energy surcharges (substantially offset in operations and maintenance expense)		26							26
Lower retail revenues related to recovery of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense		(211	)			(216	)		5
Higher fuel and purchased power costs including the effects of higher off-system sales, net of related PSA deferrals		24				29			(5	)
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		(16	)			(7	)		(9	)
Effects of weather on retail sales, primarily due to milder weather in the second quarter 2010		(27	)			(8	)		(19	)
Miscellaneous items, net		(7	)			2			(9	)
Total	$	28			$	(100	)	$	128

Operations and maintenanceOperations and maintenance expenses increased $36 million for the nine months ended September 30, 2010 compared with the prior-year period primarily because of:

• An increase of $20 million related to demand-side management and renewable energy programs, which are primarily offset in operating revenues;

• An increase of $7 million related to employee benefits costs; and

• An increase of $5 million related to customer service and other costs.

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Income taxesIncome taxes were $23 million higher for the nine months ended September 30, 2010 compared with the prior-year period primarily because of higher pretax income in the current-year period, partially offset by $11 million related to a reduction in the Company’s 2010 effective income tax rate. See Note 6.

All other

All other earnings from continuing operations were $11 million higher for the nine months ended September 30, 2010 compared to the prior-year period primarily because of improved margins from APSES’ products and services business and investment losses at El Dorado in 2009.

Real estate segment

During the first quarter of 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s assets. This decision resulted in impairment charges of approximately $246 million pretax in the first nine months of 2009. As of September 30, 2010, all of SunCor’s operations have been reclassified to discontinued operations (see Note 14). The real estate segment net loss attributable to common shareholders was $147 million lower for the nine months ended September 30, 2010 compared with the prior-year period primarily because of:

• A decrease in real estate impairment charges of $229 million;

• An increase in income from other real estate operations of $13 million primarily due to a gain from debt restructuring of approximately $14 million recorded in the current-year period (see Note 2); and

• A decrease in income tax benefits of $95 million primarily because of a lower net loss for the 2010 period.

All other

All other earnings from discontinued operations were $24 million higher for the nine months ended September 30, 2010 compared to the prior-year period primarily because of a gain of $25 million after income taxes related to the sale of APSES’ district cooling business in 2010.

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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, 2010 and 2009 (dollars in millions):

	Nine Months Ended
	September 30,
	2010			2009
Net cash flow provided by operating activities	$	570		$	771
Net cash flow used for investing activities		(377	)		(537	)
Net cash flow used for financing activities		(142	)		(239	)

The decrease of approximately $201 million in net cash provided by operating activities is primarily due to changes in collateral and margin cash provided as a result of changes in commodity prices and a voluntary pension contribution in 2010 of approximately $100 million; partially offset by other changes in working capital.

The decrease of approximately $160 million in net cash used for investing activities is primarily due to approximately $100 million of proceeds from the sale of the district cooling business in June 2010 and the proceeds from the sale of commercial real estate investments in 2010 of approximately $70 million.

The decrease of approximately $97 million in net cash used for financing activities is primarily due to lower levels of repayment of short-term borrowings in 2010 offset by lower net sources of equity and long-term debt financing including the proceeds of approximately $253 million from the issuance of equity in April 2010 and APS’ issuance of $500 million of unsecured senior notes in 2009.

Liquidity

Capital Expenditure Requirements

The following table summarizes the actual capital expenditures for the nine months ended September 30, 2009 and 2010 and the estimated capital expenditures for the next three years:

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CAPITAL EXPENDITURES
(dollars in millions)

	Nine Months Ended				Estimated for the Year Ended
	September 30,				December 31,
	2009		2010		2010 (a)		2011		2012
APS
Generation:
Nuclear Fuel	$	64	$	63	$	63	$	68	$	65
Renewables		—		1		14		225		184
Environmental		30		2		20		80		220
Other Generation		88		126		167		147		134
Distribution		172		183		271		333		328
Transmission		159		83		134		160		192
Other (b)		30		43		55		60		49
Total APS		543		501		724		1,073		1,172
Other		8		4		4		—		—
Total	$	551	$	505	$	728	$	1,073	$	1,172

(a)	Estimated 2010 capital expenditures are lower than the estimate in the 2009 Form 10-K, primarily due to the timing of renewable expenditures.
(b)	Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment. 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 — Regional Haze Rules” and “Environmental Matters — Coal Combustion Waste” in Part II, Item 5 below and “Environmental Matters — Mercury and Other Hazardous Air Pollutants” in Part II, Item 5 of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (“2^nd Quarter 10-Q”)).

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction, related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Pinnacle West (Parent Company)

Our primary cash needs are for dividends to our shareholders and principal and interest payments on our short-term and long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

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On October 20, 2010, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on December 1, 2010, to shareholders of record on November 1, 2010.

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At September 30, 2010, APS’ common equity ratio, as defined, was 53%. Its total common equity was approximately $3.8 billion, and total capitalization was approximately $7.2 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’ total capitalization remains the same.

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs. During the first quarter of 2010, Pinnacle West and APS refinanced existing credit facilities that would have otherwise matured in December 2010.

On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. The new facility matures in February 2013. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Pinnacle West will use the facility for general corporate purposes, commercial paper support and for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. As a result of the downsized credit facility, the Company also reduced the size of its commercial paper program to $200 million from $250 million.

At September 30, 2010, the $200 million credit facility was available to support the issuance of up to $200 million in commercial paper or for bank borrowings, including issuances of letters of credit up to $100 million. At September 30, 2010, Pinnacle West had no outstanding borrowings under its revolving credit facility, no commercial paper borrowings and no outstanding letters of credit.

In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the net proceeds from this offering into APS in the form of equity infusions. APS has used these contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes. Pinnacle West intends to issue equity to provide most of the funds for the equity infusions into APS required by the retail rate case settlement. Such equity issuances may occur at any time in the period through 2014, in Pinnacle West’s discretion. See Note 3.

In June 2010, Pinnacle West received approximately $100 million related to the sale of APSES’ district cooling business. The net proceeds were used to repay short-term indebtedness.

Pinnacle West expects to receive approximately $132 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 16), which will not be fully realized until all of the asset sales are completed. Approximately $7 million of these benefits were recorded in the nine months ended September 30, 2010 as reductions to income tax expense related to the current impairment charges. The additional $125 million of tax benefits were recorded as reductions to income tax expense related to SunCor impairment charges recorded on or before December 31, 2009.

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The $88 million income tax receivables on the Condensed Consolidated Balance Sheets represent the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009 and the current year tax benefits related to the SunCor strategic asset sales that closed in 2010.

Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made no contribution to our pension plan in 2009. We currently estimate that our annual pension contributions could average around $100 million for several years, assuming the discount rate remains at approximately current levels. During the first quarter of 2010, we made a voluntary contribution of approximately $100 million to our pension plan. The contribution to our other postretirement benefit plans in 2010 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 98% of both plans.

APS

APS’ capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, equity infusions from Pinnacle West and external financings. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.

On February 12, 2010, APS refinanced its $377 million credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. The new credit facility terminates in February 2013. APS has the option to increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility for general corporate purposes, commercial paper support and for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.

At September 30, 2010, APS had two credit facilities totaling $989 million, including the $500 million credit facility described above and a $489 million facility that terminates in September 2011. These facilities are available either to support the issuance of up to $250 million in commercial paper or for bank borrowings, including issuances of letters of credit up to $739 million. At September 30, 2010, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper. A $20 million letter of credit was issued under APS’ $489 million credit facility in the second quarter of 2010.

On July 13, 2010, APS changed the interest rate mode for the approximately $33 million of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Navajo Project) 1994 Series A, due 2029. The rate period for the bonds changed from a daily rate mode, supported by a letter of credit, to a three-year term rate mode that will bear interest at a rate of 3.625% per annum for three years. The letter of credit was terminated in connection with this change, and there is no bank or other third-party credit support for the bonds in the term rate mode.

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On August 10, 2010, APS changed the letter of credit supporting the approximately $17 million of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Project) Series 1998, due 2033. The bonds were in a daily rate mode supported by a letter of credit and remain in a daily rate mode, supported by a new three-year letter of credit expiring in August 2013.

On October 12, 2010, APS changed the interest rate mode for the approximately $147 million of City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project) 1994 Series A and 1994 Series B, due 2024 and City of Farmington, New Mexico Pollution Control Revenue Bonds (Arizona Public Service Company Four Corners Project) 1994 Series C, due 2024. The rate period for the 1994 Series A bonds and the 1994 Series B bonds changed from a daily rate mode, supported by letters of credit, to a term rate mode to maturity with an optional redemption after year ten that will bear interest at a rate of 4.70% per annum until maturity in 2024 unless the optional redemption is exercised by APS. The rate period for the 1994 Series C bonds changed from a daily rate mode, supported by a letter of credit, to a three-year term rate mode that will bear interest at a rate of 2.875% per annum until October 2013. The letters of credit supporting each of these three series of bonds were terminated in connection with these changes, and there is no bank or other third-party credit support for any of these bonds.

On January 1, 2010, due to the adoption of amended accounting guidance relating to VIEs, APS began consolidating the Palo Verde Lessor Trusts (see Note 7) and, as a result of consolidation of these VIEs, APS has reported the Lessor Trusts’ long-term debt on its Condensed Consolidated Balance Sheets. Interest rates on these debt instruments are 8% and are fixed for the remaining life of the debt. As of September 30, 2010 approximately $30 million was classified as current maturities of long-term debt and $113 million was classified as long-term debt relating to these VIEs. These debt instruments mature on December 30, 2015 and have sinking fund features that are serviced by the lease payments. See Note 7 for additional discussion of the VIEs.

Other Financing Matters —See Note 3 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.

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

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

Other Subsidiaries

SunCor— In July 2010, SunCor sold land parcels, commercial assets and a master planned home-building community for approximately $70 million, which approximated the carrying value of these assets, resulting in a net gain of zero. In connection with this sale, SunCor negotiated a restructuring of certain of its credit facilities, including its principal loan facility. The debt restructuring resulted in an after-tax gain of approximately $9 million, which was recognized in the third quarter of 2010.

At September 30, 2010, SunCor had approximately $22 million of assets on its balance sheet classified as assets held for sale. These assets consist of $18 million of consolidated VIEs (see Note 7), master planned home-building communities and golf courses. Because it is expected that SunCor will dispose of these assets within the next 12 months, they are classified as assets held for sale on the balance sheet.

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At September 30, 2010, SunCor had $6 million debt outstanding, a portion of which is in default. 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 repay remaining debt outstanding would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

As of September 30, 2010, SunCor could not transfer any cash dividends to Pinnacle West. This restriction does not affect Pinnacle West’s ability to meet its ongoing capital requirements.

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

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

Debt Provisions

Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. 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, 2010, the ratio was approximately 49% for Pinnacle West and 46% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

Neither Pinnacle West’s nor APS’ 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 for borrowings thereafter 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 credit facility borrowings.

See Note 2 for further discussions of liquidity matters.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of October 25, 2010 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase the cost of and limit access to capital. It may also require substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient liquidity to cover a downward revision to our credit ratings.

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

(a) Pinnacle West has a shelf registration under the 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

On January 1, 2010 we adopted amended accounting guidance relating to VIEs and, as a result, we have consolidated certain entities which were previously not consolidated. The consolidation of these entities has impacted our consolidated financial statement results. See Note 7 for a discussion of these impacts.

Guarantees and Letters of Credit

We have issued parental guarantees and obtained surety bonds on behalf of our subsidiaries including credit support instruments enabling APSES to offer energy-related products and surety bonds at APS, principally related to self-insured workers’ compensation. Non-performance or non-payment under the underlying contract by our subsidiaries would result in a payment liability on our part 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 and surety bonds on behalf of our subsidiaries. At September 30, 2010, we had no outstanding claims for payment under any of these guarantees. Our guarantees and surety bonds have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees or surety bonds from our subsidiaries. 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 12 for additional information regarding guarantees and letters of credit.

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Contractual Obligations

Our future contractual obligations for fuel and purchased power contracts and purchase obligations have increased from approximately $8.8 billion at December 31, 2009 to $10.3 billion at September 30, 2010 as follows (dollars in billions):

2010		2011-2012		2013-2014		Thereafter		Total
$	0.7	$	1.0	$	1.0	$	7.6	$	10.3

These amounts have increased since the 2009 Form 10-K primarily due to increased commitments for fuel and purchased power and contracts associated with meeting our renewable energy requirements.

See Note 2 for a list of payments due on total long-term debt and capitalized lease requirements.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. There have been no changes to our critical accounting policies since our 2009 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2009 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

On January 1, 2010 we adopted amended accounting guidance relating to VIEs, and as a result we have consolidated certain entities which were previously not consolidated. The consolidation of these entities has impacted our consolidated financial statement results. See Notes 1 and 7 for a discussion of these impacts.

MARKET AND CREDIT RISKS

Market Risks

Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.

Interest Rate and Equity Risk

We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Note 15). The nuclear decommissioning trust fund also has risks associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

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The following table shows the net pretax changes in mark-to-market of our derivative positions for the nine months ended September 30, 2010 and 2009 (dollars in millions):

	Nine Months Ended
	September 30,
	2010			2009
Mark-to-market of net positions at beginning of period	$	(169	)	$	(282	)
Recognized in earnings:
Change in mark-to-market losses for future period deliveries		(7	)		(3	)
Mark-to-market losses realized including ineffectiveness during the period		3			9
Decrease (increase) in regulatory asset		(52	)		59
Recognized in other comprehensive income (OCI):
Change in mark-to-market losses for future period deliveries (a)		(168	)		(128	)
Mark-to-market losses realized during the period		102			155
Change in valuation techniques		—			—
Mark-to-market of net positions at end of period	$	(291	)	$	(190	)

(a) The changes in mark-to-market recorded in OCI are due primarily to changes in forward natural gas prices.

The table below shows the fair value of maturities of our derivative contracts (dollars in millions and excluding margin and collateral) at September 30, 2010 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” in Item 8 of our 2009 Form 10-K and Note 15 for more discussion of our valuation methods.

																			Total
																Years			fair
Source of Fair Value	2010			2011			2012			2013			2014			thereafter			value
Prices actively quoted	$	(1	)	$	(1	)	$	—		$	—		$	—		$	—		$	(2	)
Prices provided by other external sources		(33	)		(144	)		(48	)		(15	)		—			—			(240	)
Prices based on models and other valuation methods		(3	)		(3	)		(4	)		(10	)		(8	)		(21	)		(49	)
Total by maturity	$	(37	)	$	(148	)	$	(52	)	$	(25	)	$	(8	)	$	(21	)	$	(291	)

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The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at September 30, 2010 and December 31, 2009 (dollars in millions):

	September 30, 2010					December 31, 2009
	Gain (Loss)					Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings
Electricity	$	1	$	(1	)	$	1	$	(1	)
Natural gas		1		(1	)		1		(1	)
Regulatory asset, liability or OCI (a)
Electricity		15		(15	)		21		(21	)
Natural gas		38		(38	)		59		(59	)
Total	$	55	$	(55	)	$	82	$	(82	)

(a) These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 15 — “Fair Value Measurements” for a discussion of our credit valuation adjustment policy. See Note 8 for a further discussion of credit risk.

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ARIZONA PUBLIC SERVICE COMPANY — RESULTS OF OPERATIONS

Operating Results — Three-month period ended September 30, 2010 compared with three-month period ended September 30, 2009

APS’ consolidated net income attributable to common shareholder for the three months ended September 30, 2010 was $227 million, compared with net income of $197 million for the comparable prior-year period. As discussed in greater detail below, net income increased approximately $30 million from the prior-year period primarily due to increased revenues related to APS’ retail rate increases, partially offset by increased operations and maintenance expenses.

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

	Three Months Ended
	September 30,
	2010			2009			Net Change
	(dollars in millions)
Operating revenues less fuel and purchased power expenses	$	762		$	702		$	60
Operations and maintenance		(217	)		(193	)		(24	)
Depreciation and amortization		(104	)		(103	)		(1	)
Taxes other than income taxes		(37	)		(34	)		(3	)
Other income (expenses), net		(1	)		1			(2	)
Interest charges, net of allowance for funds used during construction		(45	)		(53	)		8
Income taxes		(126	)		(118	)		(8	)
Noncontrolling interests (Note 7)		(5	)		(5	)		—
Net Income Attributable to Common Shareholder	$	227		$	197		$	30

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Operating revenues less fuel and purchased power expenses

Electric operating revenues less fuel and purchased power expenses were $60 million higher for the three months ended September 30, 2010 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Fuel and
				purchased
	Operating			power
	revenues			expenses			Net change
	(dollars in millions)
Retail regulatory settlement effective January 1, 2010:
Retail base rate increases, net of deferrals	$	98		$	43		$	55
Line extension revenues (Note 3)		6						6
Transmission rate decreases		(1	)					(1	)
Higher demand-side management and renewable energy surcharges (substantially offset in operations and maintenance expense)		11						11
Effects of weather on retail sales		6			2			4
Lower retail revenues related to recovery of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense		(90	)		(92	)		2
Higher fuel and purchased power costs, including the effects of higher off-system sales, net of related PSA deferrals		22			24			(2	)
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		(15	)		(5	)		(10	)
Miscellaneous items, net		(4	)		1			(5	)
Total	$	33		$	(27	)	$	60

Operations and maintenanceOperations and maintenance expenses increased $24 million for the three months ended September 30, 2010 compared with the prior-year period primarily because of:

• An increase of $8 million related to demand-side management and renewable energy programs, which are primarily offset in operating revenues;

• An increase of $6 million related to employee benefit costs; and

• An increase of $4 million in generation costs, including the acceleration of fossil-plant planned maintenance.

Interest charges, net of allowance for funds used during constructionInterest charges, net of allowance for funds used during construction, decreased $8 million for the three months ended September 30, 2010 compared with the prior-year period primarily because of higher rates in the current year for the allowance for equity and borrowed funds used during construction.

Income taxesIncome taxes were $8 million higher for the three months ended September 30, 2010 compared with the prior-year period primarily because of higher pretax income in the current-year period.

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Operating Results — Nine-month period ended September 30, 2010 compared with nine-month period ended September 30, 2009

APS’ net income attributable to common shareholder for the nine months ended September 30, 2010 was $328 million, compared with $260 million for the comparable prior-year period. Net income increased approximately $68 million from the prior-year period due to increased revenues related to APS’ retail rate increases and other factors, partially offset by milder weather in the second quarter of 2010.

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

	Nine Months Ended
	September 30,
	2010			2009			Net Change
	(dollars in millions)
Operating revenues less fuel and purchased power expenses	$	1,706		$	1,578		$	128
Operations and maintenance		(632	)		(596	)		(36	)
Depreciation and amortization		(308	)		(304	)		(4	)
Taxes other than income taxes		(100	)		(100	)		—
Other income (expenses), net		(7	)		(3	)		(4	)
Interest charges, net of allowance for funds used during construction		(143	)		(147	)		4
Income taxes		(173	)		(154	)		(19	)
Noncontrolling interests (Note 7)		(15	)		(14	)		(1	)
Net Income Attributable to Common Shareholder	$	328		$	260		$	68

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Operating revenues less fuel and purchased power expenses

Electric operating revenues less fuel and purchased power expenses were $128 million higher for the nine months ended September 30, 2010 compared with the prior-year period. The following table describes the major components of this change:

	Increase (Decrease)
				Fuel and
				purchased
	Operating			power
	revenues			expenses			Net change
	(dollars in millions)
Retail regulatory settlement effective January 1, 2010:
Retail base rate increases, net of deferrals	$	217		$	100		$	117
Line extension revenues (Note 3)		14						14
Transmission rate increases		8						8
Higher demand-side management and renewable energy surcharges (substantially offset in operations and maintenance expense)		26						26
Lower retail revenues related to recovery of PSA deferrals, substantially offset by lower amortization of fuel and purchased power expense		(211	)		(216	)		5
Higher fuel and purchased power costs including the effects of higher off-system sales, net of related PSA deferrals		24			29			(5	)
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		(16	)		(7	)		(9	)
Effects of weather on retail sales, primarily due to milder weather in the second quarter 2010		(27	)		(8	)		(19	)
Miscellaneous items, net		(7	)		2			(9	)
Total	$	28		$	(100	)	$	128

Operations and maintenanceOperations and maintenance expenses increased $36 million for the nine months ended September 30, 2010 compared with the prior-year period primarily because of:

• An increase of $20 million related to demand-side management and renewable energy programs, which are primarily offset in operating revenues;

• An increase of $7 million related to employee benefit costs; and

• An increase of $5 million related to customer service and other costs.

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Income taxesIncome taxes were $19 million higher for the nine months ended September 30, 2010 compared with the prior-year period primarily because of higher pretax income in the current-year period, partially offset by $15 million related to a reduction in APS’ 2010 effective income tax rate. See Note 6.

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, 2010 and 2009 (dollars in millions):

	Nine Months Ended
	September 30,
	2010			2009
Net cash flow provided by operating activities	$	506		$	713
Net cash flow used for investing activities		(548	)		(560	)
Net cash flow provided by (used for) financing activities		84			(139	)

The decrease of approximately $207 million in net cash provided by operating activities is primarily due to increased collateral and margin cash provided as a result of changes in commodity prices, the payment of income taxes in 2010, and a voluntary pension contribution in 2010 of approximately $100 million. These were partially offset by other changes in working capital.

The decrease of approximately $12 million in net cash used for investing activities is primarily due to higher contributions in aid of construction and other cash flows.

The decrease of approximately $223 million in net cash used for financing activities is primarily due to the repayment of short-term borrowings in 2009 offset by lower net sources of equity and long-term debt financing including the proceeds of approximately $253 million from the infusion of equity from Pinnacle West in 2010 and by APS’ issuance of $500 million of unsecured senior notes in 2009.

Contractual Obligations

APS’ future contractual obligations for fuel and purchased power contracts and purchase obligations have increased from approximately $8.8 billion at December 31, 2009 to $10.3 billion at September 30, 2010 as follows (dollars in billions):

2010		2011-2012		2013-2014		Thereafter		Total
$	0.7	$	1.0	$	1.0	$	7.6	$	10.3

These amounts have increased since the 2009 Form 10-K primarily due to increased commitments for fuel and purchased power and contracts associated with meeting our renewable energy requirements.

See Note 2 for a list of payments due on total long-term debt and capitalized lease requirements.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Key Financial Drivers” and “Market and Credit Risks” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.

Item 4. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (15 U.S.C. 78aet seq.), is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of September 30, 2010. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of September 30, 2010. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended September 30, 2010 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

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Part II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See “Environmental Matters” in Item 5 below, Part II, Item 5 of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 and the 2^nd Quarter 10-Q, and “Business of Arizona Public Service Company — Environmental Matters” in Item 1 of the 2009 Form 10-K in regard to pending or threatened litigation or other disputes.

See Note 10 with regard to a lawsuit brought by APS on behalf of itself and the other Palo Verde owners against the DOE, for information relating to FERC proceedings on California and Pacific Northwest energy market issues and for information regarding bankruptcy proceedings involving the landlord for our corporate headquarters building.

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. — Risk Factors in the 2009 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS. The risks described in the 2009 Form 10-K are not the only risks facing Pinnacle West and APS. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS.

Item 5. OTHER INFORMATION

Environmental Matters

Superfund

See “Superfund” in Note 10 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 Four Corners, and Salt River Project Agricultural Improvement and Power District (“SRP”), as the operating agent for the Navajo Generating Station (“Navajo”), perform a 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 2009 Form 10-K 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 Four Corners and Navajo plant participants’ obligations 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 these plants or the ability of individual participants to continue their participation in these plants.

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

On October 6, 2010, the EPA issued its proposed BART determination for Four Corners, which is subject to a sixty day public comment period beginning on October 19^th, the date it was published in the Federal Register. APS has requested a sixty day extension. Once the comment period has run, the EPA will then consider the comments submitted and issue a final rule. The rule, as proposed, would require the installation of post-combustion controls on each of Units 1-5 at Four Corners to reduce nitrogen oxides emissions. As previously disclosed, APS’ total costs for these controls could be up to approximately $422 million for Four Corners. The EPA also indicated in the proposal that it may require the installation of electrostatic precipitators or baghouses on Units 1, 2 and 3 to reduce particulate matter emissions. APS estimates that its total costs for such particulate removal equipment is approximately $220 million, which may also be required by no later than 2014 under the anticipated mercury rules. (See “Environmental Matters — Mercury and Other Hazardous Air Pollutants” in Part II, Item 5 of the 2^nd Quarter 10-Q for additional information on these anticipated rules.) The EPA proposed a 10% stack opacity limitation for all five units and a 20% opacity limitation on certain fugitive dust emissions, although the proposed fugitive dust provision is unrelated to BART. APS is currently evaluating the impacts of the proposed rule and intends to submit comments to the EPA during the comment period.

The EPA has not yet issued a proposed rule for the Navajo plant. The participant owners of Four Corners and the Navajo plant will have five years after the EPA issues its final determinations for each plant, respectively, to achieve compliance with their BART requirements.

Coal Combustion Waste.On June 21, 2010, the EPA released its proposed regulations governing the handling and disposal of coal combustion residuals (“CCRs”), such as fly ash and bottom ash. APS currently disposes of CCRs in ash ponds and dry storage areas at Cholla and Four Corners, and also sells a portion of its fly ash for beneficial reuse as a constituent in concrete production. The EPA proposes regulating CCRs as either non-hazardous waste or hazardous waste and is seeking comment on three different alternatives. The hazardous waste proposal would phase out the use of ash ponds for disposal of CCRs. The other two proposals regulate CCRs as non-hazardous waste and impose performance standards for ash disposal. One of these proposals would require retrofitting or closure of currently unlined ash ponds, while the other proposal would not require the installation of liners or pond closures. The EPA has not yet indicated a preference for any of the alternatives.

APS intends to file comments on the proposed rule during the public comment period, which was recently extended by the EPA to end on November 19, 2010. We do not know when the EPA will issue a final rule, including required compliance dates. We cannot currently predict the outcome of the EPA’s actions or whether such actions will have a material adverse impact on our financial position, results of operations or cash flows.

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Item 6. EXHIBITS

(a) Exhibits

Exhibit No.			Registrant(s)	Description
	12.1		Pinnacle West	Ratio of Earnings to Fixed Charges
	12.2		APS	Ratio of Earnings to Fixed Charges
	12.3		Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
	31.1		Pinnacle West	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
	31.2		Pinnacle West	Certificate of James R. Hatfield, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
	31.3		APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
	31.4		APS	Certificate of James R. Hatfield, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
	32.1	*	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	*	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	101.INS	*	Pinnacle West APS**	XBRL Instance Document
	101.SCH	*	Pinnacle West APS**	XBRL Taxonomy Extension Schema Document

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Exhibit No.		Registrant(s)	Description
	101.CAL*	Pinnacle West APS**	XBRL Taxonomy Extension Calculation Linkbase Document
	101.LAB*	Pinnacle West APS**	XBRL Taxonomy Extension Label Linkbase Document
	101.PRE*	Pinnacle West APS**	XBRL Taxonomy Extension Presentation Linkbase Document
	101.DEF*	Pinnacle West APS**	XBRL Taxonomy Definition Linkbase Document

*	Furnished herewith as an Exhibit.
**	Furnished voluntarily.

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

Exhibit				Previously Filed as	Date
No.		Registrant(s)	Description	Exhibit1	Filed
	3.1	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of May 19, 2010	3.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-3-10
	3.2	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008	3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-7-08
	3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’ Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93
	3.4	APS	Arizona Public Service Company Bylaws, amended as of December 16, 2008	3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-4473	2-20-09

¹ Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PINNACLE WEST CAPITAL CORPORATION (Registrant)
Dated: October 28, 2010	By:	/s/ James R. Hatfield
		James R. Hatfield
		Sr. Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)
	ARIZONA PUBLIC SERVICE COMPANY (Registrant)
Dated: October 28, 2010	By:	/s/ James R. Hatfield
		James R. Hatfield
		Sr. Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)

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