Arizona Public Service 10Q 2007 Q3 Quarterly report

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

(Mark One)


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

For the quarterly period ended September 30, 2007


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
Commission	its charter; State of Incorporation; Address;	IRS Employer
File Number	and 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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

PINNACLE WEST CAPITAL CORPORATION

Large accelerated filerþ Accelerated filero Non-accelerated filero

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filero Accelerated filero Non-accelerated filerþ

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 of November 2, 2007: 100,385,036
ARIZONA PUBLIC SERVICE COMPANY		Number of shares of common stock, $2.50 par value, outstanding as of November 2, 2007: 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.

This combined Form 10-Q is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing 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 filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

ALJ – Administrative Law Judge

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

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

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

Cholla – Cholla Power Plant

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

DOE – United States Department of Energy

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

EPA – United States Environmental Protection Agency

ERMC – Energy Risk Management Committee

FASB – Financial Accounting Standards Board

FERC – United States Federal Energy Regulatory Commission

FIP – Federal Implementation Plan

FIN – FASB Interpretation Number

Fitch – Fitch, Inc.

Four Corners – Four Corners Power Plant

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

IRS – United States Internal Revenue Service

kWh – kilowatt-hour, one thousand watts per hour

Moody’s – Moody’s Investors Service

MWh – megawatt-hour, one million watts per hour

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

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

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

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

Palo Verde – Palo Verde Nuclear Generating Station

Pinnacle West – Pinnacle West Capital Corporation, the Company

Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company, dissolved as of August 31, 2006

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

PRP – potentially responsible parties under Superfund

PSA – power supply adjustor

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

SEC – United States Securities and Exchange Commission

SFAS – Statement of Financial Accounting Standards

Silverhawk – Silverhawk Power Station

Standard & Poor’s – Standard & Poor’s Corporation

SunCor – SunCor Development Company, a subsidiary of the Company

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

2005 Deferrals – PSA deferrals related to 2005 replacement power costs associated with unplanned Palo Verde outages

2006 Deferrals – PSA deferrals related to 2006 replacement power costs associated with unplanned outages or reduced power operations at Palo Verde

2006 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2006

VIE – variable interest entity

West Phoenix – West Phoenix Power Plant

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,
	2007			2006
OPERATING REVENUES
Regulated electricity segment	$	1,043,723		$	886,979
Real estate segment		47,411			97,871
Marketing and trading		99,203			84,425
Other revenues		15,597			7,167

Total		1,205,934			1,076,442

OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		407,242			314,150
Real estate segment operations		46,391			78,853
Marketing and trading fuel and purchased power		93,860			80,906
Operations and maintenance		178,419			164,396
Depreciation and amortization		95,059			90,390
Taxes other than income taxes		34,940			31,697
Other expenses		11,246			5,610

Total		867,157			766,002

OPERATING INCOME		338,777			310,440

OTHER
Allowance for equity funds used during construction		5,235			3,178
Other income (Note 14)		4,276			18,055
Other expense (Note 14)		(6,744	)		(3,693	)

Total		2,767			17,540

INTEREST EXPENSE
Interest charges		54,393			50,577
Capitalized interest		(5,435	)		(5,612	)

Total		48,958			44,965

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		292,586			283,015
INCOME TAXES		91,588			98,836

INCOME FROM CONTINUING OPERATIONS		200,998			184,179
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense of $5,038 and $3 (Note 17)		7,710			(12	)

NET INCOME	$	208,708		$	184,167

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		100,324			99,491
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		100,829			99,973

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	2.00		$	1.85
Net income – basic		2.08			1.85
Income from continuing operations – diluted		1.99			1.84
Net income – diluted		2.07			1.84
DIVIDENDS DECLARED PER SHARE	$	0.525		$	0.50

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

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


	Nine Months Ended
	September 30,
	2007			2006
OPERATING REVENUES
Regulated electricity segment	$	2,291,067		$	2,065,823
Real estate segment		173,013			318,328
Marketing and trading		264,311			259,352
Other revenues		36,113			28,173

Total		2,764,504			2,671,676

OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		880,932			735,489
Real estate segment operations		154,008			248,595
Marketing and trading fuel and purchased power		226,337			227,797
Operations and maintenance		527,307			511,155
Depreciation and amortization		277,515			267,308
Taxes other than income taxes		104,416			99,970
Other expenses		28,537			22,562

Total		2,199,052			2,112,876

OPERATING INCOME		565,452			558,800

OTHER
Allowance for equity funds used during construction		14,874			10,612
Other income (Note 14)		11,976			34,448
Other expense (Note 14)		(13,685	)		(12,953	)

Total		13,165			32,107

INTEREST EXPENSE
Interest charges		158,352			143,985
Capitalized interest		(15,455	)		(14,595	)

Total		142,897			129,390

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		435,720			461,517
INCOME TAXES		140,428			154,900

INCOME FROM CONTINUING OPERATIONS		295,292			306,617
INCOME FROM DISCONTINUED OPERATIONS
Net of income tax expense of $5,827 and $1,415 (Note 17)		8,940			2,159

NET INCOME	$	304,232		$	308,776

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		100,200			99,277
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		100,767			99,723

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	2.95		$	3.09
Net income – basic		3.04			3.11
Income from continuing operations – diluted		2.93			3.07
Net income – diluted		3.02			3.10
DIVIDENDS DECLARED PER SHARE	$	1.575		$	1.50

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

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


	September 30,			December 31,
	2007			2006
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	43,914		$	87,210
Investment in debt securities		—			32,700
Customer and other receivables		636,980			501,628
Allowance for doubtful accounts		(6,197	)		(5,597	)
Materials and supplies (at average cost)		146,755			125,802
Fossil fuel (at average cost)		30,806			21,973
Deferred income taxes		20,165			982
Assets from risk management and trading activities (Note 10)		141,182			641,040
Assets held for sale (Note 17)		5,781			—
Other current assets		49,586			68,924

Total current assets		1,068,972			1,474,662


INVESTMENTS AND OTHER ASSETS
Real estate investments – net		617,050			526,008
Assets from long-term risk management and trading activities (Note 10)		67,161			167,211
Decommissioning trust accounts (Note 18)		375,898			343,771
Other assets		119,380			111,388

Total investments and other assets		1,179,489			1,148,378


PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		11,527,758			11,154,919
Less accumulated depreciation and amortization		3,950,883			3,797,475

Net		7,576,875			7,357,444
Construction work in progress		543,964			368,284
Intangible assets, net of accumulated amortization		100,970			96,100
Nuclear fuel, net of accumulated amortization		74,500			60,100

Total property, plant and equipment		8,296,309			7,881,928


DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		150,286			160,268
Other regulatory assets		583,331			686,016
Other deferred debits (Note 8)		117,618			104,691

Total deferred debits		851,235			950,975


TOTAL ASSETS	$	11,396,005		$	11,455,943

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

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


	September 30,			December 31,
	2007			2006
LIABILITIES AND COMMON STOCK EQUITY

CURRENT LIABILITIES
Accounts payable	$	305,420		$	346,047
Accrued taxes (Note 8)		315,697			263,935
Accrued interest		45,199			48,746
Short-term borrowings		273,608			35,750
Current maturities of long-term debt (Note 4)		67,231			1,596
Customer deposits		77,382			70,168
Liabilities from risk management and trading activities (Note 10)		89,265			558,195
Other current liabilities		132,543			134,123

Total current liabilities		1,306,345			1,458,560


LONG-TERM DEBT LESS CURRENT MATURITIES (NOTE 4)		3,229,350			3,232,633


DEFERRED CREDITS AND OTHER
Deferred income taxes		1,273,826			1,225,798
Regulatory liabilities		672,679			635,431
Liability for asset retirements		277,378			268,389
Liabilities for pension and other postretirement benefits (Note 6)		552,591			588,852
Liabilities from long-term risk management and trading activities (Note 10)		54,348			171,170
Unamortized gain – sale of utility plant		37,750			41,182
Other		423,172			387,812

Total deferred credits and other		3,291,744			3,318,634


COMMITMENTS AND CONTINGENCIES (SEE NOTES)

COMMON STOCK EQUITY
Common stock, no par value		2,130,285			2,114,550
Treasury stock		(2,062	)		(449	)

Total common stock		2,128,223			2,114,101

Accumulated other comprehensive income (loss) (Note 11):
Pension and other postretirement benefits		(44,902	)		(19,263	)
Derivative instruments		21,714			31,531

Total accumulated other comprehensive income (loss)		(23,188	)		12,268

Retained earnings		1,463,531			1,319,747

Total common stock equity		3,568,566			3,446,116


TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	11,396,005		$	11,455,943

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

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


	Nine Months Ended
	September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	304,232		$	308,776
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		302,314			288,065
Deferred fuel and purchased power		(203,065	)		(231,388	)
Deferred fuel and purchased power amortization		198,677			195,127
Deferred fuel and purchased power regulatory disallowance		14,370			—
Allowance for equity funds used during construction		(14,874	)		(10,612	)
Deferred income taxes		46,023			3,598
Change in mark-to-market valuations		18,907			16,974
Changes in current assets and liabilities:
Customer and other receivables		(120,832	)		(72,154	)
Materials, supplies and fossil fuel		(29,786	)		135
Other current assets		13,351			16,294
Accounts payable		(49,457	)		(69,608	)
Accrued taxes		14,207			130,137
Collateral		(48,103	)		(176,110	)
Other current liabilities		56,173			35,647
Proceeds from the sale of real estate assets		4,991			27,144
Real estate investments		(100,418	)		(94,533	)
Change in risk management and trading – liabilities		(13,959	)		(132,540	)
Change in other long-term assets		29,877			(6,609	)
Change in other long-term liabilities		54,846			54,880

Net cash flow provided by operating activities		477,474			283,223


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(710,355	)		(534,370	)
Capitalized interest		(15,455	)		(14,595	)
Proceeds from the sale of Silverhawk		—			207,620
Proceeds from sale of investment securities		69,225			536,679
Purchases of investment securities		(36,525	)		(739,996	)
Proceeds from nuclear decommissioning trust sales		203,014			170,827
Investment in nuclear decommissioning trust		(218,570	)		(186,383	)
Proceeds from sale of real estate investments		33,615			2,134
Other		(3,010	)		(2,246	)

Net cash flow used for investing activities		(678,061	)		(560,330	)


CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		181,321			703,283
Repayment of long-term debt		(119,700	)		(384,800	)
Short-term borrowings and payments – net		237,858			41,659
Dividends paid on common stock		(157,772	)		(148,876	)
Common stock equity issuance		18,626			24,574
Other		(3,042	)		15,486

Net cash flow provided by financing activities		157,291			251,326


NET DECREASE IN CASH AND CASH EQUIVALENTS		(43,296	)		(25,781	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		87,210			154,003


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	43,914		$	128,222


Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid, net of refunds	$	87,974		$	71,901
Interest paid, net of amounts capitalized	$	142,741		$	113,408

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

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, APSES, SunCor, El Dorado, Pinnacle West Marketing & Trading and Pinnacle West Energy (dissolved as of August 31, 2006). All significant intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

2. Condensed Consolidated Financial Statements

Our unaudited condensed consolidated financial statements reflect all adjustments that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. We suggest that these condensed consolidated financial statements and notes be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2006 Form 10-K. We have condensed certain prior year amounts on our condensed consolidated statements of cash flows to conform to current year presentations.

3. Quarterly Fluctuations

Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate and trading and wholesale marketing activities can have significant impacts on our results for interim periods. For these reasons, results for interim periods do not necessarily represent results to be expected for the year.

4. Changes in Liquidity

On January 4, 2007, the FERC issued an order permitting Pinnacle West to transfer its market-based rate tariff and wholesale power sales agreements to a newly-created Pinnacle West subsidiary, Pinnacle West Marketing & Trading. Pinnacle West completed the transfer on February 1, 2007, which resulted in Pinnacle West no longer being a public utility under the Federal Power Act. As a result, Pinnacle West is no longer subject to FERC jurisdiction in connection with its issuance of securities or its incurrence of long-term debt.

SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60 million, of which $35 million was outstanding at September 30, 2007. The loan matures on April 19, 2009, and may be extended one year if certain conditions are met.

In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of the proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.

On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan matures on July 31, 2009, and may be extended annually up to two years.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At September 30, 2007, APS had borrowings of $150 million under its revolving line of credit. Pinnacle West had borrowings of $105 million under its revolving line of credit. The amounts drawn under the Pinnacle West and APS lines of credit were used for general corporate purposes.

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At September 30, 2007, APS’ common equity ratio, as defined, was 54%, its total common equity was approximately $3.4 billion, and total capitalization was approximately $6.3 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.5 billion, assuming APS’ total capitalization remains the same.

SunCor has a $150 million loan facility secured primarily by an interest in land, commercial properties, land contracts and homes under construction. The loan facility requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. As of September 30, 2007, the amount of SunCor’s net assets that could not be transferred to Pinnacle West in the form of cash dividends as a result of these covenants was approximately $213 million.

As a result of the restrictions in the preceding two paragraphs, as of September 30, 2007, the restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at September 30, 2007, our consolidated net assets were approximately $3.6 billion). These restrictions do not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

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, 2007 (dollars in millions):


	Consolidated
Year	Pinnacle West		APS
2007	$	1	$	—
2008		194		1
2009		49		1
2010		224		224
2011		578		401
Thereafter		2,260		2,260

Total	$	3,306	$	2,887

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. Regulatory Matters

APS General Rate Case and Power Supply Adjustor

Retail Rate Increase

On June 19, 2007, the ACC rendered its decision in APS’ general retail rate case pursuant to which APS had requested a 20.4%, or $435 million, increase in its annual retail electricity revenues. APS’ request was designed to recover approximately $315 million in fuel-related expenses and approximately $120 million in non-fuel related expenses. The ACC order, which was formally issued on June 28, 2007, increased APS’ annual retail base revenues by approximately $322 million, effective July 1, 2007, which includes a fuel-related increase of approximately $315 million (excluding the PSA surcharge for 2005 Deferrals discussed below), or 15.1%, and non-fuel related increases of approximately $7 million. The interim PSA adjustor approved by the ACC on May 1, 2006, which was designed to recover a portion of APS’ fuel and purchased power costs deferred under the PSA, terminated effective with the rate increase, resulting in a net retail rate increase of approximately 6.8%. The base rate increase is premised on a return on equity of 10.75%; a 45%/55% long-term debt/common equity capital structure; a weighted-average cost of capital of 8.32%; an original cost rate base of $4.4 billion as of September 30, 2005; and a Base Fuel Rate of $0.0325 per kWh.

PSA Modifications

The ACC order modified the PSA in various respects, effective July 1, 2007. The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case, provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. As modified by the ACC’s recent order, the PSA is subject to specified parameters and procedures, including the following:

	•		APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

	•		the deferrals continue to be subject to a 90/10 sharing arrangement in which APS must absorb 10% of the retail fuel and purchased power costs above the Base Fuel Rate and may retain 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate, excluding certain costs, such as renewable energy resources and the capacity components of long-term purchase power agreements acquired through competitive procurement;

	•		the adjustment is made annually each February 1^st and goes into effect automatically unless suspended by the ACC;

	•		the PSA now uses a forward-looking estimate of fuel and purchased power costs (instead of historical deferred costs, as under the prior PSA) to set the annual PSA rate, which will be reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	•		the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) an “Historical Component,” under which the differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component;

	•		amounts to be recovered or refunded through the sum of the PSA components discussed in the preceding bullet point are limited to a maximum plus or minus $0.004 per kWh change in the PSA rate in any PSA Year;

	•		the Base Fuel Rate established in the ACC order reflects projected 2007 fuel and purchased power costs; as a result, the “Forward Component” for the PSA Year ending January 31, 2008 will be zero; and

	•		the PSA adjustor that took effect on February 1, 2007 ($0.004 per kWh), and that was scheduled to expire on January 31, 2008, will remain in effect as long as necessary after January 31, 2008 to collect $46 million of 2007 fuel and purchased power costs deferred as a result of the mid-year implementation of the new Base Fuel Rate.

2008 PSA Year

On September 28, 2007, APS submitted preliminary forecast calculations to the ACC for the Forward Component, Historical Component and Transition Component for the PSA Year beginning February 1, 2008. APS will update the calculations in a filing to the ACC prior to December 31, 2007. Based upon the preliminary calculations, the PSA rates would be limited to $0.004 per kWh for the 2008 PSA Year. Any uncollected deferrals during the 2008 PSA Year resulting from this limit will flow into the 2009 Historical Component at the end of 2008.

PSA Deferrals Related to Palo Verde Outages

APS recorded $45 million of 2005 Deferrals and $79 million of 2006 Deferrals. The ACC order (a) disallowed approximately $14 million, including accrued interest ($8 million after income taxes), of the 2005 Deferrals because the ACC found that the outage costs giving rise to those amounts resulted from APS’ imprudence and (b) approved APS’ recovery of the balance of the 2005 Deferrals (approximately $34 million, including accrued interest) through a temporary PSA surcharge over a twelve-month period effective July 1, 2007. In connection with the interim PSA adjustor approved on May 1, 2006, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde outage costs. Virtually all of the 2006 Deferrals were associated with a Unit 1 vibration issue. On October 4, 2007 the ACC staff filed a report with the ACC that concludes that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that these costs were prudently incurred and that the 2006 Deferrals are, therefore, recoverable.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PSA Balance

The following table shows the changes in the deferred fuel and purchase power regulatory asset for the nine months ended September 30, 2007 and 2006 (dollars in millions):


	Nine Months Ended
	September 30,
	2007			2006
Beginning balance	$	160		$	173
Deferred fuel and purchased power costs-current period		198			225
Regulatory disallowance		(14	)		—
Interest on deferred fuel and purchased power		5			6
Amounts recovered through revenues		(199	)		(195	)

Ending balance	$	150		$	209

Other Matters

The ACC order approved an environmental improvement surcharge (“EIS”) to recover capital costs incurred for environmental improvements made by APS in compliance with federal and state laws or regulatory requirements. The EIS will be set initially at $0.00016 per kWh, designed to produce approximately $4.5 million of cash per year until further order of the ACC.

The ACC order requires APS and the ACC staff to work to prepare a “nuclear performance standard” that the ACC can consider in a separate proceeding. The parties are currently working together to develop the standard.

The ACC Order also required APS to file a revised line extension schedule for ACC approval that would eliminate certain footage and equipment allowances for new or expanded electric service and remove any requirement for economic feasibility analyses used to determine whether or how much of an allowance should be granted. This would permit APS to collect, on a current basis, costs related to line extensions. Such pretax costs are currently estimated to be approximately $3,500-$5,000 per new meter set. These are average figures and the actual costs of a service extension will vary by customer class and the particulars of the extension.

On October 24, 2007, APS filed a proposed amendment to its line extension schedule. On November 2, 2007, the ACC staff issued its recommended order, which accepts APS’ proposed amendment in all respects except for the accounting treatment for payments received for new or upgraded service. APS’ proposal would treat such payments as non-refundable other electric revenues, while the ACC Staff proposes these payments should be treated as contributions in aid of construction (“CIAC”). CIAC treatment would result in a positive cash flow that would offset capital expenditures, but without any revenue impact.

APS proposed to “grandfather” applicants that have executed line extension agreements prior to the effective date of its amended line extension schedule. The impact of the amended line extension schedule on APS’ financial condition cannot be accurately predicted at this time and depends on the accounting treatment authorized for the proceeds, the extent of any “grandfathering” required by the ACC, and the level and mix of new APS customers. APS intends to file exceptions to the ACC staff’s recommended order by mid-November, and the final outcome of this matter is pending until further ACC action, which is expected to occur in late November.

APS Financing Authorization

On December 15, 2006, APS filed a financing application with the ACC requesting an increase in APS’ (a) current short-term debt authorization (7% of APS’ capitalization) to (i) 7% of APS’ capitalization plus (ii) $500 million in order to meet its growing cash requirements, including cash requirements for natural gas and power purchases and (b) current long-term debt authorization (approximately $3.2 billion) to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. On October 30, 2007, the ACC issued a financing order in which it approved APS’ requests, subject to specified parameters and procedures.

Federal

Price Mitigation Plan

In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. On February 13, 2006, the FERC increased this price cap to $400 per MWh for prospective sales. Sales at prices above the cap must be justified and are subject to potential refund. We do not expect this price cap to have a material impact on our financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FERC Order

On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.

On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ authority to make sales at market-based rates in the APS control area (the “April 17 Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.

On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on October 12, 2007.

Based upon an analysis of this matter and preliminary calculations of the refund obligations, at this time neither Pinnacle West nor APS believes that this proceeding will have a material adverse effect on its financial position, results of operations or cash flows.

FERC Rate Case

On July 10, 2007, APS submitted a revised Open Access Transmission Tariff (OATT) filing with the FERC to move from a fixed rate to a formula rate in order to more accurately reflect the costs that APS incurs in providing transmission and ancillary services. The requested formula rate would result in an estimated $37 million increase in annual transmission revenues, effective October 1, 2007. The proposed formula rate would be updated each year on June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 reports, and projected capital expenditures. Approximately $30 million of the requested increase represents charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”) and, as a result, would not affect APS’ earnings until such time as APS retail rates are adjusted to include these charges. As part of a retail rate case settlement order in 2005, the ACC approved the use of a mechanism by which changes in Retail Transmission Charges can be reflected in APS’ retail rates. APS is currently addressing the appropriate procedure to implement the retail transmission rate change.

On September 21, 2007, the FERC issued an order on these proposed revisions to APS’ transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge procedures, with an initial settlement conference held on October 11, 2007. The proposed rates

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

become effective March 1, 2008, subject to refund based upon the outcome of the settlement procedures and a hearing, if necessary, that has been scheduled in abeyance to allow time for such settlement procedures.

6. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a nonqualified supplemental excess benefit retirement plan (“SEBRP”), 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.

Pursuant to the ACC’s June 28, 2007 order in APS’ general rate case, APS was not allowed to recover the pension costs associated with the SEBRP through the ratemaking process. Therefore, amounts that were previously recorded as a regulatory asset, approximately $45 million ($27 million, net of income taxes), were charged to OCI at June 30, 2007 (see Notes 11 and S-2). This treatment is consistent with the accounting for this type of plan by our unregulated entities.

The following table provides details of the plans’ benefit costs for the three and nine months ended September 30, 2007 and 2006. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or capitalized as overhead construction (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,
	2007			2006			2007			2006			2007			2006			2007			2006
Service cost-benefits earned during the period	$	13		$	12		$	38		$	36		$	3		$	5		$	14		$	16
Interest cost on benefit obligation		25			23			75			69			6			10			27			27
Expected return on plan assets		(27	)		(24	)		(80	)		(72	)		(8	)		(10	)		(32	)		(29	)
Amortization of:
Transition (asset) obligation		—			(1	)		—			(1	)		1			1			2			2
Prior service cost		1			1			2			2			—			—			—			—
Net actuarial loss		4			6			12			18			1			2			3			7

Net periodic benefit cost	$	16		$	17		$	47		$	52		$	3		$	8		$	14		$	23

Portion of cost charged to expense	$	7		$	7		$	21		$	22		$	2		$	3		$	6		$	10

APS’ share of costs charged to expense	$	7		$	7		$	20		$	20		$	2		$	3		$	6		$	9

Contributions

Our pension contribution of $52 million has been made for the year. The contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $18 million, of which

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

approximately $15 million was contributed through September 30, 2007. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

7. Business Segments

Pinnacle West’s two reportable business segments are:

	•		our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and

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

Financial data for the three and nine months ended September 30, 2007 and 2006 and at September 30, 2007 and December 31, 2006 is provided as follows (dollars in millions):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007		2006
Operating Revenues:
Regulated electricity segment	$	1,044		$	887		$	2,291	$	2,066
Real estate segment		47			98			173		319
All other (a)		115			91			301		287

Total	$	1,206		$	1,076		$	2,765	$	2,672


Net Income (Loss):
Regulated electricity segment	$	205		$	170		$	278	$	252
Real estate segment		6			17			16		49
All other (a)		(2	)		(3	)		10		8

Total	$	209		$	184		$	304	$	309


	As of		As of
	September 30, 2007		December 31, 2006
Assets:
Regulated electricity segment	$	10,544	$	10,566
Real estate segment		673		591
All other (a)		179		299

Total	$	11,396	$	11,456


(a)		All other activities relate to marketing and trading, APSES products and services and El Dorado. None of these segments is a reportable segment.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. Income Taxes

As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next 12 months, we expect that the IRS will finalize its examination and will issue a settlement on the tax accounting method change. At this time, an estimate of the range of reasonably possible change in the uncertain tax position cannot be made. However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows.

We adopted FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.

The total amount of unrecognized tax benefits recorded in accrued taxes as of January 1, 2007 was $186 million, of which $179 million related to APS. The majority of the unrecognized tax benefits relate to the 2001 tax return position described above. Included in the balance of unrecognized tax benefits at January 1, 2007 are approximately $5 million of tax positions for consolidated Pinnacle West that, if recognized, would decrease our effective tax rate. For APS, approximately $3 million would have the same effect.

We continue to recognize potential accrued interest related to unrecognized tax benefits in the financial statements as income tax expense. As of January 1, 2007, the total amount of accrued interest expense related to unrecognized tax benefits was $54 million for consolidated Pinnacle West, which is included as a component of the $186 million unrecognized tax benefit noted above. APS’ share included in the total was approximately $53 million. Additionally, Pinnacle West has accrued $9 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS. APS’ share included in the total was approximately $7 million. Partial resolution of previously unrecognized tax benefits during the quarter ended September 30, 2007 resulted in a $10 million benefit.

As of January 1, 2007, the tax year ended December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ended prior to December 31, 1999 may remain subject to examination by state taxing authorities.

9. Variable-Interest Entities

In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.

APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of September 30, 2007, APS would have been required to assume approximately $208 million of debt and pay the equity participants approximately $174 million.

10. Derivative and Energy Trading Accounting

We use derivative instruments (primarily forward purchases and sales, swaps, options and futures) to manage our exposure to the commodity price risk inherent in the purchase and sale of fuel, electricity and emission allowances and credits. As of September 30, 2007, we hedged exposures to the price variability of the power and gas commodities for a maximum of 40 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Cash Flow Hedges

The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the three and nine months ended September 30, 2007 and 2006 are comprised of the following (dollars in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007		2006
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(239	)	$	(2,830	)	$	1,094	$	(5,984	)
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		—			4			—		(10	)
Gains from the discontinuance of cash flow hedges		6			—			320		434

During the next twelve months ending September 30, 2008, we estimate that a net gain of $34 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

Our assets and liabilities from risk management and trading activities are presented in two categories, regulated electricity and marketing and trading.

The following tables summarize our assets and liabilities from risk management and trading activities at September 30, 2007 and December 31, 2006 (dollars in thousands):


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
September 30, 2007	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	35,843	$	50,147	$	(64,714	)	$	(48,563	)	$	(27,287	)
Margin account and options		58,398		—		(557	)		—			57,841
Marketing and trading:
Mark-to-market		46,904		16,523		(23,529	)		(5,785	)		34,113
Options, emission allowances and other contracts – at cost		37		491		(465	)		—			63

Total	$	141,182	$	67,161	$	(89,265	)	$	(54,348	)	$	64,730


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2006	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	458,034	$	96,892	$	(481,661	)	$	(135,056	)	$	(61,791	)
Margin account and options		77,705		—		(2,228	)		—			75,477
Marketing and trading:
Mark-to-market		105,301		69,480		(61,553	)		(36,114	)		77,114
Options and emission allowances – at cost		—		839		(12,753	)		—			(11,914	)

Total	$	641,040	$	167,211	$	(558,195	)	$	(171,170	)	$	78,886

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

disclosed in the table above is unchanged. Further, this change has no impact on results of operations, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.

We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $58 million at September 30, 2007 and $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $4 million at September 30, 2007 and $10 million at December 31, 2006, and is included in other current assets on the Condensed Consolidated Balance Sheets. No collateral was provided to us by counterparties at September 30, 2007 and $54 million was provided to us at December 31, 2006, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.

Credit Risk

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ securities are 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, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

11. Comprehensive Income

Components of comprehensive income for the three and nine months ended September 30, 2007 and 2006 are as follows (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006
Net income	$	208,708		$	184,167		$	304,232		$	308,776

Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)		(44,715	)		(68,201	)		(15,035	)		(342,307	)
Net reclassification of realized (gains) losses on derivative instruments to income (b)		17,989			2,519			(1,072	)		(15,688	)
Net unrealized gains (losses) related to pension and other postretirement benefits (c)		605			—			(43,968	)		—
Reclassification of pension and other postretirement benefits to income		1,223			—			1,702			—
Net income tax benefit related to items of other comprehensive income		9,764			25,649			22,917			139,798

Total other comprehensive loss		(15,134	)		(40,033	)		(35,456	)		(218,197	)

Comprehensive income	$	193,574		$	144,134		$	268,776		$	90,579


(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 for contracted commodities delivered during the period.

(c)		In accordance with the ACC’s June 28, 2007 order in APS’ general rate case, these amounts primarily include costs that were previously recorded as a regulatory asset and have now been charged to OCI.

12. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim.

APS currently estimates it will incur $147 million (in 2006 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At September 30, 2007, APS had a regulatory liability of approximately $8 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

NRC Matters

In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator started but did not provide electrical output during routine inspections on July 25 and September 22, 2006. On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) for this matter. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), which has resulted in an enhanced NRC inspection regimen. Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS management has been conducting site-wide assessments of equipment and operations. Preliminary work in support of the NRC’s enhanced inspection regimen took place throughout summer 2007. On June 21, 2007, the NRC issued an initial confirmatory action letter confirming APS’ commitments regarding specific actions APS will take to improve Palo Verde’s performance. From October 1, 2007, through November 2, 2007, a team of NRC inspectors performed on-site in-depth inspections of Palo Verde equipment and operations. APS expects to be informed of the NRC’s inspection findings in late December 2007 or January 2008. APS continues to cooperate fully with the NRC throughout this process. Following receipt of the inspection findings and APS’ revisions to improvement plans to address the inspection findings, the NRC will issue a revised confirmatory action letter in the first quarter of 2008.

On November 9, 2006, APS notified the NRC that a senior reactor operator at Palo Verde had attempted to conceal a mistaken entry the operator had made in a Palo Verde operations verification log. The senior reactor operator resigned shortly thereafter. By letter dated July 12, 2007, the NRC notified APS that, based upon the results of its investigation of the matter, the NRC was considering an escalated enforcement action against Palo Verde due to the willfulness of the senior reactor operator’s actions. The NRC noted in its letter that the safety significance of the matter was very low. The NRC also offered to resolve the potential escalated enforcement action through the agency’s alternative dispute resolution program, which APS elected to do. As a result of the alternative dispute resolution proceeding between the NRC and APS, a settlement was reached under which APS agreed to take a number of corrective actions, including specified training for certain Palo Verde personnel and follow up reporting to the NRC. As a result of APS’ commitments, the NRC agreed not to pursue any further enforcement action in connection with this matter. The agreement between APS and the NRC became effective upon the NRC’s issuance of a confirmatory order, dated October 19, 2007, memorializing the agreement.

California Energy Market Issues and Refunds in the Pacific Northwest

FERC

In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006, the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Various parties filed petitions for rehearing on this order. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, or cash flows.

On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31, 2006. On December 28, 2006, certain parties petitioned the Supreme Court for a writ of certiorari. This petition was denied on June 18, 2007. On October 10, 2006, the State of California filed a motion to stay the issuance of the mandate (scheduled to be issued on November 2, 2006) until June 13, 2007. The Ninth Circuit has extended the stay until November 16, 2007. The outcome of the further proceedings cannot be predicted at this time.

On July 25, 2001, the FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. The Court stayed the date for petitions for rehearing of this opinion until November 16, 2007 to allow for any possible settlement negotiations. Although the FERC ruling in this matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or cash flows.

On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.

FERC Order

See “FERC Order” in Note 5 for a discussion of an order issued by the FERC on April 17, 2006.

Natural Gas Supply

Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium through December 31, 2005.

On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party sought appellate review to reallocate the cost responsibility associated with the changed contractual obligations in a way that would have increased APS’ annual capacity cost by approximately $3 million per year after income taxes for the period September 2003 through December 2005. This appeal had been stayed pending further consideration by the FERC. On May 26, 2006, the FERC issued an Order on Remand affirming its earlier decision that there was no basis for modifying the settlement rates during the remaining term of the settlement. By order of the D.C. Court of Appeals issued on October 10, 2007, this case was dismissed as a result of a motion for voluntary dismissal filed by the party that originally sought review in this case.

Navajo Nation Litigation

In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.

In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. APS cannot currently predict the outcome of this matter.

Superfund

Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures that may be required.

Salt River Project

Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserts that certain of these failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims that APS owes it approximately $29 million. APS disputes that it is required to pay these amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect that resolution of this matter will have a material adverse impact on our financial position, results of operations, or cash flows.

Litigation

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

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

13. Nuclear Insurance

The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $15 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 $88 million, with an annual payment limitation of approximately $13 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $21.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. Other Income and Other Expense

The following table provides detail of other income and other expense for the three and nine months ended September 30, 2007 and 2006 (dollars in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Other income:
SO2 emission allowance sales and other (a)	$	—		$	801		$	—		$	9,972
Interest income		2,921			5,878			8,283			13,068
Investment gains – net		—			1,656			—			559
SunCor other income (b)		778			9,430			2,136			10,313
Miscellaneous		577			290			1,557			536

Total other income	$	4,276		$	18,055		$	11,976		$	34,448


Other expense:
Non-operating costs (a)	$	(3,552	)	$	(2,954	)	$	(9,207	)	$	(10,501	)
Investment losses – net		(2,070	)		—			(1,128	)		—
Miscellaneous		(1,122	)		(739	)		(3,350	)		(2,452	)

Total other expense	$	(6,744	)	$	(3,693	)	$	(13,685	)	$	(12,953	)


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

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

15. Guarantees

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to commodity energy products. Our credit support instruments enable APSES to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at September 30, 2007 are as follows (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
Parental:
Pinnacle West Marketing & Trading	$	45		1	$	—		—
APSES		18		1		22		1

Total	$	63			$	22

At September 30, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in 2009. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

APS has entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2007, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $83 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, at September 30, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2007. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

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

16. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2007 and 2006:

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Basic earnings per share:
Income from continuing operations	$	2.00	$	1.85	$	2.95	$	3.09
Income from discontinued operations		0.08		—		0.09		0.02

Earnings per share – basic	$	2.08	$	1.85	$	3.04	$	3.11


Diluted earnings per share:
Income from continuing operations	$	1.99	$	1.84	$	2.93	$	3.07
Income from discontinued operations		0.08		—		0.09		0.03

Earnings per share – diluted	$	2.07	$	1.84	$	3.02	$	3.10

Dilutive stock options and performance shares increased average common shares outstanding by approximately 505,000 shares and 482,000 shares for the three months ended September 30, 2007 and September 30, 2006, respectively, and by approximately 567,000 shares and 446,000 shares for the nine months ended September 30, 2007 and 2006, respectively.

Options to purchase 610,250 shares of common stock for the three-month period and 115,200 shares for the nine-month period ended September 30, 2007 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 shares of common stock that were excluded from the computation of diluted earnings per share for that same reason were 447,650 shares for the three-month period ended September 30, 2006 and 732,534 shares for the nine-month period ended September 30, 2006.

17. Discontinued Operations

SunCor(real estate segment)–In 2006 and 2007, SunCor sold commercial properties that were required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144. As a result of those sales, we recorded in 2007 a gain from discontinued operations of approximately $8 million ($13 million pretax). Assets held for sale at September 30, 2007 relate to commercial properties in the amount of $6 million. The following table contains SunCor’s revenue, income before income taxes and income after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2007 and 2006 (dollars in millions):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Revenue	$	—	$	1	$	3	$	3
Income before income taxes		13		—		15		4
Income after income taxes		8		—		9		2

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

18. Nuclear Decommissioning Trust

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income and equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, APS has recorded the offsetting amount of unrealized gains (losses) on investment securities in other regulatory liabilities/assets.The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at September 30, 2007 and December 31, 2006 (dollars in millions):


			Total Unrealized
	Fair Value		Gains
September 30, 2007
Equity securities	$	181	$	75
Fixed income securities		195		3

Total	$	376	$	78


December 31, 2006
Equity securities	$	164	$	63
Fixed income securities		180		3

Total	$	344	$	66

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Realized gains	$	—		$	1		$	2		$	2
Realized losses		(1	)		(1	)		(3	)		(3	)
Proceeds from the sale of securities		70			56			203			171

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The fair value of fixed income securities, summarized by contractual maturities, at September 30, 2007 is as follows (dollars in millions):


Fair Value	September 30, 2007
Less than one year	$	8
1 year - 5 years		44
5 years - 10 years		38
Greater than 10 years		105

Total	$	195

19. New Accounting Standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance and preparing for the new disclosure requirements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance.

See Note 8 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial.

In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1). Under FSP FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This new guidance is effective for us on January 1, 2008, with early application permitted. We are currently evaluating the impacts of FSP FIN 39-1 on our balance sheet. We do not expect the guidance to have an impact on our results of operations or cash flows.

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)


	Three Months Ended
	September 30,
	2007			2006
ELECTRIC OPERATING REVENUES
Regulated electricity	$	1,045,751		$	888,724
Marketing and trading		1,311			(2,038	)

Total		1,047,062			886,686


OPERATING EXPENSES
Regulated electricity fuel and purchased power		409,059			315,666
Marketing and trading fuel and purchased power		819			839
Operations and maintenance		171,963			156,170
Depreciation and amortization		92,834			88,999
Income taxes		99,469			93,061
Other taxes		34,774			31,371

Total		808,918			686,106

OPERATING INCOME		238,144			200,580


OTHER INCOME (DEDUCTIONS)
Income taxes		1,262			684
Allowance for equity funds used during construction		5,235			3,178
Other income (Note S-3)		4,083			7,713
Other expense (Note S-3)		(3,303	)		(2,770	)

Total		7,277			8,805


INTEREST DEDUCTIONS
Interest on long-term debt		40,232			39,175
Interest on short-term borrowings		2,715			2,438
Debt discount, premium and expense		1,162			1,066
Allowance for borrowed funds used during construction		(2,945	)		(1,928	)

Total		41,164			40,751


NET INCOME	$	204,257		$	168,634

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

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


	Nine Months Ended
	September 30,
	2007			2006
ELECTRIC OPERATING REVENUES
Regulated electricity	$	2,295,570		$	2,070,673
Marketing and trading		11,511			11,732

Total		2,307,081			2,082,405


OPERATING EXPENSES
Regulated electricity fuel and purchased power		884,854			739,675
Marketing and trading fuel and purchased power		4,626			3,697
Operations and maintenance		508,528			493,896
Depreciation and amortization		271,519			263,279
Income taxes		145,294			136,682
Other taxes		103,884			99,585

Total		1,918,705			1,736,814

OPERATING INCOME		388,376			345,591


OTHER INCOME (DEDUCTIONS)
Income taxes		1,617			1,873
Allowance for equity funds used during construction		14,874			10,612
Other income (Note S-3)		12,872			22,798
Other expense (Note S-3)		(10,976	)		(10,298	)

Total		18,387			24,985


INTEREST DEDUCTIONS
Interest on long-term debt		120,707			108,315
Interest on short-term borrowings		6,748			7,449
Debt discount, premium and expense		3,477			3,264
Allowance for borrowed funds used during construction		(7,833	)		(5,322	)

Total		123,099			113,706


NET INCOME	$	283,664		$	256,870

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

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


	September 30,			December 31,
	2007			2006
ASSETS

UTILITY PLANT
Electric plant in service and held for future use	$	11,464,755		$	11,094,868
Less accumulated depreciation and amortization		3,941,211			3,789,534

Net		7,523,544			7,305,334

Construction work in progress		541,530			365,704
Intangible assets, net of accumulated amortization		100,479			95,601
Nuclear fuel, net of accumulated amortization		74,500			60,100

Total utility plant		8,240,053			7,826,739


INVESTMENTS AND OTHER ASSETS
Assets from long-term risk management and trading activities (Note S-1)		50,147			96,892
Decommissioning trust accounts (Note 18)		375,898			343,771
Other assets		70,773			67,763

Total investments and other assets		496,818			508,426


CURRENT ASSETS
Cash and cash equivalents		37,410			81,870
Investment in debt securities		—			32,700
Customer and other receivables		578,328			410,436
Allowance for doubtful accounts		(4,754	)		(4,223	)
Materials and supplies (at average cost)		146,755			125,802
Fossil fuel (at average cost)		30,806			21,973
Assets from risk management and trading activities (Note S-1)		94,242			539,308
Deferred income taxes		33,713			19,220
Other current assets		12,298			13,367

Total current assets		928,798			1,240,453


DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		150,286			160,268
Other regulatory assets		583,331			686,016
Unamortized debt issue costs		24,882			26,393
Other (Note 8)		80,470			65,397

Total deferred debits		838,969			938,074


TOTAL ASSETS	$	10,504,638		$	10,513,692

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

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


	September 30,			December 31,
	2007			2006
LIABILITIES AND EQUITY

CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital		2,105,466			2,065,918
Retained earnings		1,118,782			960,405
Accumulated other comprehensive income (loss) (Note S-2):
Pension benefits		(26,496	)		—
Derivative instruments		7,385			2,988

Common stock equity		3,383,299			3,207,473
Long-term debt less current maturities (Note 4)		2,876,970			2,877,502

Total capitalization		6,260,269			6,084,975


CURRENT LIABILITIES
Short-term debt		150,000			—
Current maturities of long-term debt (Note 4)		987			968
Accounts payable		205,560			223,417
Accrued taxes (Note 8)		448,514			381,444
Accrued interest		40,689			45,254
Customer deposits		68,987			61,900
Liabilities from risk management and trading activities (Note S-1)		65,352			490,855
Other current liabilities		114,533			74,728

Total current liabilities		1,094,622			1,278,566


DEFERRED CREDITS AND OTHER
Deferred income taxes		1,262,589			1,215,862
Regulatory liabilities		672,679			635,431
Liability for asset retirements		277,378			268,389
Pension and other postretirement liabilities (Note 6)		516,579			551,531
Customer advances for construction		85,672			71,211
Unamortized gain – sale of utility plant		37,750			41,182
Liabilities from long-term risk management and trading activities (Note S-1)		48,563			135,056
Other		248,537			231,489

Total deferred credits and other		3,149,747			3,150,151


COMMITMENTS AND CONTINGENCIES (SEE NOTES)

TOTAL LIABILITIES AND EQUITY	$	10,504,638		$	10,513,692

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

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


	Nine Months Ended
	September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	283,664		$	256,870
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		296,318			284,036
Deferred fuel and purchased power		(203,065	)		(231,388	)
Deferred fuel and purchased power amortization		198,677			195,127
Deferred fuel and purchased power regulatory disallowance		14,370			—
Allowance for equity funds used during construction		(14,874	)		(10,612	)
Deferred income taxes		36,646			29,566
Changes in mark-to-market valuations		(3,785	)		6,060
Changes in current assets and liabilities:
Customer and other receivables		(152,467	)		(85,190	)
Materials, supplies and fossil fuel		(29,786	)		(5,152	)
Other current assets		12			4,311
Accounts payable		(26,687	)		(13,468	)
Accrued taxes		31,504			133,359
Collateral		(2,491	)		(185,091	)
Other current liabilities		42,923			41,306
Change in risk management and trading – liabilities		(1,952	)		(120,769	)
Change in other long-term assets		31,960			(70,411	)
Change in other long-term liabilities		60,390			57,278

Net cash flow provided by operating activities		561,357			285,832


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(675,870	)		(466,095	)
Capitalized interest		(7,833	)		(5,322	)
Proceeds from sale of investment securities		69,225			389,178
Purchases of investment securities		(36,525	)		(592,495	)
Proceeds from nuclear decommissioning trust sales		203,014			170,827
Investment in nuclear decommissioning trust		(218,570	)		(186,383	)
Other		(62	)		(3,453	)

Net cash flow used for investing activities		(666,621	)		(693,743	)


CASH FLOWS FROM FINANCING ACTIVITIES
Equity infusion		39,548			210,000
Short-term borrowings, net		150,000			—
Issuance of long-term debt		—			395,481
Dividends paid on common stock		(127,500	)		(127,500	)
Repayment and reacquisition of long-term debt		(1,244	)		(2,310	)

Net cash flow provided by financing activities		60,804			475,671

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(44,460	)		67,760
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		81,870			49,933

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	37,410		$	117,693


Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds	$	70,083		$	24,414
Interest, net of amounts capitalized	$	124,186		$	95,149

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

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


	Condensed	APS’
	Consolidated	Supplemental
	Footnote	Footnote
	Reference	Reference
Consolidation and Nature of Operations	Note 1	—
Condensed Consolidated Financial Statements	Note 2	—
Quarterly Fluctuations	Note 3	—
Changes in Liquidity	Note 4	—
Regulatory Matters	Note 5	—
Retirement Plans and Other Benefits	Note 6	—
Business Segments	Note 7	—
Income Taxes	Note 8	—
Variable-Interest Entities	Note 9	—
Derivative and Energy Trading Accounting	Note 10	Note S-1
Comprehensive Income (Loss)	Note 11	Note S-2
Commitments and Contingencies	Note 12	—
Nuclear Insurance	Note 13	—
Other Income and Other Expense	Note 14	Note S-3
Guarantees	Note 15	—
Earnings Per Share	Note 16	—
Discontinued Operations	Note 17	—
Nuclear Decommissioning Trust	Note 18	—
New Accounting Standards	Note 19	—

S-1. Derivative and Energy Trading Accounting

APS is exposed to the impact of market fluctuations in the commodity price of electricity, natural gas and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels, and emission allowances and credits. As of September 30, 2007, APS hedged exposures to these risks for a maximum of 40 months.

Cash Flow Hedges

The changes in the fair value of APS’ hedged positions included in the APS Condensed Statements of Income, after consideration of amounts deferred under the PSA, for the three and nine months ended September 30, 2007 and 2006 were comprised of the following (dollars in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007		2006
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(239	)	$	(2,505	)	$	1,094	$	(5,765	)
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		—			4			—		(10	)
Gains from the discontinuance of cash flow hedges		—			—			150		159

During the next twelve months ending September 30, 2008, APS estimates that a net gain of $16 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

APS’ assets and liabilities from risk management and trading activities are presented in two categories.

The following tables summarize APS’ assets and liabilities from risk management and trading activities at September 30, 2007 and December 31, 2006 (dollars in thousands):


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
September 30, 2007	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	35,843	$	50,147	$	(64,714	)	$	(48,563	)	$	(27,287	)
Margin account and options		58,398		—		(557	)		—			57,841
Marketing and Trading:
Mark-to-market		1		—		(50	)		—			(49	)
Options and other contracts – at cost		—		—		(31	)		—			(31	)

Total	$	94,242	$	50,147	$	(65,352	)	$	(48,563	)	$	30,474


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2006	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	458,034	$	96,892	$	(481,661	)	$	(135,056	)	$	(61,791	)
Margin account and options		77,705		—		(2,228	)		—			75,477
Marketing and Trading:
Mark-to-market		3,569		—		(6,654	)		—			(3,085	)
Options at cost		—		—		(312	)		—			(312	)

Total	$	539,308	$	96,892	$	(490,855	)	$	(135,056	)	$	10,289

During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps in the regulated electricity segment. We historically presented the buy side and the sell side of such swaps at fair value gross on our consolidated balance sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset/liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.

Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. Collateral provided to counterparties was $4 million at September 30, 2007 and $2 million at December 31, 2006 and is included in other current assets on the

Condensed Balance Sheets. No collateral was provided to us by counterparties at September 30, 2007 and $1 million was provided to us at December 31, 2006, and is included in other current liabilities on the Condensed Balance Sheets.

S-2. Comprehensive Income

Components of APS’ comprehensive income (loss) for the three and nine months ended September 30, 2007 and 2006 are as follows (dollars in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Net income	$	204,257		$	168,634		$	283,664		$	256,870

Other comprehensive income (loss):
Net unrealized losses on derivative instruments (a)		(35,322	)		(51,359	)		(10,558	)		(276,555	)
Net reclassification of realized losses on derivative instruments to income (b)		23,324			8,068			17,795			910
Net unrealized losses related to pension benefits (c)		—			—			(44,613	)		—
Reclassification of pension and other postretirement benefits to income		1,005			—			1,005			—
Net income tax benefit related to items of other comprehensive income		4,314			16,906			14,272			107,640

Total other comprehensive loss		(6,679	)		(26,385	)		(22,099	)		(168,005	)

Comprehensive income	$	197,578		$	142,249		$	261,565		$	88,865


(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.

(c)		In accordance with the ACC’s June 28, 2007 order in APS’ general rate case, these amounts include costs that were previously recorded as a regulatory asset and have now been charged to OCI.

S-3. 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, 2007 and 2006 (dollars in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Other income:
SO2 emission allowance sales and other (a)	$	420		$	801		$	854		$	9,972
Interest income		2,771			5,439			7,630			10,943
Investment gains – net		315			1,193			2,832			1,358
Miscellaneous		577			280			1,556			525

Total other income	$	4,083		$	7,713		$	12,872		$	22,798


Other expense:
Non-operating costs (a)	$	(2,690	)	$	(2,353	)	$	(7,924	)	$	(8,879	)
Miscellaneous		(613	)		(417	)		(3,052	)		(1,419	)

Total other expense	$	(3,303	)	$	(2,770	)	$	(10,976	)	$	(10,298	)


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

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

INTRODUCTION

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

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.

The ACC regulates APS’ retail electric rates. Our profitability is affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ capital expenditure requirements, which are discussed below under “Liquidity and Capital Resources,” are substantial because of the significant customer growth in APS’ service territory, highlighting APS’ need for the timely recovery of these and other expenditures through rates. As discussed in greater detail in Note 5, on June 28, 2007, the ACC issued an order in a general rate case that APS filed in late 2005. Additionally, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde outage costs. Virtually all of the 2006 Deferrals were associated with a Unit 1 vibration issue. On October 4, 2007 the ACC staff filed a report with the ACC that concludes that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that these costs were prudently incurred and that the 2006 Deferrals, totaling approximately $79 million, are, therefore, recoverable.

SunCor, our real estate development subsidiary, has been and is expected to continue to be an important source of earnings. See discussion below in “Pinnacle West Consolidated – Factors Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APSES, provides competitive commodity-related energy services and energy-related products and services to commercial and industrial retail customers in the western United States. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures. Pinnacle West Marketing & Trading is the Company’s marketing and trading subsidiary, which began activity in February 2007. See Note 4.

We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction. We plan to expand long-term resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.

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

EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

Pinnacle West’s two reportable business segments are:

	•		our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and

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

The following table summarizes income (loss) from continuing operations for the three months and nine months ended September 30, 2007 and 2006 and reconciles net income in total (dollars in millions):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007		2006
Regulated electricity segment	$	205		$	170		$	278	$	252
Real estate segment		(2	)		17			7		47
All other (a)		(2	)		(3	)		10		8

Income from continuing operations		201			184			295		307
Discontinued operations – net of tax (b)		8			—			9		2

Net income	$	209		$	184		$	304	$	309


(a)		All other includes activities related to marketing and trading, APSES products and services and El Dorado. None of these segments is a reportable segment.

(b)		Primarily relates to sales of commercial properties.

PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS

Regulatory Matters

On June 28, 2007, the ACC issued an order in the general rate case of APS. In its order, effective July 1, 2007, among other things, the ACC (a) approved an increase in APS’ retail base rates, the components of which included an increase in APS’ Base Fuel Rate and a non-fuel rate increase; (b) modified the PSA; and (c) disallowed certain PSA deferrals as described below.

Under the PSA, APS defers for future rate recovery or refund 90% of the difference between actual retail fuel and purchased power costs and the Base Fuel Rate included in APS’ retail rates, subject to specified parameters. APS absorbs the other 10% of variances between actual retail fuel and purchased power costs and the Base Fuel Rate. The increase in APS’ Base Fuel Rate approved by the ACC reduced the amount of fuel and purchased power costs subject to the 90/10 PSA sharing arrangement. APS recovers PSA deferrals from its customers through PSA annual adjustors and surcharges. The recovery of PSA deferrals recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses recorded as fuel and purchased power. The balance of APS’ PSA accumulated unrecovered

deferrals at September 30, 2007 was approximately $150 million. See Note 5 for additional information about the ACC order and the PSA.

APS recorded PSA deferrals of (a) $45 million related to the 2005 Deferrals and (b) $79 million related to the 2006 Deferrals. In its order, the ACC (a) disallowed approximately $14 million, including accrued interest ($8 million after income taxes), of the 2005 Deferrals and (b) approved APS’ recovery of the balance of the 2005 Deferrals (approximately $34 million, including accrued interest) through a temporary PSA surcharge over a twelve-month period beginning July 1, 2007. The ACC directed the ACC staff to conduct a “prudence audit” of the 2006 Palo Verde outage costs. Virtually all of the 2006 Deferrals were associated with a Unit 1 vibration issue. On October 4, 2007, the ACC staff filed a report with the ACC that concludes that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that the 2006 Deferrals were prudently incurred and, therefore, are recoverable.

Operating Results – Three-month period ended September 30, 2007 compared with three-month period ended September 30, 2006

Our consolidated net income for the three months ended September 30, 2007 was $209 million compared with $184 million for the comparable prior-year period. The current period includes income from discontinued operations of $8 million, which was related to income from the sale of commercial properties at SunCor. Income from continuing operations increased $17 million in the period-to-period comparison, reflecting the following changes in earnings:

	•		Regulated Electricity Segment – Income from continuing operations increased approximately $35 million primarily due to the effects of hotter weather on retail sales; higher retail sales primarily due to customer growth and usage patterns; impacts of the retail rate increase (see “Regulatory Matters” above); and income tax benefits related to prior years resolved in 2007. These positive factors were partially offset by higher operations and maintenance expense primarily for customer service and regulatory programs and increased costs for generation, including the Palo Verde performance improvement plan. In addition, higher fuel and purchased power costs related to commodity price increases were offset by the deferral of such costs in accordance with the PSA. See “Regulatory Matters” above.

	•		Real Estate Segment – Income from continuing operations decreased approximately $19 million primarily due to lower sales of residential property and land parcels resulting from the continued slowdown in the western United States real estate markets and prior-year sales of certain joint venture assets. Income from discontinued operations increased $8 million due to increased commercial property sales.

Additional details on the major factors that increased (decreased) net income for the three-month period ended September 30, 2007 compared with the same period in 2006 are contained in the following table (dollars in millions):


	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment:
Effects of hotter weather on retail sales	$	27		$	16
Higher retail sales primarily due to customer growth and usage patterns, excluding weather effects		17			10
Impacts of retail rate increase (see discussion above):
Revenue increase related to higher Base Fuel Rate		114			70
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(103	)		(63	)
Non-fuel rate increase		5			3
Net changes in fuel and purchased power costs related to prices:
Higher fuel and purchased power costs due to increased prices		(39	)		(24	)
Increased deferred fuel and purchased power costs related to increased prices		37			23
Operations and maintenance increases primarily due to:
Customer service costs and regulatory programs		(8	)		(5	)
Increased generation costs, including Palo Verde performance improvement plan		(6	)		(4	)
Income tax benefits related to prior years resolved in 2007		—			10
Miscellaneous items, net		(4	)		(1	)

Increase in regulated electricity segment net income		40			35
Lower real estate segment contribution primarily due to decreased sales of residential property and land parcels and prior-year sales of certain joint venture assets		(31	)		(19	)
Other miscellaneous items, net		1			1

Increase in income from continuing operations	$	10			17

Discontinued operations primarily related to sales of commercial real estate assets					8

Increase in net income				$	25

Regulated Electricity Segment Revenues

Regulated electricity segment revenues were $157 million higher for the three months ended September 30, 2007 compared with the prior-year period primarily because of:

	•		a $119 million increase in retail revenues due to retail rate increase effective July 1, 2007;

	•		a $36 million increase in retail revenues due to the effects of hotter weather;

	•		a $22 million increase in retail revenues primarily related to customer growth and usage patterns, excluding weather effects;

	•		a $16 million increase in Off-System Sales due to higher prices and volumes;

	•		a $44 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount

recorded as fuel and purchased power expense (see “Regulatory Matters” above); and

•

an $8 million net increase due to miscellaneous factors.

Real Estate Segment Revenues

Real estate segment revenues were $50 million lower for the three months ended September 30, 2007 compared with the prior-year period primarily because of:

	•		a $48 million decrease in residential property sales due to the continued slowdown in the western United States real estate markets;

	•		a $4 million decrease in revenue primarily due to lower sales of land parcels; and

	•		a $2 million net increase due to miscellaneous factors.

All Other Revenues

Marketing and trading revenues were $15 million higher for the three months ended September 30, 2007 compared with the prior-year period primarily due to an increase in competitive retail sales volumes in California.

Other revenues were $8 million higher for the three months ended September 30, 2007 compared to the prior-year period primarily as a result of increased sales by APSES of energy related products and services.

Operating Results — Nine-month period ended September 30, 2007 compared with nine-month period ended September 30, 2006

Our consolidated net income for the nine months ended September 30, 2007 was $304 million compared with $309 million for the comparable prior-year period. Our net income includes income from discontinued operations related primarily to sales of commercial properties by SunCor of $9 million in the current period and $2 million in the prior-year period. Income from continuing operations decreased $12 million in the period-to-period comparison, reflecting the following changes in earnings:

•

Regulated Electricity Segment — Income from continuing operations increased approximately $26 million primarily due to higher retail sales primarily due to customer growth and usage patterns; the effects of weather on retail sales; impacts of the retail rate increase; and income tax benefits related to prior years resolved in 2007. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs, including the Palo Verde performance improvement plan, customer service and regulatory programs; income tax credits related to prior years resolved in 2006; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior-year period and lower interest income as a result of lower investment balances; and a

regulatory disallowance. In addition, higher fuel and purchased power costs related to commodity price increases were partially offset by the deferral of such costs in accordance with the PSA. See “Regulatory Matters” above for further discussion.

•

Real Estate Segment — Income from continuing operations decreased approximately $40 million primarily due to lower sales of residential property and land parcels resulting from the continued slowdown in the western United States real estate markets and prior-year sales of certain joint venture assets. Income from discontinued operations increased $7 million due to increased commercial property sales.

Additional details on the major factors that increased (decreased) net income for the nine-month period ended September 30, 2007 compared with the same period in 2006 are contained in the following table (dollars in millions):


	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment:
Higher retail sales primarily due to customer growth and usage patterns, excluding weather effects	$	37		$	23
Effects of weather on retail sales		33			20
Impacts of retail rate increase (see discussion above):
Revenue increase related to higher Base Fuel Rate		114			70
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(103	)		(63	)
Non-fuel rate increase		5			3
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs due to increased prices		(80	)		(49	)
Increased deferred fuel and purchased power costs related to increased prices		75			46
Regulatory disallowance (see “Regulatory Matters” above)		(14	)		(8	)
Operations and maintenance increases primarily due to:
Increased generation costs, including Palo Verde performance improvement plan		(8	)		(5	)
Customer service costs and regulatory programs		(8	)		(5	)
Higher depreciation and amortization primarily due to increased plant balances		(8	)		(5	)
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in the prior-year period		(13	)		(8	)
Income tax benefits related to prior years resolved in 2007		—			13
Income tax credits related to prior years resolved in 2006		—			(10	)
Miscellaneous items, net		7			4

Increase in regulated electricity segment net income		37			26
Lower real estate segment contribution primarily due to decreased sales of residential property and land parcels and prior year sales of certain joint venture assets		(66	)		(40	)
Higher marketing and trading contribution primarily due to higher competitive retail sales volumes in California and higher mark-to-market gains because of changes in forward prices		6			4
Other miscellaneous items, net		(3	)		(2	)

Decrease in income from continuing operations	$	(26	)		(12	)

Discontinued operations primarily related to increased sales of commercial real estate assets					7

Decrease in net income				$	(5	)

Regulated Electricity Segment Revenues

Regulated electricity segment revenues were $225 million higher for the nine months ended September 30, 2007 compared with the prior-year period primarily because of:

	•		a $119 million increase in retail revenues due to retail rate increase effective July 1, 2007;

	•		a $49 million increase in retail revenues primarily related to customer growth and usage patterns, excluding weather effects;

	•		a $45 million increase in retail revenues due to the effects of weather; and

	•		a $12 million net increase due to miscellaneous factors.

Real Estate Segment Revenues

Real estate segment revenues were $145 million lower for the nine months ended September 30, 2007 compared with the prior-year period primarily because of:

	•		a $124 million decrease in residential property sales due to the continued slowdown in western United States real estate markets;

	•		a $23 million decrease in revenue primarily due to lower sales of land parcels; and

	•		a $2 million net increase due to miscellaneous factors.

All Other Revenues

Marketing and trading revenues were $5 million higher for the nine months ended September 30, 2007 compared with the prior-year period primarily because of higher competitive retail sales volumes in California and higher mark-to-market gains because of changes in forward prices.

Other revenues were $8 million higher for the nine months ended September 30, 2007 compared to the prior-year period primarily as a result of increased sales by APSES of energy-related products and services.

LIQUIDITY AND CAPITAL RESOURCES — Pinnacle West Consolidated

Operating Cash Flows

Net cash provided by operating activities was $477 million for the nine months ended September 30, 2007, compared to $283 million for the same period in 2006, an increase in cash provided of $194 million. This change was primarily due to the 2006 return of cash collateral and margin cash held as a result of changes in commodity prices, partially offset by lower cash contributions from decreased sales of residential properties and land parcels due to the continued slowdown in western United States real estate markets.

Investing Cash Flows

Net cash used for investing activities was $678 million for the nine months ended September 30, 2007, compared to $560 million for the same period in 2006, an increase in cash used of $118 million. This change was primarily due to:

	•		Approximately $208 million in proceeds received from the sale of Silverhawk in 2006;

	•		An approximate $178 million increase in capital expenditures (see table and discussion below);

	•		An approximate $236 million decrease in the invested position, primarily at APS. In 2006 we issued long-term debt and invested some of the proceeds in short-term investment securities until they were later redeemed and the cash used for general corporate purposes.

Capital Expenditure Requirements

The following table summarizes the actual capital expenditures for the nine months ended September 30, 2006 and 2007 and estimated capital expenditures for the next three years (dollars in millions):

CAPITAL EXPENDITURES


	Nine Months Ended				Estimated for the Year Ended
	September 30,				December 31,
	2006		2007		2007		2008		2009
APS
Distribution	$	275	$	306	$	360	$	410	$	460
Transmission		72		97		170		200		290
Generation		110		259		390		300		340
Other (a)		14		10		30		40		40

Subtotal		471		672		950		950		1,130
SunCor (b)		151		132		140		100		100
Other		6		2		10		20		10

Total	$	628	$	806	$	1,100	$	1,070	$	1,240


(a)		Primarily information systems and facilities projects.

(b)		Consists primarily of capital expenditures for residential land development and retail and office building construction reflected in “Real estate investments” on the Condensed Consolidated Statements of Cash Flows.

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

Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants and the replacement of Palo Verde steam generators (see below). Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment. Environmental expenditures are estimated at approximately $80 million to $100 million per year for 2007, 2008 and

2009. Generation also includes nuclear fuel expenditures of approximately $110 million for 2007, $40 million for 2008, and $100 million for 2009.

Installation of new steam generators in Palo Verde Unit 3 is in progress and is scheduled for completion in the fourth quarter of 2007 at an approximate cost of $70 million (APS’ share). Approximately $52 million of the Unit 3 steam generator costs have been incurred through September 30, 2007, with the remaining $18 million included in the capital expenditures table above. Capital expenditures will be funded with internally generated cash and/or external financings.

Financing Cash Flows and Liquidity

Net cash provided by financing activities was $157 million for the nine months ended September 30, 2007, compared to $251 million for the same period in 2006, a decrease in cash provided of $94 million. This change was primarily due to:

	•		An approximate $256 million decrease due to the 2006 issuance of approximately $318 million of new long-term debt, net of redemptions, in order to fund our construction program and for other general corporate purposes. During the first nine months for 2007, we issued approximately $62 million of new long-term debt, net of refinancing.

	•		An approximate $196 million increase in short-term borrowings to fund day-to-day operations and liquidity needs.

Pinnacle West (Parent Company)

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

Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At September 30, 2007, APS’ common equity ratio, as defined, was approximately 54% (see Note 4).

On October 17, 2007, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on December 3, 2007, to shareholders of record on November 1, 2007.

At September 30, 2007, Pinnacle West had borrowings of $105 million under its revolving line of credit. The amount drawn was used for general corporate purposes.

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 fund performance and fund valuation assumptions. We contributed $47 million in 2006. Our 2007 pension contribution of $52 million has been made for the year. The contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $18 million, of which approximately $15 million has been contributed through September 30, 2007. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

APS

APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West. As noted above, in May 2007, Pinnacle West infused approximately $40 million of equity into APS.

Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. APS requested the ACC to increase (a) APS’ current short-term debt authorization (7% of APS’ capitalization) to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ current long-term debt authorization (approximately $3.2 billion) to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. On October 30, 2007, the ACC issued a financing order in which it approved APS’ requests, subject to specified parameters and procedures. See “APS Financing Authorization” in Note 5.

See “Regulatory Matters” above and “PSA Modifications” in Note 5 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and, if necessary, periodic surcharge applications.

See “Cash Flow Hedges” in Note 10 for information related to collateral provided to us by counterparties.

At September 30, 2007, APS had borrowings of $150 million under its revolving line of credit. The amount drawn was used for general corporate purposes.

Other Subsidiaries

During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures during the nine months ended September 30, 2007 and projected capital

expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.

On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan matures on July 31, 2009, and may be extended annually up to two years.

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 expects minimal capital expenditures over the next three years.

See “Overview” above and Note 4 for discussion of Pinnacle West Marketing & Trading, the Company’s marketing and trading subsidiary, which began activity in February 2007.

Debt Provisions

Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At September 30, 2007, the ratio was approximately 49% for Pinnacle West and 46% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.8 times under APS’ bank financing agreements as of September 30, 2007. 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, in the event of a rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.

See Note 4 for further discussions.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of November 2, 2007 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 access to capital. It may also require additional collateral related to certain derivative instruments (see Note 10).


	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Senior unsecured (a)	Baa3 (P)	BB+ (prelim)	N/A
Commercial paper	P-3	A-3	F-3
Outlook	Negative	Stable	Stable

APS
Senior unsecured	Baa2	BBB-	BBB
Secured lease obligation bonds	Baa2	BBB-	BBB
Commercial paper	P-2	A-3	F-2
Outlook	Negative	Stable	Stable


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

Off-Balance Sheet Arrangements

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

Guarantees and Letters of Credit

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to commodity energy products. Our credit support instruments enable APSES to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 15 for additional information regarding guarantees and letters of credit.

Contractual Obligations

Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2006 Form 10-K, with the exception of our aggregate fuel and purchased power commitments, which increased from approximately $2.6 billion at December 31, 2006 to $3.5 billion at September 30, 2007 as follows (dollars in billions):


2007	2008-2009		2010-2011		Thereafter		Total
$0.5	$	0.7	$	0.5	$	1.8	$	3.5

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

Given our adoption of FIN 48, we are now required to include uncertain tax positions in our contractual obligations disclosure. As of September 30, 2007, we have uncertain tax positions of approximately $210 million and we expect a majority of these positions to be settled within the next twelve months. See Note 8 for additional information.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting, the determination of the appropriate accounting for our pension and other postretirement benefits and derivatives accounting. There have been no changes to our critical accounting policies since our 2006 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2006 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

PINNACLE WEST CONSOLIDATED — FACTORS AFFECTING
OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

GeneralElectric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. For the years 2004 through 2006, retail electric revenues comprised approximately 82% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer mix, customer growth, average usage per customer, electricity rates and tariffs, variations in weather from period to period, and amortization of PSA deferrals. Competitive retail sales of energy and energy-related products and services are made by APSES in certain western states that have opened to competition. 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 demand and prices. Competitive wholesale transactions are made by the marketing and trading group through structured trading opportunities involving matched sales and purchases of commodities.

Retail Rate ProceedingsThe ACC regulates APS’ retail electric rates. Our profitability is affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ capital expenditure requirements, which are discussed above under “Liquidity and Capital Resources,” are substantial because of the significant customer growth in APS’ service territory, highlighting APS’ need for the timely recovery of these and other expenditures through rates. As discussed in greater detail in Note 5, on June 28, 2007, the ACC issued an order in a general rate case that APS filed in late 2005. Additionally, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde outage costs. Virtually all of the deferrals related to these 2006 outage costs were associated with a Unit 1 vibration issue. On October 4, 2007, the ACC staff filed a report with the ACC that concludes that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that these

costs were prudently incurred and that the 2006 Deferrals, totaling approximately $79 million, are, therefore, recoverable.

Fuel and Purchased Power CostsFuel and purchased power costs included on our income statements are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the amortization thereof. See “PSA Modifications” and “PSA Deferrals Related to Palo Verde Outages” in Note 5 for information regarding the PSA, including the 2006 Deferrals. APS’ recovery of PSA deferrals from its ratepayers is subject to annual PSA adjustments and, if necessary, periodic surcharge applications.

Customer and Sales GrowthThe customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory for the nine-month period ended September 30, 2007 was 3.5% compared with the prior-year period. Customer growth averaged 4.1% a year for the three years 2004 through 2006, and we currently expect customer growth to average about 3.0% per year from 2007 to 2009. For the three years 2004 through 2006, APS’ actual retail electricity sales in kilowatt-hours grew at an average rate of 4.2%; adjusted to exclude effects of weather variations, such retail sales growth averaged 4.6% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 2.8% on average, during 2007 through 2009, before excluding the effects of weather variations. We currently expect our retail sales growth in 2007 to be below average because of potential effects on customer growth and usage from the slowdown in the residential housing market and retail rate increases (see Note 5).

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

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

Wholesale MarketOur marketing and trading activities focus primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. Our marketing and trading activities include, subject to specified parameters, marketing, hedging and trading in electricity, fuels and emission allowances and credits. See “FERC Rate Case” in Note 5 for information regarding APS’ recent filing with the FERC requesting an increase in transmission rates.

Other Factors Affecting Financial Results

Operations and Maintenance ExpensesOperations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher-trending pension and other postretirement benefit costs and other factors.

Depreciation and Amortization ExpensesDepreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction, changes in depreciation and amortization rates, and changes in regulatory asset amortization.

Property TaxesTaxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessed valuation ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.9% of assessed value for 2006 and 9.2% for 2005. We expect property taxes to increase as new power plants and additions to our transmission and distribution facilities are included in the property tax base.

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

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

SubsidiariesSunCor’s net income was $61 million in 2006, $56 million in 2005, and $45 million in 2004. See Note 17 for further discussion. We currently expect SunCor’s net income in 2007 to be approximately $20 million. This estimate reflects the continued slowdown in the western United States real estate markets, as well as deteriorating credit markets in the second half of 2007.

APSES’ and El Dorado’s historical results are not indicative of future performance.

GeneralOur financial results may be affected by a number of broad factors. See “Forward-Looking Statements” below for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.

Market Risks

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

Interest Rate and Equity Risk

We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund. 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, natural gas and emissions allowances. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the

results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories:

	•		Regulated Electricity — non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and

	•		Marketing and Trading — non-trading and trading derivative instruments of our competitive business activities.

The following tables show the pretax changes in mark-to-market value of our non-trading and trading derivative positions for the nine months ended September 30, 2007 and 2006 (dollars in millions):


	Nine Months Ended						Nine Months Ended
	September 30, 2007						September 30, 2006
	Regulated			Marketing			Regulated			Marketing
	Electricity			and Trading			Electricity			and Trading
Mark-to-market of net positions at beginning of period	$	(62	)	$	77		$	335		$	181
Recognized in earnings:
Change in mark-to-market gains (losses) for future period deliveries		1			(8	)		(9	)		(3	)
Mark-to-market gains realized including ineffectiveness during the period		(1	)		(12	)		(3	)		(2	)
Decrease (increase) in regulatory asset		28			—			(76	)		—
Recognized in OCI:
Change in mark-to-market for future period deliveries — losses (a)		(11	)		(4	)		(277	)		(66	)
Mark-to-market (gains) losses realized during the period		18			(19	)		1			(17	)
Change in valuation techniques		—			—			—			—

Mark-to-market of net positions at end of period	$	(27	)	$	34		$	(29	)	$	93


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

The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at September 30, 2007 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2006 Form 10-K for more discussion of our valuation methods.

Regulated Electricity


													Years		Total fair
Source of Fair Value	2007			2008			2009			2010			thereafter		value
Prices actively quoted	$	(13	)	$	(12	)	$	2		$	3		$	—	$	(20	)
Prices provided by other external sources		—			(8	)		(4	)		(3	)		—		(15	)
Prices based on models and other valuation methods		—			(2	)		(3	)		(2	)		15		8

Total by maturity	$	(13	)	$	(22	)	$	(5	)	$	(2	)	$	15	$	(27	)

Marketing and Trading


											Years		Total fair
Source of Fair Value	2007		2008		2009		2010		2011		thereafter		value
Prices actively quoted	$	9	$	—	$	—	$	—	$	—	$	—	$	9
Prices provided by other external sources		—		20		—		—		3		2		25
Prices based on models and other valuation methods		—		—		—		—		—		—		—

Total by maturity	$	9	$	20	$	—	$	—	$	3	$	2	$	34

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at September 30, 2007 and December 31, 2006 (dollars in millions):


	September 30, 2007					December 31, 2006
	Gain (Loss)					Gain (Loss)
Mark-to-market changes reported in:	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%

Earnings
Electricity	$	4	$	(4	)	$	—	$	—
Natural gas		3		(3	)		—		—
Regulatory asset (liability) or OCI (a)(b)
Electricity		44		(44	)		38		(38	)
Natural gas		76		(76	)		80		(80	)

Total	$	127	$	(127	)	$	118	$	(118	)

	(a)		To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

	(b)		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.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 1, “Derivative Accounting” in Item 8 of our 2006 Form 10-K for a discussion of our credit valuation adjustment policy. See Note 10 for further discussion of credit risk.

ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS

Regulatory Matters

See “Pinnacle West Consolidated – Results of Operations — Regulatory Matters” above for information about the ACC’s order in APS’ general retail rate case and the PSA.

Operating Results – Three-month period ended September 30, 2007 compared with three-month period ended September 30, 2006

APS’ net income for the three months ended September 30, 2007 was $204 million compared with $168 million for the comparable prior-year period. The $36 million increase was primarily due to the effects of hotter weather on retail sales; higher retail sales primarily due to customer growth and usage patterns; impacts of the retail rate increase (see Note 5); and income tax benefits related to prior years resolved in 2007. These positive factors were partially offset by higher operations and maintenance expense primarily for customer service and regulatory programs and increased costs for generation, including the Palo Verde performance improvement plan. In addition, higher fuel and purchased power costs related to commodity price increases were offset by the deferral of such costs in accordance with the PSA. See Note 5 for further discussion.


	Increase (Decrease)
	Pretax			After Tax
Effects of hotter weather on retail sales	$	27		$	16
Higher retail sales primarily due to customer growth and usage patterns, excluding weather effects		17			10
Impacts of retail rate increase (see Note 5):
Revenue increase related to higher Base Fuel Rate		114			70
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(103	)		(63	)
Non-fuel rate increase		5			3
Net changes in fuel and purchased power costs related to prices:
Higher fuel and purchased power costs due to increased prices		(39	)		(24	)
Increased deferred fuel and purchased power costs related to increased prices		37			23
Operations and maintenance increases primarily due to:
Customer service costs and regulatory programs		(10	)		(6	)
Increased generation costs, including Palo Verde performance improvement plan		(6	)		(4	)
Income tax benefits related to prior years resolved in 2007		—			10
Other miscellaneous items, net		(1	)		1

Increase in net income	$	41		$	36

Regulated Electricity Revenues

Regulated electricity revenues were $157 million higher for the three months ended September 30, 2007 compared with the prior-year period primarily because of:

	•		a $119 million increase in retail revenues due to retail rate increase effective July 1, 2007;

	•		a $36 million increase in retail revenues due to the effects of hotter weather;

	•		a $22 million increase in retail revenues primarily related to customer growth and usage patterns, excluding weather effects;

	•		a $16 million increase in Off-System Sales due to higher prices and volumes;

	•		a $44 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 5); and

	•		an $8 million net increase due to miscellaneous factors.

Operating Results – Nine-month period ended September 30, 2007 compared with nine-month period ended September 30, 2006

APS’ net income for the nine months ended September 30, 2007 was $284 million compared with $257 million for the comparable prior-year period. The $27 million increase was primarily due to higher retail sales primarily due to customer growth and usage patterns; the effects of weather on retail sales; impacts of the retail rate increase; and income tax benefits related to prior years resolved in 2007. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs, including the Palo Verde performance improvement plan and customer service and regulatory programs; income tax credits related to prior years resolved in 2006; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior-year period and lower interest income as a result of lower investment balances; and a regulatory disallowance. In addition, higher fuel and purchased power costs related to commodity price increases were partially offset by the deferral of such costs in accordance with the PSA. See Note 5 for further discussion.


	Increase (Decrease)
	Pretax			After Tax
Higher retail sales primarily due to customer growth and usage patterns, excluding weather effects	$	37		$	23
Effects of weather on retail sales		33			20
Impacts of retail rate increase (see Note 5):
Revenue increase related to higher Base Fuel Rate		114			70
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(103	)		(63	)
Non-fuel rate increase		5			3
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs due to increased prices		(80	)		(49	)
Increased deferred fuel and purchased power costs related to increased prices		75			46
Regulatory disallowance (see “Regulatory Matters” above)		(14	)		(8	)
Operations and maintenance increases primarily due to:
Increased generation costs, including the Palo Verde performance improvement plan		(8	)		(5	)
Customer service costs and regulatory programs		(7	)		(4	)
Higher depreciation and amortization primarily due to increased plant balances		(8	)		(5	)
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in the prior-year period		(10	)		(6	)
Income tax benefits related to prior years resolved in 2007		—			11
Income tax credits related to prior years resolved in 2006		—			(7	)
Other miscellaneous items, net		2			1

Increase in net income	$	36		$	27

Regulated Electricity Revenues

Regulated electricity revenues were $225 million higher for the nine months ended September 30, 2007 compared with the prior-year period primarily because of:

	•		a $119 million increase in retail revenues due to retail rate increase effective July 1, 2007;

	•		a $49 million increase in retail revenues primarily related to customer growth and usage patterns, excluding weather effects;

	•		a $45 million increase in retail revenues due to the effects of weather; and

	•		a $12 million net increase due to miscellaneous factors.

LIQUIDITY AND CAPITAL RESOURCES – Arizona Public Service Company

Operating Cash Flows

Net cash provided by operating activities was $561 million for the nine months ended September 30, 2007, compared to $286 million for the same period in 2006, an increase in cash provided of $276 million. This change was primarily due to the 2006 return of cash collateral and margin cash held as a result of changes in commodity prices.

Investing Cash Flows

Net cash used for investing activities was $667 million for the nine months ended September 30, 2007, compared to $694 million for the same period in 2006, a decrease in cash used of $27 million. This change was primarily due to:

	•		An approximate $236 million decrease in APS’ invested position. In 2006, we issued long-term debt and invested some of the proceeds in short-term investment securities until they were later redeemed and the cash used for general corporate purposes; partially offset by

	•		An approximate $201 million increase in capital expenditures. See “capital expenditures” chart, Liquidity and Capital Resources — Pinnacle West Consolidated.

Financing Cash Flows and Liquidity

Net cash provided by financing activities was $61 million for the nine months ended September 30, 2007, compared to $476 million for the same period in 2006, a decrease in cash provided of $415 million. This change was primarily due to:

	•		An approximate $394 million decrease due to the issuance of approximately $393 million of new long-term debt, net of redemptions, in order to fund our construction program and for other general corporate purposes. During the first nine months of 2007, APS has not issued any new long-term debt.

	•		An approximate $170 million decrease due to decreased equity infusions from Pinnacle West; and

	•		An approximate $150 million increase in short-term borrowings to fund day-to-day operations and liquidity needs.

For additional discussion see “LIQUIDITY AND CAPITAL RESOURCES – Pinnacle West Consolidated.”

Contractual Obligations

APS’ future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2006 Form 10-K, with the exception of our aggregate fuel and purchased power commitments, which increased from approximately $2.5 billion at December 31, 2006 to $3.4 billion at September 30, 2007 as follows (dollars in billions):


2007	2008-2009		2010-2011		Thereafter		Total
$0.4	$	0.7	$	0.5	$	1.8	$	3.4

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

Given our adoption of FIN 48, APS is now required to include uncertain tax positions in the contractual obligations disclosure. As of September 30, 2007, APS has uncertain tax positions of approximately $204 million and expects a majority of these positions will be settled within the next twelve months. See Note 8 for additional information.

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the 2006 Form 10-K, these factors include, but are not limited to:

	•		state and federal regulatory and legislative decisions and actions, particularly those affecting our rates and our recovery of fuel and purchased power costs;

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

	•		the outcome of regulatory, legislative and judicial proceedings, both current and future, relating to the restructuring and environmental matters (including those relating to climate change);

	•		market prices for electricity and natural gas;

	•		power plant performance and outages;

	•		transmission outages and constraints;

	•		weather variations affecting local and regional customer energy usage;

	•		customer growth and energy usage;

	•		regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile fuel and purchased power costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;

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

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

	•		our ability to compete successfully outside traditional regulated markets (including the wholesale market);

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

	•		changes in accounting principles generally accepted in the United States of America and the interpretation of those principles;

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

	•		technological developments in the electric industry;

	•		the strength of the real estate market in SunCor’s market areas, which include Arizona, Idaho, New Mexico and Utah; and

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.

Item 4. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (15 U.S.C. 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, 2007. 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, 2007. 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, 2007 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See Note 12 in regard to pending or threatened litigation or other disputes. See also “Federal Implementation Plan – Four Corners FIP” under Item 5 below.

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 2006 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of APS and Pinnacle West. The risks described in the 2006 Form 10-K are not the only risks facing APS and Pinnacle West. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of APS and Pinnacle West.

Item 5. OTHER INFORMATION

Construction and Financing Programs

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

Regulatory Matters

See Note 5 for a discussion of regulatory developments.

Environmental Matters

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

Regional Haze Rules

On April 22, 1999, the EPA announced final regional haze rules. These regulations require states to submit state implementation plans (SIPs) by December 2007 to demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class I Areas,” including several on the Colorado Plateau. The SIP is required to consider and potentially apply “best available retrofit technology” (BART) for certain older major stationary sources. The rules allow nine western states and Indian tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.

On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional haze rules by providing guidelines, known as the BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use. The EPA also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court remand of that rule.

ADEQ is currently undertaking a rulemaking process to amend its SIP to reconcile it with the Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. ADEQ’s Regional Haze SIPs are due to EPA Region 9 in December 2007. As part of the rulemaking process, ADEQ will

require certain sources in the state to conduct BART analyses. Cholla and West Phoenix received letters from ADEQ asserting that the plants are potentially subject to BART and requesting that we either perform a BART analysis on each plant or provide information demonstrating that we are not subject to BART. We are currently performing a BART analysis for Cholla and expect to complete and submit it to ADEQ by the end of December 2007. Because we believe that ADEQ made several errors in its baseline modeling for West Phoenix, we re-performed the baseline modeling using correct input and have determined that West Phoenix is not subject to BART. We submitted these findings for West Phoenix to ADEQ and are awaiting its response. In addition, EPA Region 9 has requested us to perform a BART analysis for Four Corners. We are performing that analysis and expect to submit it to the EPA by the end of November 2007.

Once the analyses and BART recommendations for Cholla and Four Corners are submitted to ADEQ and the EPA respectively, the agencies will review the submissions and determine what, if anything, constitutes BART for the plants and will incorporate those determinations into implementation plans for the plants. We expect to receive the agencies’ final determinations in 2008. Implementation of any such recommendations would likely occur over a five-year period. While we continue to monitor this matter, at the present time we cannot predict the outcome of our BART analyses, the nature of the BART controls, if any, the agencies may mandate, or the resulting financial or operational impact.

Federal Implementation Plan (“FIP”)

In September 1999, the EPA proposed FIPs to set air quality standards at certain power plants, including Four Corners and the Navajo Generating Station. On September 12, 2006, the EPA proposed revised FIPs to establish air quality standards at both of these plants.

Four Corners FIP

On April 30, 2007, the EPA adopted a source specific FIP to set air quality standards at Four Corners. See “Environmental Regulation – Federal Implementation Plan” in Part 1, Item 1 of the 2006 Form 10-K for additional information regarding the procedural and litigation issues leading to the EPA’s adoption of the FIP. The FIP essentially federalizes the requirements contained in the New Mexico State Implementation Plan, which Four Corners has historically followed. The FIP also includes a requirement to maintain and enhance dust suppression methods. On July 2, 2007, APS filed a petition for review in the United States District Court of Appeals for the Tenth Circuit seeking revisions to the FIP to clarify certain requirements and allow operational flexibility. The Sierra Club has intervened in this action. On July 6, 2007, the Sierra Club and other parties filed a petition for review with the same court challenging the FIP’s compliance with the Clean Air Act and we have intervened in their action. Although we cannot predict the outcome of these matters, we do not believe that they will have a material adverse impact on our financial position, results of operations or cash flows.

Navajo Generating Station FIP

The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently predict the effect of this proposed FIP on the Company’s financial position, results of operations or cash flows, or whether the proposed FIP will be adopted in its current form.

Climate Change Initiative

On February 26, 2007, five western states (Arizona, California, New Mexico, Oregon and Washington) entered into an accord, called the Western Regional Climate Action Initiative, later

renamed the Western Climate Initiative (the “Initiative”), to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. Since then, Utah, British Columbia and Manitoba have joined the Initiative. In August 2007, the Initiative participants set a goal of reducing greenhouse gas emissions 15% below 2005 levels by 2020. By August 2008, the Initiative participants intend to develop a plan for implementation of this goal. Any such implementation would require independent action by each individual state’s (or province’s) legislature or Governor to adopt a version of the plan. The Company is currently developing a climate change management plan to address these and related issues. While we continue to monitor the impact of the Initiative, at the present time we cannot predict what form it will ultimately take, whether it will be implemented or, if it is implemented, what impact it will have on our operations.

Item 6. EXHIBITS

(a) Exhibits


*Exhibit No.*	*Registrant(s)*	*Description*

10.1^a	Pinnacle West	Description of Annual Stock Grants to Non-Employee Directors

10.2^a	Pinnacle West	Description of Stock Grant to W. Douglas Parker

10.3^a	Pinnacle West APS	Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries

10.4^ab	Pinnacle West APS	Form of Amended and Restated Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries

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 William J. Post, 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 Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended


^a		Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 6 of Form 10-Q.

^b		The Company has entered into identical Amended and Restated Key Executive Employment and Severance Agreements (“KEESAs”) with each of its executive officers.


*Exhibit No.*	*Registrant(s)*	*Description*

31.3	APS	Certificate of Jack E. Davis, 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 Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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


*Exhibit*				*Date*
*No.*	*Registrant(s)*	*Description*	*Previously Filed as Exhibit¹*	*Filed*
3.1	Pinnacle West	Articles of Incorporation, restated as of May 23, 2007	4.1 to Pinnacle West/APS May 23, 2007 Form 8-K Report, File Nos. 1-8962 and 1-4473	5-25-07

3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of May 23, 2007	4.2 to Pinnacle West/APS May 23, 2007 Form 8-K Report, File Nos. 1-8962 and 1-4473	5-25-07

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 June 23, 2004	3.1 to APS’ June 30, 2004 Form 10-Q Report, File No. 1-4473	8-9-04


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.

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: November 5, 2007	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		Executive Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)

	ARIZONA PUBLIC SERVICE COMPANY (Registrant)
Dated: November 5, 2007	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)

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Arizona Public Service 10-Q2007 Q3 Quarterly report

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